Polaris Renewable Energy Inc. (PIF) Earnings Call Transcript & Summary

Good morning. My name is Michelle, and I will be your conference operator today. At this time, I would like to welcome everyone to the Polaris Infrastructure Year-end 2019 Earnings Results Conference call. [Operator Instructions] Mr. Jelic, you may begin your conference.

Thank you, Michelle. Good morning, everyone, and welcome to the 2019 year-end earnings call for Polaris Infrastructure. In addition to the press release that was issued earlier this morning, you can find our financial statements, MD&A and annual information form on both SEDAR and shortly on our website at polarisinfrastructure.com. Unless noted otherwise, all dollar amounts referred to are denominated in U.S. dollars. I'd like to remind everyone 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 Infrastructure Inc., and 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 annual information form for the year ended December 31, 2019. I'm also joined this morning, as always, by Marc Murnaghan, Chief Executive Officer of Polaris Infrastructure. At this time, I will walk you through our 2019 year-end financial highlights and comment on our recently paid quarterly dividend, after which I will turn the call over to Marc for additional commentary. Power generation. Consolidated power generation for the 3 months ending December 31, 2019, and '18 was 144,760 megawatt hours and 148,498 megawatt hours, respectively. Consolidated power generation for the 12 months ending December 31, 2019, and '18, was 570,934 megawatt hours, up from 548,510 megawatt hours, again, respectively. These production figures are net of all plant downtime, both planned and unplanned. With respect to Nicaragua, we saw total megawatt hours of 132,182 in the fourth quarter of 2019 versus 143,301 in the 3 months ending December 31, 2018. For the year 2019, total megawatt hours were 532,987 versus 543,313 in 2018. In Peru, total megawatt hours for the 3 months ending December 31, 2019, were 12,579 versus 5,197 in the 3 months ending December 31, 2018. For the year 2019, total megawatt hours in Peru were 37,948 versus 5,197 in 2018. A full year of generating results at our Canchayllo facility coupled with recently operational El Carmen and 8 de Agosto positively impacted our Peruvian power generation totals for 2019. Revenue, we reported revenue of $17.8 million for the 3 months ending December 31, 2019, compared to $18.3 million in the same period last year. For the 12 months ending December 31, 2019, and '18, we generated consolidated revenue of $71.2 million versus $68.8 million, respectively. On a year-over-year consolidated basis, we realized $2.4 million additional revenue, driven by an additional 18.5 megawatts. Net production in Peru coupled with the 3% annual increase in our Nicaragua PPA price, which was partly offset by reduced steam production at San Jacinto. Net earnings. We recognized net earnings of $13.6 million for the 3 months ended December 31, 2019, compared to net earnings of $8.8 million for the same period in 2018. The $4.8 million increase in earnings was driven primarily by the recognition of income tax recovery coupled with a decrease in G&A expenses and partly offset by marginal revenue decreases again at San Jacinto. The year-over-year net earnings were $14.5 million in 2019 versus $17.2 million in 2018, respectively. This $2.7 million decrease in earnings was driven by the impairment loss related to the Casita project, an increase in finance costs, a decrease in other gains, offset by an increase in revenues from our Peruvian operations. Adjusted EBITDA. For the 3 months ended December 31, 2019, adjusted EBITDA totaled $14.3 million compared to $13.3 million for the same period in 2018 as a result of a $1.4 million decrease in G&A costs, partly offset by a $0.5 million decrease in revenue from our San Jacinto facility. For the 12 months ended December 31, 2019, adjusted EBITDA totaled $58.9 million compared to $56.3 million for the same period in 2018. The increase was as a result of increased contribution from San Jacinto as well as contributions from Canchayllo and the 2 facilities, newly opened at Generación Andina, offset by increases in direct costs and G&A expenses, ignoring share-based compensation and acquisition costs. Cash generation. During 2019, we generated $44.6 million in cash flows from operating activities compared to $37.4 million in the 2018 fiscal year, a 19.2 -- a 19.25% increase year-over-year. Dividend. Finally, I'd like to just note that we paid our 16th consecutive quarterly dividend on March 28 of $0.15 per share to shareholders of record on March 20. This continues the Board's -- sorry, that was February 28, $0.15 per share to shareholders of record on February 20. This continues the Board and Management's commitment to regular positive distributions to shareholders at Polaris. With that, I'll turn over the call to Marc, who will elaborate on current business matters as well as our year-end results. Thank you.

Thank you, Anton. Okay. So I'll just go through several points here, then turn over for questions. First, production at San Jacinto. When I look at more than -- I look at a quarter -- 2 quarters as opposed to the 2018 quarter. So we went from 60.2 to 59.9. I'll give you some monthly data. Actually, it was 59.7 in October, 59.94 in November and 59.95 in December. So effectively identical every single month, October, November, December. So it's important to note that in the sense that's very stable. The 12-5 was the big well we put on in 2018 and -- call it, mid of '19 is when we think the field sort of settled into a level here. We did -- in the press release, we commented that we're up marginally, actually, quarter to date. So we're in March now, and were up, call it, 2%, 3% from that. So up a bit, and we think that's just due to some injection system configuration changes to improve things. But I think assuming no drilling campaigns and no big CapEx, I think the field does have enough time after 12-5 and it's kind of settled into a stable range here. Next, I'll comment on the numerical model, which is all part of this, is that we spent a good part of last year working with our technical advisers, Jacobs, and they did something called a numerical model, which is taking all of the known data, breaking down the reservoir into thousands of different components of blocks of rock and you put in temperature, pressure, permeability data. And you then do mass extraction, calculations over not just tending the rest of our contract, but over 20, 30, 40 years to get a sense as to what type of production that the field can sustain. And from that, once you've done all that, you can then start running more scenarios in terms of should you drill more wells, should you do a binary unit and how that -- and then you use it as a tool for the field management. And a lot of companies do these a bit later, sort of after the big, call it, drilling campaigns are sort of over. So we've done that. It's actually -- the report is now on SEDAR, I believe.

[ It will be available shortly ].

So shortly will be. But the net conclusions, at least from that, I think, are very positive is that it predicts sort of a 1% annual decline if we don't do anything. So we generally model 3. So I think that's very good. And then we'll -- as I said, we'll use it to look at other potential scenarios if, as and when we decide to put more capital into San Jacinto in either the medium or longer term. My comments on Peru is that if they don't come through the numbers are just that. So for Q4, it was actually a negative drag on EBITDA because of about 130,000. So not a big negative drag, but the 2 new plants came on late in the quarter, but we've had to staff up even in September. So we even had some costs in September. So we had to have a full complement of staff ready to go. And so the cost of that was borne for the full quarter, but the revenues were quite small. So for instance, I think our costs were around $800,000 for the quarter and only about $400,000 of revenue for the 2 new plants came in, in Q4, and we would expect those costs to be maybe a tiny bit higher, but pretty close to that on a quarterly basis. So we didn't -- we'll see the, call it, the full benefit in Q1 here with the revenue with kind of a flattish cost structure, but we bore all of that in Q4. I'll talk about the dividend payout ratio. So actual in Q4 was low because we didn't have any maintenance CapEx. It was about 32%, but if you put sort of -- it depends on what your assumptions are in terms of what we really want to do with the field. But if you assume some level of annual maintenance and annual sustaining CapEx, you're probably closer to 37%, 38% on a consolidated basis. So I still think that is in the range, could maybe go a little bit higher in the future here, and I'll talk about that in a bit. One other comment I would like to make is that, our overall leverage continues to go down on a consolidated basis. In Nicaragua, now we're down -- if you actually look just at Nicaragua in the back of the corporate head costs, but we would be on a net debt basis right around 2x debt to EBITDA. So I have talked in the past of potential for refinancing. I think that will remain as something we are going to look to be interested in doing. And that's one of the things I'd like to highlight. Another thing also is that the principal repayments are fixed; however, we do have on the senior debt floating rate, a spread to the floating rate, which actually was -- went up from 16, 17 and 18, and it actually is coming down again. So just in terms of -- obviously that helps in terms of the cash cost, but also should help in terms of an earnings per share perspective and that your interest cost is -- hopefully, this year, it will continue to go down. So the percentage of your EBITDA, our interest costs continue to go down. I'll talk about 2 other things here and then turn over to questions. So we do major maintenance on turbines. One of the 2 turbines in Nicaragua every year. That's no different this year. The only thing that is different is that it is going to be somewhat longer just because it's really -- it's almost a major, major maintenance, and that will go back to the usual -- usually, it takes us about 18, 19 days. We think this one will be sort of 27. So we'll have one of the turbines down for a bit longer. In isolation, that would be about $1 million kind of lost revenue, although, as I mentioned, we are somewhat up, call it, quarter-to-date from where we were in Q3 and Q4 of last year. And you generally always get somewhat of a recharge and the plant tends to come out a little bit stronger in the following 3 to 4 weeks. So I don't think that the overall negative impact will be $1 million, but it -- maybe it's going to be in the $750,000 range, which is the recharge. But then, hopefully, we can more than make up for that with the fact that we're at higher production right now. And then I'll talk about the -- at El Carmen's and sort of generally where that leads us to Q1. So we had an issue at El Carmen, which is the 8-megawatt facility, not the 20, which has caused an outage, which it will likely be out for the rest of the quarter. So from Feb 25 to call it March 31 for sure and likely a little bit into April. So where that would lead us -- I think it would be about $300,000 change to the Q1 numbers from what we, otherwise, would have had, which is not material. That plan actually has been producing well and somewhat, I would say, ahead. So it was in a pretty good state before that. All in all, I think we'll still be, call it, for the Peru, 2 -- 2.5 -- 2.2 to 2.5 in revenue for Q1, assuming everything else stays as it has been, which I think is quite good. And it is early to know exactly what we'll be able to recruit from the outage, but we will be able to recruit something. We are in -- with our insurance policies, our coverage for these types of events, but it's going to take a bit of time for the assessment and trust to be able to give any numbers. So when I say we will be down probably $300,000, that's assuming 0 comes back from insurance, which I don't think is going to happen. So that's all I have to say. So we can open up the questions then.

[Operator Instructions] Your first question comes from David Quezada from Raymond James.

Just -- my first question here, just, I think last quarter we talked a little bit about maybe a small CapEx item, the perforation project on 6-3. I'm wondering where you're at with that and if you're still thinking about doing that?

We are still considering it. I think we -- but it's a 50-50, David, it's just the well produces, a small well of 2 to 3 megawatts. We're not going to have it in our numbers for this year, though, I think, and it's not a big CapEx number. It's like $200,000 or $300,000. I would say that given what the results are in the numerical model, we're quite happy with that. And I think we will likely pause for a year, but we won't know that for, I don't know, probably 30, 45 days.

Okay. Fair enough. And then I guess, just a confirmation, then that you guys -- the adjustments that you've been making to try and increase the steam-to-brine ratio, you're -- with the numerical model, you're happy with that and those adjustments or that process is pretty much complete now?

Yes, absolutely. We did some changes back in September, October, which have helped, and we've seen the results of that, so quite happy.

Great, great. And then just last one for me. I imagine you still have some M&A targets you're looking at, if you could just give some commentary on the -- how the opportunity set is developing there? And if you've -- any more recent thoughts?

Yes. So no, it is. We're busy on that front. I think we -- if you recall, with the 2 plants in Peru that we finished construction, we've had an in-service date, call it commitment of October 28, 2019, which we did not hit. So we needed an extension of the contract, which we got in the first week of January. So everything is fine on that. But what I would say is that the things that were in corporate development pipeline until we've got the plants finished, but also got the extension from the ministry we had to be slow playing, call it, the corporate development pipeline. So now that we had that and have clarity on that, we can kind of -- let's just say that we're back on that in earnest. And I would say that the opportunity set is good, and as we had seen for the last, call it, 12 to 18 months and it -- I would say just conceptually it's similar versions of what we did in Peru, nothing exact, but this profile is very similar.

Your next question comes from [ Tom James ], private investor.

I was looking at the MD&A and you didn't have anything under the future outlook. And obviously, we haven't really seen the impact of the revenue to be generated from Peru. I'm wondering if you could just give us a little bit more color on some kind of guidance for 2020, excluding, of course, any potential on the MD&A.

Yes. I think what we have done either through press releases or through our website in the presentation is that we do give megawatt-hour ranges for all of the plants in Peru and the prices. So for instance, we think that the 8 de Agosto plant, which has a power purchase price of $53.90 a megawatt hour, we think that will produce around 120,000 to 140,000 megawatt hours a year. El Carmen was the 8-megawatt one that we just finished as well. We think that that will do, call it, between 40,000 to 50,000 megawatt hours a year and that has a $55 -- $1,255 megawatt hour price. And Canchayllo is the one that's always been running, that will -- that tends to do around 30,000 megawatt hours a year and that has a $50 price. So you can take those. The only thing that I would say is that we're going to -- which is normal is we're likely going to be at the low end of those ranges in our first year of operation as we work through, call it, ramp up. So we haven't given formal guidance. And those numbers are more, call it, steady-state. And I would say that you could take 19% of those for the 2 plants that we just finished, i.e., 8 de Agosto and El Carmen. Apply 19% to those ranges because it is called the first year of operation.

You can't do the math for us?

Can you do the math?

I said, can you not do the math for us?

We don't -- we're not giving guidance yet, so...

Okay. On the dividend front, I know at one point we were talking about potential increase in dividends depending on how Peru is turning out, and there was no increase in dividends. I don't know that that is a very encouraging sign of your confidence in the forward outlook.

Well, I'm glad you brought that up. The one thing with the contracts in Peru is they have a May 1 to April 30 power year because that is defined mostly by, call it, rainy seasons and dry seasons there. And so what they do is it doesn't matter what date you put your plants into operation on, if it would -- until May 1, you only get paid at spot price in terms of cash on hand -- cash in your jeans. And right now, the spot price is very low. So spot price is around $12 a megawatt hour versus, call it, $50 megawatt hour power contract prices. And so -- and then what happens is starting in May not only do we get the full $50 monthly, we get paid what has been accrued between our COD and April 30. And that will get paid. So let's say that's a couple of million dollars, $2 million or $3 million, something like that that will get paid to us on a monthly basis. But that won't even be invoiced until June. Okay. So in terms of dividend increases, it is something we're going to absolutely consider and do. I can't comment in terms of the magnitude, I won't. But I would say the realistic time for us to start increasing dividends again is Q3 and Q4 given that the cash flow, the earnings and revenue will get reported on an accrual basis. But the cash flow will not really be there in terms of a big bump up from Peru until effectively, I call it, end of June, when we start getting paid. So we would really be looking at Q3 and Q4 for dividend increases.

Your next question comes from [ Peter Drucker from Barometer Capital ].

Would you be able to talk to a little bit the political kind of situation or kind of environment that we're seeing in both Peru and Nicaragua and how you guys see that affecting operations moving forward in the next couple of months?

So in terms of affecting operations, we've seen, I guess, since April of 2018. So we're coming up on 2 years since the situation got delicate, let's say. And we are yet to see any impacts on the operations. The biggest impact we had, which did flow through the statements as initially our receivables went up, call it, I think, from 45 days, which is pretty typical, to something closer to 70. And then at most in '19, it was a number in between that, and it's been very consistent since then. So we haven't really seen much. I think it's going to be quiet. The elections are next year, November of '21. I -- So if there were elections this year, I think there would be at least more noise and some press, but I wouldn't expect that really is anything coming until Q4. So it's hard to know exactly what's going to happen. But I think my personal guess is, call it, 6 months of quiet. And then maybe it's kind of Q4 or Q1 where things -- people start to talk about the elections and what's going to happen at that point in time. In terms of Peru, I don't really see -- I would look at it as a very different situation. At least you tend to get certain news, but it's quite stable, a lot of capital going in. We're a very small component of the grid. And so it's -- I don't really have much to comment other than so far we're very happy with, call it, the decline in Peru.

Okay. Fair enough. And then if you could just maybe touch or provide a little bit of color on the San Jacinto operation. I'm curious about the kind of the cyclical component that was brought up in the earnings that you put out this morning. Can you provide a little bit of color kind of on those fluctuations and when you see them stabilizing in the near future?

Right. So I don't know if you heard, but I said I'll give you these numbers again. So October, our production was 59.7; November was 59.94, December was 59.95. So I call that stable. We're actually up January and February year-to-date from that. So we think we have reached stability. There's a few things in terms of cycling. There's one well, we have 9-3, which has basically been cycling since it was drilled because it's actually got 2 legs to production. Most of our wells only have 1 production leg. It has 2. And just -- you can get different pressures and even different temperatures from each leg. And so depending on how that's operating, you get -- sometimes you can get one of the legs actually going into the other one. And so it's just an op -- from an operational perspective, it's about 4.5-megawatt well. And it's always been like this; one day this could be at 0, next day it's a 4.5 and then it's a 2. It just cycles a lot. But what -- that's actually very -- what is a little bit more hard to predict is that, how often it's cycling and so what we -- and we have another one called 12-3, which is more predictable, but it cycles. It has some high cycles, it has a low cycle and then kind of just stays that -- sets in. What was happening, I would say in the fall is that the cyclicality was more than what we experienced. And so this is where there's 2 kinds of injection wells, one are called, what they call, infield, which are closer to your production and others are called outfield, further away. And it's a bit of a trial and error. It's a combination of doing the model, the reservoir model, but also the trial and error just to say, okay, if we inject more infield, what do we see is, for instance, 9-3, does it stabilize or destabilize. And if we know it does -- how we inject does impact that and there's a theory, but then there's the practice. And so we're -- last year was a year trying different configurations. And then you need to leave them probably for 3 or 4 months to really see if there's a net benefit on that cost. And so we've been in this current one for about 4 months now, and it seems to be more stable.

[Operator Instructions] Your next question comes from Mac Whale from Cormark Securities.

Just one more follow-up on the operations there. If we're now sitting, you're pretty comfortable with your modeling and you're looking at the results being pretty stable at San Jacinto in around 60, you still have -- I think, a year ago, you were talking about waiting for that stability. And it was of another 5 megawatts higher. And it's a little bit lower than, I guess, you probably want it to be given where you have your power agreement. Does that -- does -- with everything -- I know you're saying you don't necessarily need -- well, you don't need to do more drilling. You don't -- you want to look at your options on in terms of what to do with that model now. But does it not sort of that decline in -- not decline, but the lower level, does that not make you want to go in there and say let's see if we can really get in there and get another 5 megawatts since you've got the PPA there? Like does it -- do you not feel more comfortable now that it's stable that you can go and do that?

So I say, yes. And I -- every time the net math seems to be, call it, if you drill a 10-megawatt well you get, let's say, 12 to 18 months of a net add of 8, but it just kind of then comes down to 5, but you still got a net add of 5. So the first thing is you got to run your number. Now that 12 to 18 months that extra, call it, flush production, you earn back a lot of your cost and then some, right? So then the field does seem to -- but if you just looked at our EBITDA this is just the net production in the field as you get this sort of initial bump up and then it comes off a bit and then it stabilizes. And it's always stabilizing higher, right? And so you're right that it's not as high as we were at the beginning, but it's still stabilized a lot higher than it was before. And at the same time, you do need to be modeling in that the field is going to -- other wells are going to decline at 2% to 3%, right? So the net add is even higher. But let's just say that at 60, we're still at, call it, I mean realistically, between downtime and maintenance the most we could really ever deliver is like 67, 68, practically speaking. So it's not like -- so you could probably be 7 megawatts, I'd say. When we've spoken with not just our technical consultants, but the lenders, consultants, others, call it, 3 different technical people, they also think that we could add, i.e., the add by that I mean net add. So it's not as if it's just going to cannibalize. So people do think that there's even more net add, and we could get closer to that 67. So -- and the numbers would be attractive. The issue is that we're paying down debt, we're paying dividend and we're -- we did a big investment program in Peru. And if I had a choice of doing Peru again versus our net add of 1 well in Nicaragua, it's not likely that -- we're not going to get probably the same economics if I did another Peru instead of a new well. But I think diversification trumps that, and so this is a great level. And I think as a company we're better to diversify more, even if the dollar returns are lower.

In the short term?

In the short term. So I think from a -- as a shareholder, because I think that that will lead to a higher multiple, more so than having more production in Nicaragua. I'd say that's generally our view and the Board's view. Now that doesn't mean what I would say is to the extent that we ever could do a refinancing in Nicaragua and effectively take equity dollars out, repay the debt, but get more capital in. We would then look to do more. But I would actually -- even a binary unit would come back on the table, maybe even before a well.

Okay. Okay. That makes sense.

So I think what we're seeing is like right now let's continue to diversify, let's continue to generate great cash flow in Nicaragua, and then we are going to think about the balance sheet. And if there's something out of that, then I think we can go back to growing the cash flow there.

Okay. And anything -- I know you've talked about the pipeline a little bit on a question, but I was wondering when you bought the assets in Peru there was quite a big pipeline of projects. Have you done any work on like, presumably, you own all those, but is there any further work where you've looked and said, some of these aren't actually viable? Or I know a couple of them look really good, but I was wondering whether there's anything more specific on that particular pipeline that you acquired?

Yes. Well, I would say the specific -- it's not a specific comment about the pipeline rather the -- my comment before that, So spot prices are quite low in Peru right now. So the political will to do more auctions, I'd call it, $50 to $60 a megawatt hour is low. And even though they talk about doing more, I don't think you're going to see that for at least a year or 2 there. So we'll keep that pipeline going, whereas we see other opportunities effectively, call it, more corporate development to keep us busy, where in the next, call it, 12 to 24 months that we like better for a risk/reward, and then in 24 months, which -- the spot price is not going to stay there. They are going to do more calls. And that's when I think we can -- so we're spending the small dollars to keep those things, making sure that the environmental, call it, studies are done, that's 25,000. So we are doing those things to maintain the portfolio, but I don't think that comes into play for a little bit.

Okay. And there's no other jurisdictions like in -- that have changed there that, say, the pace of looking for new assets to bring online, like something that's changed sort of politically or some condition on the grid itself that they're really looking for more renewables? Is there any change there at all in that part of the world?

Well, yes, the countries that are really, like Colombia, is massively trying to get more power, Ecuador is. So as I mentioned, we are looking at some projects in Panama. Although, I wouldn't say that they are -- they're not looking for a lot more than normal. It's sort of more typical growth. So there always seems to be kind of like Columbia is looking for thousands of megawatts of projects in hydro, so is Ecuador. So there's always something for sure to do.

Okay. But there's nothing that's changed, like there's no change in politics from sort of right to left or left to right that is -- that's always had a maiden area that was maybe before overlooked, now like sort of hot bed of activity, I think. Just curious whether there has been any.

Well, call it, I mean I would say Colombia of 3 to 4 years ago people were still quite nervous about it. Now it's like a hotspot. There's plenty who're dying to get into Colombia, and you could do -- we have proposals to do. It is a lot. There's a ton of projects, tons out there. So that has changed because it is more stable, and it's much more stable now. And it went right.

Your next question comes from [ Tom James ], private investor.

I guess you partially answered that question in terms of your M&A. My question was really that you're looking for M&A outside of Peru, so we would have a third country in which Polaris would be operating. Is that true?

That's correct. We are -- there are other M&A things in Peru that we're looking, so Mac just asked about the portfolio that we own, that we have, and I made the comment there. There are some other ones in Peru that we think is interesting from an M&A perspective. But I would suggest that the third country is a more likely event at this point. So another jurisdiction -- yes, another jurisdiction. Yes.

I think that that would be a good move. If you're going to diversify more projects in different countries that would be great.

I have no further questions at this time. I turn the call back over to the presenters for closing remarks.

Well, thank you very much, everyone, for joining us today, and have a great day.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.