Alvopetro Energy Ltd. (ALV) Earnings Call Transcript

Good morning. Thank you for joining us today for our Q2 2025 earnings call. I'm joined today by Alison Howard, our Chief Financial Officer; and Adrian Audet, our Vice President, Asset Management.

Good morning, everyone. Thanks for joining us today. Just a few administrative points before we begin. We are recording today's call, and we will have a replay available on our website later on this afternoon. [Operator Instructions] Lastly, we do go through various non-GAAP measures, and we make forward-looking statements throughout this presentation. So we do encourage you to review all the cautionary statements and additional disclosures, both on our corporate presentation and on our most recent management discussion and analysis that was just released yesterday for Q2.

All right. Thank you, Alison. So as we previously announced, we did upgrade our gas sales agreement with Bahiagas late last year. And as part of that, we did increase our firm gas sales volumes by 33%. That, combined with some considerable operational successes, has resulted in a very strong start to 2025 for us. As per last quarter, our production was up 41% quarter-over-quarter in Q1, and we had a similarly strong quarter in the second quarter here, pretty consistent with Q1 and up 50% from the previous quarter -- second quarter of last year. We did have some facility maintenance and inspections in Brazil that did impact the quarter, and that was offset by the addition of our new production in Western Canada that averaged 138 barrels of oil per day. As you can see here, our July production did continue at pretty consistent levels, averaging almost 2,300 barrels of oil equivalent per day in Brazil and 134 barrels of oil per day in Canada. And Adrian will walk through this later, but our strategy here through the rest of this year is to add additional 100% working interest productive capacity in Brazil with a target of getting to 3,000 barrels of oil equivalent per day and be in a position again to increase our firm sales volumes for 2026. And then in Canada, you'll see we have drilled an additional couple of wells that will be brought on production here later this month, and we expect to drill a couple more as we exit this year.

So just jumping into some of the key highlights from our results released yesterday. This first slide here that we'll go through is our operating netback. Again, a reminder, that is a non-GAAP measure. It's a measure of our operating profitability. We express it in per barrel of oil equivalent, and that's the green bars that you see on the chart. So to compute that, we start with our realized price. At the very top of the chart, we deduct off royalties in the orange bar. The gray bar, we've aggregated both our production expenses and transportation expenses, and then the net result is our operating netback. So looking at Q2 2025, we saw a marginal decrease of about $0.47 per BOE in our realized price, overall average realized price company-wide. So we did actually have an increase in our realized natural gas price in Brazil, up 2% to $10.62 per Mcf. But with bringing on our Canadian operations, our overall company-wide realized price did decrease just marginally. On the royalties, that orange bar, our royalties were down $4.63 from last quarter. If you recall, our last earnings call, we did have some historical adjustments in Q1 recognized relating to a dispute on our gross overriding royalties on natural gas. So with those historical amounts in there, we did see a decrease in our overall royalties this quarter. On an effective royalty rate as a percentage of sales, it was 4.7%, which was 4.2% in Brazil, and then in Canada, 16.3%. In Canada, it doesn't include our Crown royalty charges, any gross overriding royalties applicable, and then on freehold lands, our freehold royalty rate as well as Saskatchewan resource surcharge. Moving on to production expenses and transportation expenses. We've aggregated that in that gray bar there, totaling $5.51 this quarter, including production expenses of $5.37, which is relatively consistent with last quarter. And then we do have transportation expense in Canada for clean oil trucking that worked out to $0.14 per BOE company-wide. So overall, we generated a netback of $54.72. That was up close to $4 from last quarter. And that includes a Brazil operating netback of $56.08, which was up over $5 from last quarter. And then in Canada, USD 32.07 operating netback. So overall, really strong netbacks still in place here. If you look at our operating netback margin, which is that line at the top, that's our operating netback expressed as a percentage of our realized price. We are at 87% this quarter. And overall, for the last 6 quarters, well above 80%, and that's really best-in-class netback margins compared to companies operating in Canada and in South America. And you layer in the fact that we have a very low effective rate in Brazil, we're eligible for a tax incentive of 15%. And the fact that in Canada, we have significant tax pools to offset our current earnings in Canada. So we're not expecting tax in Canada this year. Overall, that allows us to generate really strong funds flow from operations. So going into funds flow here. Just a reminder, that's cash flow from operating activities before changes in working capital. So this chart just highlights the change from Q1 of $9.2 million this quarter, we were up $1.1 million to $10.4 million of funds flow. Basically, all of that is due to that royalty change without those historical royalty amounts that I talked about in the operating netback discussion. Similarly, on net income, overall operating netback higher with those lower royalties. Depletion and depreciation expense also decreased compared to last quarter, and then those were offset by lower foreign exchange gains this period and then higher current and deferred tax. So overall, net income went up about $800,000 to $6.8 million this quarter. On the balance sheet side, these green bars that you see go through our working capital, including cash balances. We've shown this since we started natural gas sales back in July 2020, so over 5 years now. This quarter, our operating -- or sorry, our working capital was $6.8 million. So we did see a bit of a decrease from Q1 and Q4 2024, just we have had higher capital spending in the last 2 quarters, as you've seen. So that has resulted in a decrease in working capital, but still a very strong working capital position, and our cash balance is still $15 million as of June 30. And we are debt-free as well, as you pointed out.

All right. So just on our dividend history, all the way through last year, we paid the dividend at USD 0.09 per share quarterly. With the new gas sales agreement and the higher sales volumes that I walked through earlier, we did increase the dividend starting in the first and second quarters of this year to USD 0.10 per share quarterly. And since inception, when we started the dividend in the third quarter of 2021, we've now paid USD 58 million or USD 1.60 per share back out to shareholders over that time. Just walking through our more, I would say, disciplined capital allocation model that we'd introduced quite a while ago. Again, our model is to reinvest about half of our cash flows in growth and return the other half to stakeholders. If you look at the chart on the left-hand side, the green lines with the black dots are all the cash inflows each quarter. Most recently, as Alison walked through, $10.4 million of funds flow from operations this quarter. And then all the different stacking bars show the cash outflows in each quarter. So the yellow is the reinvestment, and the various shades of green shows the return to stakeholders. As Alison noted, we did have higher capital expenditures, particularly in the last 2 quarters here as we had simultaneous investment programs happening both in Canada and in Brazil. We would expect that as we move into the fourth quarter to reverse and slow down a little bit. If you look at the pie on the right-hand side, you can see since starting up production of natural gas in Brazil, we've had cash flow from operations or funds flow from operations of over $183 million now. 49% of that's been reinvested, 48% of it has been returned to stakeholders, and the remaining 3% represents the portion where we built that cash and working capital position that Alison walked through.

So we've established a strong gas infrastructure platform, and our focus is firmly set on our next growth objectives. Our near-term target is to be at 18 million standard cubic feet a day or 3,000 barrels of oil equivalent, which will roughly fill our current gas plant capacity. Our longer-term vision is to double this. So reaching these objectives is planned to come from a combination of our assets. Our first is our core base of operations, which is Cabure. The Cabure unit has been performing very well, and we're looking to further expand this unit capacity with our development well program. This program is currently underway with 3 of the 5 wells drilled and our fourth one to be finishing drilling this month. However, our biggest growth opportunity is the Murucututu project, which is a 100% working interest for Alvopetro, and this is just north of Cabure. We had a very successful completion late last year on our 183-A3 well, which is on production now. And we're now focused on the completion and the tie-in of the 183-D4 well that was drilled earlier this year. For this asset, GLJ has assigned a combination of 2P reserves, contingent and prospective resources to this opportunity. And we are working to migrate this into production and cash flow in support of the longer-term growth objective. And just some more detail on this main growth opportunity in Murucututu. So like I mentioned, this is a 100% working interest in Alvopetro, and it's just north of Cabure, and it's pipeline connected to our sales infrastructure. So earlier this year, we finished drilling the 183-D4 well. And we're following -- which followed up on the A3 success of last year. The logs are shown on the right-hand side of the slide, and we identified 61 meters of net pay over 3 Caruacu sequences, 6.2 to 6.4. And this is the same formation as being produced in Cabure, it's just across the fault and it's a bit deeper. The well was completed, but as -- after we drilled it, we completed it with sliding sleeves in the casing program over 8 spots within the Caruacu formation. And we have just finished completing 7 of these sleeves, and we're in the process of configuring the well for initial production right now. Note that in our 183-A3 well, we have production only from the top sequence, Sequence 6.4, which is in the D4 well, just the top 3 sleeves there that you can see with the cursor on the right. So for the D4 well, we've completed 6.2 and 6.3, and we'll put co-mingling in all of that and putting it on production later this quarter.

All right. So just moving on to the Western Canadian entry that we announced on February 5 of this year. I remind you, our initial focus areas is on the Mannville stack. This is a resource that straddles the Alberta-Saskatchewan border. We're on the Saskatchewan side of the border. It's a multi-zone area. You can see up to 8 different horizons that can be targeted. Our first 2 wells targeted the General Petroleum and the Lloydminster formations that you see there. And so this is a pretty exciting play, I would say. We've got stacked multizone potential, and it's really something that's being reinvigorated through the application of the open hole multilateral drilling technology. There's a large amount of [ original ] oil in place in roughly 3- to 5-meter thick sands that we're targeting here with excellent reservoir quality. So the red dash line that you see on the map here is our AMI with our partner. The yellow is our lands here that you see. As we announced, I think, on our last call, we did drill the first 2 earning wells to earn into this play, 100% turn, 50% in all this. Those first 2 wells were drilled at Neilburg South and Lashburn. And then more recently, we just finished drilling the next 2 wells, both at Big Gully, you can see on the northern part of the map sheet there. And we were able to drill both those wells with 8 open hole legs totaling over 19 kilometers of open hole horizontal reservoir access, and we'd expect both those wells to be on production later this month. So I would say we're extremely pleased with this entry into Western Canada. And part of the reason we did this is we've got exposure to much lower geological risk, I would say, an excellent and competitive service environment. Our individual well costs are much lower. And we've got the ability to very effectively apply leading edge technology to a proven resource that can generate very strong economics, short cycle times and rapid payouts. And I think we've got a lot of opportunity in a basin that really is starved for capital. And the nice thing is we've got a big inventory of locations that we can get after here. And to put this all in perspective, I think it is kind of remarkable that we signed this deal on February 5 of this year. And we've already got 4 wells drilled, and we expect to have all 4 on production within the first 7 months of starting out here. So we're pretty excited about it. Just talk about the individual well performance from the first 2 wells that we brought on production. The 2 kind of more straight lines that you see here, the upper one, the blue line is the type curve that we had established before we did the farm-in. And then the lower dash line is just basically 80% of that type curve. So respectively, we would recover 121,000 or 97,000 barrels of oil on an expected ultimate basis. And you can see the rates of return at a $70 WTI that, that type curve can generate close to 100% rates of return payouts of basically a year, extremely strong economics. And then from the individual well performance, it's the more jiggery lines that you see there. The Lashburn well, the green one, was the first well that came on production. And then the Neilburg South well was the blue one. So you can see the first one performing within that expectation range and the Neilburg well significantly exceeding expectations. So what we've done here is just created an indicative multiyear development. It shows 4 wells being drilled this year and then basically 12 wells per year, a total of 52 wells, so roughly half of the inventory that we're currently seeing. But it just gives you an idea of what this looks like on a multiyear basis. The green lines show the dollars, and the black lines show the production. The solid and dash lines match those type curves that you saw on the previous slide. And what is interesting, the right hand -- the green lines match the right-hand axis. So you can see for a maximum capital exposure of between $7 million and say, $9 million, we have the opportunity here just at those type curves to build somewhere between 1,100 and 1,400 barrels of oil per day production platform that after returning all the capital, has the potential of generating free cash flow of up to $80 million. So we're off to a good start, and we're very excited about this. So to conclude, I think we continue to deliver some pretty strong results. Obviously, we've still got very attractive natural gas prices with industry-leading operating netbacks and margins, our strong Q1 and Q2 results this year of strong production growth. We've got a clean balance sheet, very good free cash flow generation capacity that helps really underpin that more balanced capital allocation model that I reviewed earlier. For value investors, we're still trading at less than our 1P NPVs and about 45% of our 2P NPVs. For yield investors, that USD 0.10 per share quarterly dividend translates into a yield of over 9%. And for growth investors, I think we've got a very exciting organically funded capital program that has the potential to unlock an awful lot of value, especially when you consider it relative to our existing enterprise value. And I think now with the ability to deploy capital in high rate of return opportunities both in Brazil and Western Canada, I think we're positioned better than ever. And I think as a result of that, we've significantly strengthened our capital allocation model. I think Q3, in particular, is going to be a very exciting quarter for us. We've had a lot of simultaneous activity here. And if you think -- we're going to bring on 4 wells out of -- new wells out of the unit. We've just completed the completion at the 183-D4 well, which looks extremely exciting, expect to have that well on production later this month. And then the latest 2 wells that we drilled in Western Canada also coming online roughly around the end of this month. So it's an exciting time certainly to be an Alvopetro shareholder. And with that, I'll turn it over to the question-and-answer period.

Okay. We've got a few questions in. How many drill locations are ready at Murucututu? And when do you expect to drill the next well on that property?

So if you look at our broader corporate presentation, what you can see is there's some actual -- there's some aerial photos of the 3 well pads that we've got. So our 197(1) well is producing from one pad. We've got our field production facility and our 183-A3 well from another pad and then the D pad, 183, where the 183-D4 well was just drilled and completed from. So 3 different pads. We can probably drill at least 6 additional locations from those pads. And we're looking at licensing another pad to access some of the more southern locations, and that's in the works right now. So I think the second part of that was when will the next wells be drilled.

Yes.

We're looking at the contracting and procurement and all that for those wells. Practically speaking, we're probably looking at the -- into the early part of next year. We'll get the results from this current D4 well that we're bringing on production, incorporate that and then look at restarting drilling next year.

Do you have any expectation on production rates from the 183-D4 well?

Yes, we don't really put out those -- that production guidance. But if you look at our 183-A3 well, it's been producing about 53 M3 per day roughly, and that's just from that upper sequence that Adrian talked about. So we don't really want to speculate, but we're obviously completing more of it, and we're optimistic about it.

Do you have any drilling plans for Block 183, the portion of the block that is not part of Murucututu?

For me? Yes. We actually just recently -- we have another prospect that we had identified there. We've made an application to the ANP to extend the block, and we're working through all the permitting to do that. I forget when the new deadline is, but we've got several years to...

2027.