Polaris Infrastructure Inc

TSX:PIF

Earnings Call Transcript 2022-Q3

[Operator]

Good morning, ladies and gentlemen, and welcome to the Polaris renewable Energy Inc.'s Third Quarter 2022 Earnings Conference Call. [Operator Instructions] It is now my pleasure to turn the floor over to your host, Anton Jelic, Sir, the floor is yours.

[Anton Jelic, executive]

Thanks, John. Good morning, everyone, and welcome once again to our Q3, '22 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 U.S. dollars.

I'd like to remind you that the 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 with Marc Murnaghan, CEO of Polaris Renewable Energy.

At this time, I'll walk through our financial highlights. Power generation. During the 3 months ended September 30, '22, 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 projects in the Dominican Republic acquired on June 28 and the hydroelectric project in Ecuador acquired on September 7.

During the 9 months ended September 30, power production was 475,536 megawatt hours net compared to 480,981 megawatts net in the 9 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 9 months period ended September 30.

Revenue. Total revenue was $14.5 million during the 3 months ended September 30 compared to $14.8 million in the same period last year. Total revenue of $45.8 million for the 9 months ended September 30 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 3 months ended September 30 compared to earnings of $2.2 million for the same period in 2021. Further, the net loss attributable to owners for the 9 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 3 months ended September 30 compared to $10.9 million last year. As well, adjusted EBITDA was $33 million for the 9 months ended September 30 compared to $32.7 million for the same period in 2021.

Cash generation. Net cash from operating activities for the 9 months ended September 30 of $20.7 million than the $33.9 million in the same period last year, mainly because in the 2021 period, San Jacinto collected approximately $8 million overdue receivable balance after the sign off of the new PPA agreement.

Net cash used in investing activities for the 9 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 to the acquisition of Emerald in Dominican Republic and $15.2 million cash due to the acquisition of HSJM in Ecuador, net of the total cash received $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 the solar projects in Panama. Net cash used in financing activities for the 9 months ended September 30 of $24.4 million compared to net cash provided by financing activities of $14.5 million for 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.

And 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 will elaborate on current business matters as well as on our quarter end results. Thank you.

[Marc Murnaghan, executive]

Thanks, Anton. So first starting with the quarter.

This third quarter was always anticipated in terms of the EBITDA and production to be lower, 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, onetime items. But 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, and we came in at about 45 megawatts, which I will -- we did talk about that a little bit in the press release due to just 2 wells took a bit long to recover. That was about $500,000.

And then actually, the bigger one was on the G&A line, some deal costs from the acquisitions, et cetera, in terms of the finder's fee and legal fees of about $600,000. So you're looking at about $1.6 million in costs, I would say, either costs incurred lower revenue in the quarter in terms of the net impact on EBITDA, but I wouldn't consider going forward and definitely not what we're running in our numbers going forward.

We'll give you an example. San Jacinto 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, 8 de Agosto in October, did as much production as the whole Q3. So it would -- the call it the rainy season has started in normal fashion, and that's actually more important than, call it, having a dry, dry season in terms of numbers to us. So we're happy with that.

A few other things about the quarter, call it Dominican was, I would say, as expected, and that did have a full quarter contribution. EBITDA around 1.4 to 1.5. San Jose de Minas was only about a month so that didn't really contribute anything there, but it is running as expected. And then we did have a small carbon credit sale that brought in about $427,000 in revenue, and that was actually for 2015 vintages. And I'll talk a little bit about that later, but we saw that in the price of -- those at a price of $2.30. So that did come in, in the quarter.

But I think in terms of once San Jose de Minas current quarter, it's going to be a full quarter, obviously, the 8 de Agosto quarter so 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, and I would have that in call it a $12.5 million range ballpark for current quarter EBITDA.

And then -- but that does not include the Binary unit, nor Panama Solar in Panama. So in terms of those projects, the Binary unit, we are still looking at a COD in December, the commissioning date in December. And we had spent up to $23 million at September 30. There's another $2 million. So we are expected to come in on budget for that and starting in December. So Q1 should be a full quarter with the Binary unit.

The Panama Solar and that's the big one of the development projects, the solar in Panama is moving as expected and as budgeted as well. And we're looking at end of December, potentially early January, but -- for commissioning. So maybe a little bit of slippage, but not much there and on budget which is great.

So those will come in. So 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 the Panama Solar, 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, we were -- Canoa 2 would be the most important one. That's the expansion at the site. So we did -- 2, 3 weeks ago, we did 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. So we couldn't get into the pricing and terms with the offtaker until this was granted by the authority, which has been granted. So we're now actually exchanging documentation in terms of the contract. And so we hope that to move pretty quickly.

And we will -- given that we're going to be starting, what I call the very sort of early-stage small dollar side trap designs, et cetera. So that is going to start moving very quickly now, which is great. That would be, call it, our first expansion project on the backs of the acquisitions that we announced earlier.

The other one that we're going to be starting construction on either this month or the first thing in December is the -- it's a small expansion, brownfield expansion project at the San Jose de Minas site in Ecuador, which is about a $3 million project. So we think it should increase production by about 20% to 30% annually, very good payback project, and that should be started and we're looking at about a 9-month construction there.

And then the other that we have yet to, I would say, fully defined, but we'll have a guide by end of December in terms of what the plan is, so certain acid jobs on wells in San Jacinto. We've been assessing this with a technical consultant for the greater part of the year. And we think that we have some real interesting opportunities here. Principal one being one of the wells or 2 where we had to use a lot of mudding, drilling because it was -- we've got a lot of steam kick during the drilling. We're getting estimates of anywhere from 3 to 10 megawatts of potential there, and this is something that should cost us at about $750,000 to do.

So that is something that we will hope to have. The only thing that's left is really the -- what is the exact way of doing it. And there's a few options, but we should have that nailed down and can communicate to it. I think this is important because as we -- we don't see any large program drilling at the field for years now, but we do see, what I'd call, more typical maintenance/optimization, and this will probably be the first one that we will execute to kind of validate the thought that would -- call it a maintenance CapEx of 1 to 2 a year. We can sort of change the either sustain to 0% decline and potentially even improve the production from where we're at today, which should be very economic for us.

Last thing I'll mention is the carbon credits. We did get -- 8 de Agosto a month ago was finally fully verified, so that's great. So we now have what I call relatively recent credits that we can sell there. And we are in the process on 3 other ones, which would include Panama Solar, actually El Carmen in Peru and the Binary unit is actually being done separately. So those should all be done. We spent a lot of time on that, those will be done this year.

We should be entering, call it, next year with around 350,000 tons annually in terms of annual production. And 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 -- despite the war, despite inflation, I do -- I would have expected maybe more of a pressure on those prices, but we're not seeing that. We are seeing transactions getting done. So I would expect -- at this point, I don't see us doing anything in Q4. But given that 8 de Agosto is done, and we have actually at San Jacinto alone from 2017 and '18, about $300,000 just sitting there in inventory.

So I think the policy for us will be just to keep working on things that are 4 or 5 years dated. As I said, we sold 2015s. Things closer to today, I think we can get $4 to $5. So 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 in reduced small bits of it. So I would think that next year, in terms of, as I said, the numbers that I quoted, I don't put the carb credits in, but I would expect it to be represent a larger number in terms of our total revenue next year than it is this year.

So that's it for my comments, so we can open up for questions now.

[Operator]

[Operator Instructions] The first question is coming from Nick Boychuk with Cormark Securities.

[Nicholas Boychuk, analyst]

Just on Nicaragua first. Can you please clarify the 3 to 10 megawatts that you're looking at getting out of that additional well that's totally new capacity that we'd be adding right?

[Marc Murnaghan, executive]

Yes, yes. So that is a well that when you drill we had a steam kick, which means steam comes -- the only way -- before you have cased your well. And so you have to basically kill it, which will be the only way to do that is you dump a lot of mud. 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.

And so basically, there's a lot of mud in the formation, right? And so this well unfortunately only produces about 1 to 2 megawatts, despite how strong these kicks were. So all the data suggests that there's for sure production there. The question is 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.

So our estimates, as I said, are anywhere from 1 to even higher than 10 megawatts. So that was part of the 2017, '18 drilling campaign. And right now, this is a tiny producer, but our average well in the field is about 5, 6 megawatts now. So if you assume the average, then we get like an extra 4, I'd say. And then 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.

[Nicholas Boychuk, analyst]

Okay. So budget by end of the year and then roughly in terms of construction time line, how long you think that would take?

[Marc Murnaghan, executive]

Well, it's -- we would do it likely midyear, but it's one month process.

[Nicholas Boychuk, analyst]

Okay. So looking into Panama, could we get a little bit of extra color on Panama Solar 3? What are you seeing in terms of the development process, cost development and also power price market where merchant rates in Panama is currently and how you're thinking about PPAs versus going full spot on those 2 assets?

[Marc Murnaghan, executive]

So in terms of the current build, we're still -- are you talking the current one that we're building or even further?

[Nicholas Boychuk, analyst]

I'm thinking more Panama Solar 3.

[Marc Murnaghan, executive]

Yes, just so predominantly, probably my bad, but it's technically 2 projects that we're building just because they have 2 different generating licenses, but we're doing 2 and 3 now, and we're looking at doing a few more later next year. But I would -- just let me comment first on the spot market. The trailing 12 months is around $100 a megawatt hour there. We definitely have interest in contracting, although given that sort of the first projects that we're building right now that are going to come on, call it, Jan 1 would only represent 2% to 3% of our total production.

Everything else is 100% contracted. So 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, but I think we'll just start the year in call it merchant there, and I run my numbers at about $85 a megawatt hour.

Yes, it's at about $100 right now. The LTM is at about $100. In terms of the cost to get there, I think our all-in will be about $9 million for 12.5 megawatt DC, 10-megawatt DC, which is, I think, very good. And we executed this project with our own sort of project management team. And I think that is something we would look at going forward. It was the same with the Binary and it will likely be the same with the Canoa 2. So as opposed to hiring an EPC contractor, because we see about $0.10 to $0.15 per watt difference in doing that. And so 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 too.

[Nicholas Boychuk, analyst]

Okay. That's helpful. And then in Ecuador, were you guys were able to submit the bids for 7, 20 and 27 megawatts projects in the October 31st auction?

[Marc Murnaghan, executive]

November 18 is the big day, but we are evaluating -- we are reevaluating because they did publish some prices for -- max prices and hydro was $52, which is -- it would may be possible to get our returns. I think very few people are going to bid and immediately after that there was a change in the Minister of Energy for the ministry. So I think they're going to have to redo the whole thing quite frankly and we're going to come back in Q1 and they've already talked about it too.

So I think we would be very shocked that people show up at that price and/or they basically redo the whole thing in Q1, it is back on track. So yes, I don't -- our plan is really going to be to do the expansion. We can go ahead with everything that's needed, but in terms of the bidding process, it's likely going to be more of a Q1 thing now.

[Operator]

Next, we have David Quezada with Raymond James.

[David Quezada, analyst]

Maybe my first one here, just maybe a longer-term question, just thinking about growth opportunities across your footprint. Obviously, you've got a lot of stuff going right now. But just curious about what kind of potential you see for storage across your footprint and what kind of time line would you look at there, I suspect a few years out? And what would you need to see in terms of contractual underpinning for something like that?

[Marc Murnaghan, executive]

So yes, in terms of a few years -- I would hope that actually contractually it is sooner than that in terms of having something nailed down for storage. We are actually are 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 is going to be like a 1-megawatt hour lithium project. And again, I think, it will be very good knowledge for us. It is a little baby step to do it, which actually is the second one. We have the solar plus battery project in Nicaragua right now at a very small scale and we're going to just run it through.

And then I think the next one will be the Dominican. We've already had conversations with them what they -- so all this was we really wanted to get those definitive concession for Canoa done and then which we have. And now we're going to go move ahead with that project. On the back of that, though, what we need to do is just change our concession, which right now it is technology specific, which is solar. So technically, we need an amendment. And it's not actually hard, it is just taking -- instead of saying solar, it's solar and batteries.

And we can now start that process, because -- and we are going to start it. The nice thing with the Dominican is that they've already published reference prices for solar projects that add storage, and it's an increase. And it's a material increase and they're not definitive. They use the term referential for a reason, because they're trying to guide people. I would say that, that the guiding that they're doing is close to making a lot of economic sense. It's not quite there, but they've already had a task force that's working on it.

So I would hope we can have that kind of amendment in the first half of next year to say that we can do it. And then it would get into negotiating that price and the size. So how big do you need to start? Can you go sort of small, medium or do they want you to go big? That will be a bit of a negotiation, but I think it will 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 or 100-megawatt hours of storage on the backs of Canoa 1 and Canoa 2, and we have the land for it.

So that's where hope that we would start and maybe do a decrease in terms of actual production. But in terms of project definition, contracting, I would hope it is much sooner than that. And then with that, I think the messaging will be that is going to be a really big focus for the company going forward and that's our, call it, a key growth engine for the company is going to be in storage, absolutely.

[David Quezada, analyst]

Okay. That's awesome. That's great color. 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 looking to procure panels. I think in the past, you suggested that the size of the projects you're looking at, it's not too much of an issue. Just curious what you're seeing there and if you see that as a hurdle in any way?

[Marc Murnaghan, executive]

Yes. We just -- interesting, we recently got indicative quotes on panels and inverters and they both were lower than the project in Panama was done at. So that's -- obviously that's good. I think we're seeing more is it tends to be more certain parts of the 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 do -- parts flow through China, and they are still having issues.

So I would see it more as timing though, necessarily than budget at this point. That's what we're saying. So it can cause delays, which you've got that's where you need to for more so than it is on call it cost increase, and I would reiterate that we don't -- 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.

[Operator]

[Operator Instructions] Up next we have Naji Baydoun with iA Capital Markets.

[Naji Baydoun, analyst]

Just wanted to go back to the Panama solar projects. So if I understood correctly, you're comfortable operating the projects that are going to be completed soon on a merchant basis for now? And then maybe you think about contracting for the next ones? Like there's no rush essentially to get PPAs in the door to be able to raise that financing, you're okay with the way things are for now.

[Marc Murnaghan, executive]

With the current one, absolutely, yes.

[Naji Baydoun, analyst]

And what about let's say the next tranche of projects in Panama?

[Marc Murnaghan, executive]

Yes. So it really -- it depends on which type we are doing. We have a couple on the solar side of the same developer that would be -- we think we'll be ready back half of next year as well as the hydro project that we have been working on for quite some time. And we signed the deal several years ago, it's still in our queue. It actually has contracts. So if we were to move ahead with that and our go and no go in that is in the next 3 months.

As the same company, we could use those contracts. The amount of contract was higher than what the first solar plant would produce and it would actually be a good percentage of next ones. So 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 probably 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 want to raise some debt locally in the market in Panama, because it's a very -- it's actually a great market from that perspective. So maybe we can try to get a 40% to 50% contracted as a package when you include the new ones and the current one.

[Naji Baydoun, analyst]

Right. Okay. That makes sense. So I was just thinking about actually you didn't put any equity on those projects, but it's -- I guess, we'll hear more about your spend in about in a few months.

[Marc Murnaghan, executive]

I think we would in the sense that let's just say how we did with the solar. And let's just say each one is $10 million, and we've already spent $10 million. We can probably do the next 2 on using local debt, but not if it was -- if the whole package was 100% merchant. You probably need to get 40%, 50% contracted. And then you could. And then we -- our equity quote has already been spent and invested.

[Naji Baydoun, analyst]

Okay. Okay. That's good. And just on Canoa 2, is that maybe you can just give us an update on the time lines and sort of milestones to get that project moving for next year?

[Marc Murnaghan, executive]

Yes. So I think -- as we said, we're now into negotiation PPA. We're going to start doing certain land prep immediately. I think it will take us to being truly like large, the full construction start probably not till April or May. We will have -- 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 to 2024 like the end of Q1 ready 2024.

[Naji Baydoun, analyst]

Okay. Okay. And I guess an FID soon and then construction, so call it, mid to the back half of next year or 2024.

[Marc Murnaghan, executive]

Yes.

[Naji Baydoun, analyst]

Okay. And just one last question if I may, if we go back to the Ecuador bidding, I mean just based on public -- it seems like it's going to be tougher process with lot of interested parties. I'm just wondering you talked about the pricing on the hydro, which I think is going to be about 150 megawatts. Also looking I think looking at other ones in solar and RFP, is there any more you can say about that? Is that something that you're interested in? And let's say they come out with the award in Q1 next year, what would be kind of the time line to build those projects?

[Marc Murnaghan, executive]

So just -- 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. So I think partly because I think there is a little bit more competition. I don't think I'd say medium competitive on those where it's low commit on the hydros. So I think for us, one scenario if the hydros don't happen, there's going to be people that get some solar and winds and that don't have the equity capital to go ahead. We absolutely look to work on that. Because that whole call it dynamic of still capital constrained, small project developers, I mean that does not exist and still it's gotten a lot worse.

So I think it is better for us. I think we would play more of a wait and see on those. And I'm sure we would get a call on the solar and the wind. And then in terms of the hydro, yes, I don't think -- what I think would happen on a call it project win Q1, let's say, assuming that happens, the original thinking actually would have been that a hydro project comes online call it for 2025. So if you had sort of Canoa 2 plus the Solar Panama and maybe the hydro coming on in 2024, the hydro in 2025, I don't think that's changed, but it's probably could push back 3 to 6 months to mid-2025.

[Naji Baydoun, analyst]

It's very helpful. And that will definitely sort of be continuation of a steady pace of growth. Okay. So focus on hydro and maybe keeping some options open to partner with someone else in the solar.

[Operator]

Next, we have [ Viveck Punjabi ] with National Bank Financial.

[Unknown Analyst]

This is Viveck from National Bank on behalf of [ Rupert ]. I just want to circle back on carbon credits. I know you've provided some commentary on that. But just to understand, how should we think about carbon credit sales and leading into the next year? Should we see it at 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 comment.

[Marc Murnaghan, executive]

So where I think we're going to go. So it was -- would have been a year ago or maybe 1.5 years ago, CORSIA, which is -- so the airlines have a buying consortium. It's called CORSIA. And they're one of the -- and there's also an oil and gas one called IETA. They're big buying consortiums, and I think they're in the voluntary market. There would be some of the larger buyers. But 1 year, 1.5 years ago, yes, it was 2021, CORSIA came and said if it's before 2016 vintage we're not really interested. And so that kind of had a bit of a demarcation line in terms of pricing.

So I think any vintages because, again, you don't need to sell these right away, you can inventory them . So that made a bit of a demarcation line. So we've gotten rid of -- now interestingly, we were able to sell some 2015s this quarter or the past quarter at $2.3 whereas, call it, what I call, more recent vintages, so below 5 years seem to be in the $4 and $5 range. So what I think we will do is -- and 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.

But the risk is that they say now we only want things that are not 5 years but 3 years, no more than 3 years dated. And so we still have -- so for instance, at San Jacinto, some remaining inventory just for '17 and '18 alone is like 300,000 tons, okay? So I think what our policy will be, will be to start moving off older inventory to remove that risk, before kind of switches into a lower pricing environment that is being dictated.

So -- and what we're seeing in the market is the $4 or $5 is being achieved with some 2017s and '18s, because it's still within that sort of 5-year thing. So 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 to $5, you can do the math. So $1.5 million. I don't know -- I don't think I can say that's sort of guidance, but that at least the thinking right now.

I think the thinking is that as I said, the fact that it's still at $4, $5 in this environment, to me, suggests that, to the extent we do reach any form of normalization, I think there should be more value in this and even more recent vintages than $4 or $5.

[Unknown Analyst]

Sure. And just to circle back on the Panama Solar that was 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?

[Marc Murnaghan, executive]

There is. The risk is I think it's small. I mean it's a smart transformer from Huawei, which is the last piece of equipment, and it's supposed to be delivered the last week of November and that's the last communication we had. If they -- if that slips, now that just to be clear that already is later than in what we thought. But if that happens, we're still good for what I said. If that's 2 weeks late, it might be 2 weeks late, but that's we're down to kind of 1 key piece of equipment from a much, much larger set. So we think we've wrestled it down to a reasonable low risk. But, yes. So technically speaking, we could get pushed out, and it's coming down to that.

[Operator]

[Operator Instructions] It looks like we have a follow-up from Nick Boychuk with Cormark Securities.

[Nicholas Boychuk, analyst]

Marc, just going back to the 8 de Agosto maintenance. Can you just kind of give us a little bit of color on what work was done at the plant? If this is not the annual moving forward and if other one of your hydro assets improved and require some more work?

[Marc Murnaghan, executive]

Yes. It's not. So 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. The -- I do think that this should go down a lot going forward. These are not big dollar CapEx, it is just its down time and you try to minimize the downtime by doing it in the dry season. I would suggest that out of the, call it, hydrology versus maintenance, it is like 90%, hydrology for the quarter, not the maintenance in terms of the difference in production.

[Nicholas Boychuk, analyst]

Okay. So just 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?

[Marc Murnaghan, executive]

No. I mean no. You just going to have years that are low, you're going to have years that are high. I mean if you look at the 9-months basis, we're actually ahead of where we were last year, right? And so when it's just a quarter, it's just the dry season you are going to have -- when you're dealing with lower numbers, too, but -- so yes, the 9 months numbers aren't that far off. As I said, I think they're a bit better. So -- and we're running right on budget in October. So, no. We don't see any reason to change our numbers.

[Operator]

[Operator Instructions] Okay, it appears there are no further questions in queue.

[Marc Murnaghan, executive]

Okay. Thanks, everyone.

[Anton Jelic, executive]

Thank you.

[Operator]

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.