Alvopetro Energy Ltd. (ALV) Earnings Call Transcript

Good morning. I'm Corey Ruttan, President and CEO of Alvopetro Energy. I'm joined by Alison Howard, our Chief Financial Officer; and Adrian Audet, our Vice President, Asset Management.

Hi, everyone. Thanks for joining us this morning. Just a few administrative points before we start here. We will be recording today's call, and we will have a replay available on our website later on today. [Operator Instructions] Lastly, just a reminder, we do go through various forward-looking statements and have non-GAAP measures and some oil and gas metrics throughout the presentation. So we do encourage you to read all of the cautionary statements and other disclosures that you can find at the end of our corporate presentation that's posted on our website.

Thank you, Alison. All right. So I think the third quarter was another good quarter for us. If you recall, just looking back, we had a pretty good year last year. Our production was up over 40%. We're off to a pretty good start for -- well, we're getting most of the way through 2026 now, but we're tracking to be up close to 25% again. You can see our third quarter production averaged 2,966 barrels of oil equivalent per day. We did have a 5-day -- or close to a 5-day shutdown of our gas plant to finish the planned upgrades at the plant. All that was done in September. And then we also just announced our October production, so up to 3,200 barrels of oil equivalent per day after that expansion was done. And just a reminder, if you look at the funds flow from operations that we've generated since our key project in Brazil came online in 2000, we've now generated funds flow from operations of $245 million and 46% of that's been returned to our stakeholders, including close to $80 million of dividends. So I think to be able to generate this type of organic growth and have that type of discipline back to our shareholders, we're pretty proud of that. The last thing I'll make -- a comment I'll make, we'll talk about our capital program that continues this year. But as we exit the year with the remaining kind of facilities focused investments that we have in Brazil as well as a very busy program in Western Canada, I think we're well positioned to continue this growth trajectory as we move through 2027.

So the one key thing we like to highlight is our exceptional funds flow from operation generation, and it really starts with our operating netback. A reminder, this is one of those non-GAAP measures. It's our operating profitability. We express it in per barrel of oil equivalent, and that's the green bars, that's the profit that you see on our production. So in Q3, starting at the top of the bar chart, we had a realized sales price of just under $71. That included natural gas sales of $11.49 per Mcf, up over $0.50 from our Q2 price. The orange bar, we deduct off our royalties. That's the orange bar, really attractive royalty rates. Our effective royalty rate overall is just over 5% in Brazil, just under 5% and in Canada, roughly 15%. And then we also deduct off here the operating costs, and we've combined our trucking costs in Canada as well. That's the gray bar. Again, really low-cost natural gas production in Brazil. Our operating costs in Brazil were about $5.50 this quarter and overall company-wide, just over $6. So that allowed us to generate an operating netback of $60.87 per BOE. That's U.S. dollar. That's up $1.79 from last quarter. And when you look at that relative to our realized price of $70.62, that's a netback margin of 86%, which is really best-in-class. Thinking about it in total dollar terms, we had revenues of $19.3 million. We generated operating income of $16.6 million, again, that operating netback margin of 86%. And then you layer in all of our other costs and a very low current tax rate, we're eligible for a tax incentive in Brazil that reduces our tax rate to just over 15%, and we generated funds flow from operations of $14.3 million on that $19.3 million of revenue. So that's a 74% margin from a funds flow side. So it's really quite remarkable on this level of production and how much funds flow we could generate, and we'll look at that next. So this chart just compares this quarter's funds flow of $14.3 million to Q2 of $14.1 million. You can see it's relatively flat. We did have that slightly lower sales volumes in Q3 that Corey touched on mainly due to that planned shutdown we had in Brazil. That was more than offset though by our realized prices. Our royalties were a little bit lower and other income was higher and G&A was also a little bit lower. Overall, that was offset by some marginally higher production expenses and current tax, and we generated the $14.3 million this quarter. On the net income front, there's some noncash things that go through our net income. So we did see a slight decrease, $1.2 million from Q2 to $8.5 million net income in Q3. The biggest driver of that was foreign exchange. We had a gain in Q3 compared to a very small loss in -- or a gain in Q2 compared to a very small loss in Q3. So overall, that was the biggest change in our net income there.

All right. So this chart just tracks our dividends since we started them in the third quarter of 2021. We've been paying out USD 0.12 per share through this year, including our third quarter dividend. That represents a yield of 7.5% at current share prices. And I think I referred to this earlier, but since inception, we've returned USD 2.18 per share or close to $80 million back to shareholders. Just an update on our gas pricing formulas. I think everyone has seen this a number of times. As a reminder, about 80% of our gas right now is being priced under this QDC1 formula, which is the red line that you see here. 20% of the gas is being priced on the QDC2 line. The formulas are actually -- the detailed formulas are in footnote 5 to the presentation. But at risk of oversimplifying it, about 1/3 of this QDC1 formula effectively is fixed, about 1/3 of it floats based on Henry Hub prices and another 1/3 of it floats based on Brent oil prices, whereas the QDC-2 one floats entirely based on Brent. The weighted average between the 2 is the green line that you see here. As Alison noted, our Q3 average realized price was $11.49 per Mcf. The November 1 reset that just happened is around USD 11 an Mcf, so fairly close. And if you look at the futures market as of, I think this was November 4, so a day or 2 ago, this is what the forecast looks like as we move through next year. So if you look at the green line, kind of averaging between that $11 and $12 mark through to the end of next year. So certainly helps with our free cash flow generation capacity. And...

So far in 2026, we've been very busy with all of our technical teams. So we've been executing our capital program, which has been targeting the Murucututu asset. First off, on the facility side, our gas plant upgrade was completed in September, which culminated in the shutdown that Corey mentioned earlier, that 5-day shutdown in September. So this upgrade gives us the ability to process larger percentages of the richer Murucututu gas. And then at the Murucututu field level, our teams have been working to finish our pipeline expansion and the tie-in at the G location. And both of these projects are required so that we can complete and tie in the newly drilled G2 well and have the ability to put this on production. So both of those projects, you can see in the picture at the bottom right. So the pipeline is there on the right with the line pipe laid on right away. And then the rig there on the left is at our G-Pad location. So we're just in the final phases of moving out of the way, and then we'll start the actual tie-in projects to the flow lines. So both of those 2 projects are slated to be done in the first quarter of '27. The teams are also finishing an expansion at the Murucututu hub facility, which is the picture at the top right. This will give that facility the ability to flow up to 600 e3m3 a day and includes new separator, flare and some other equipment. The project is also going to be done in the first quarter of 2027. On the drilling side, both the D1 and the H2 well were drilled then completed in the last quarter or the last few months, and both wells are currently flowing into our production system and into our sales system. And then we finished this drilling campaign with that G2 well. This project was executed very efficiently. We are encouraged about the log results we saw on this well. We logged over 97 meters of net pay over 4 Caruaçu sequences and the upper Gomo sequence. And that well has now been cased. And like I mentioned earlier, we need to wait for the facilities projects to be done before we finish the completion and then put that well online, which is expected in the first quarter of 2027. Next year, we're planning a follow-up drilling program at that same G location as well as an exploratory well at our 183-C1 prospect, which is west of Murucututu itself.

All right. So moving on to our Western Canadian business unit that I think we've assembled a pretty impressive position here. If you recall, we did a couple of initial joint ventures with an initial partner. We'll call that the 2025 JV focused on the Mannville stack heavy oil play fairway. So that was focused on the Saskatchewan side of the play in this kind of green outline that you see here. And then in the third quarter, we announced a new joint venture, the 2026 JV with a new counterparty. The terms of that are basically Alvopetro is going to fund 5 earning wells here. We've started drilling the first of those 5 this morning actually. And then as the terms of that are basically, we earn 75% interest in those wells before getting payout. And then after payout, we earn a 50% working interest. And as we drill the wells, we earn a 50% interest in all the surrounding undeveloped land. So I think it's certainly a nice transaction for us. It gives us access to kind of an accelerated drilling program here in the fourth quarter. And we're getting access to 2 of the leading technologies that are being applied to this play. So open-hole multilateral wells and single-leg horizontal wells with recirculation strings. We're drilling the 5 wells across 5 different core areas into some very attractive geologies. And then the other thing is with our initial joint venture partner here, we actually did just finish drilling 2 additional gross wells, 0.8 net wells. Those were brought on production in October that go through a cleanup flow period and then we fill the tanks. And ultimately, you'll start to probably see sales from those wells show up in our November and certainly December sales numbers that we announced. But I think if you put this in perspective, this is one of the leading plays in Western Canada. And through these 2 transactions, we very quickly built, I think, a pretty impressive inventory of opportunities, after earning here, our land position will be over 133 square miles of gross land over 175 Tier 1 drilling locations. So we're pretty excited about the business here, and we've got a very busy fourth quarter ahead of us. So just to summarize again, Alvopetro certainly offers, I think, an attractive investment proposition, whether you look at it on a value yield or growth basis. I think we've got some exceptional quality assets that are really -- that ratio of funds flow to revenue that we can generate, really highlights the strength of our assets, and we've got some highly strategic infrastructure and I think a pretty attractive and disciplined capital allocation model where we've been able to have some attractive organic growth and pretty disciplined return of capital to our stakeholders. From a value perspective, we're trading at less than 2/3 of our 2P NPVs. I mentioned the yield, 7.5% yield. And from a growth perspective, I think it is a very busy time for us. And although we've had 2 successive pretty good years, I think as we move through into next year, we're very well positioned to continue that growth trajectory and unlock a lot of value for shareholders.

Okay. So we have some questions. We do have some from social media e-mails. So maybe I'll start with some of those. There are quite a few questions actually around facilities, expansion and capacity. How are you managing facilities capacity constraints between your plans to increase Murucututu field and pipeline capacity to 600,000 cubic meters per day and your existing UPGN capacity, considering the contribution of higher heat content and liquids-rich gas from Murucututu, along with your commercial offtake relationship with Bahiagas.

Okay. So I think Alison has combined a few questions into there, but I'll try and cover them all off. So our capital program this year really was kind of dual-pronged. We had a facilities component and a drilling component. The facilities part of it really has been to address the levels of success that we've had at Murucututu. As Adrian mentioned, the UPGN expansion was completed in September. Most of that related to improving the condensate stabilization process at the plant, and we did add some additional redundant compression as well. But the biggest reason we did that is it will allow us to produce roughly about half of our gas from the higher heat content gas that we have at Murucututu, so 50-50 relative with Murucututu. It also should give us the ability to grow the nameplate capacity of that plant up to about 600,000 cubic meters a day, which is just over 21 million cubic feet a day. In parallel, we're -- as Adrian walked you through those facilities projects that are actively going on in the field right now, we're expanding the field production facility at Murucututu and the related pipeline takeaway capacity to increase Murucututu's field takeaway capacity back up to that kind of same number. Longer term, if you look at those 2 things together, if we move towards an even higher percentage of gas coming from Murucututu or other hot gas, like, for example, the 183-C1 exploration prospect that we're going to drill next year. To do that, we would have a next plant expansion at the gas plant to basically allow us to remove the propane portion of the gas stream from the sales gas and that's something that's actually being engineered right now, and we'll continue to work through that. But that gives us the next layer of flexibility. The last part of that was related to the interaction, I think, with Bahiagas. So I think as demonstrated in the last couple of years here, in 2025, I think we increased our firm commitments to Bahiagas by 1/3. In 2026, we increased them by another 25%. And then as these projects get completed, we'll look to continue to complement that. The City Gate that Bahiagas built at our physical gas plant and the pipeline capacity from there is pretty robust. I think it's about 70 million cubic feet a day. So we've got lots of room to grow there. And the relationship with Bahiagas, just so everyone understands, we typically look at that annually and then we'll commit these incremental volumes on kind of a 1- or 2-year period. And that's kind of what we did, that QDC 2 line that I reviewed in the presentation, that's about 20% of our sales right now. We had negotiated that, I think, near the end of 2025.

Just following up on the capacity because there's some additional questions around if we have sufficient drilling inventory, but there's another question about previously back in 2022, we showed a long-term vision of Brazil of 6,000 BOE per day. And now you've added our Canadian operations. Is Brazil -- is the long-term vision for Brazil still 600 -- sorry, 6,000 BOE per day? Or are you going to be relying on Canada to get to that longer term? But maybe the first part is on the drilling inventory and filling this capacity that we're building for.

Alison has now combined -- I think that was 3 questions again combined to 1. So okay, I'm going to try and go back to 2022 in my mind. So someone's testing me pretty well here. But as I recall, we had presented a number of kind of some stacking production charts that with success, particularly at Murucututu on both the reserve and resource development side as well as kind of a vision for what that business could grow to, which is basically kind of doubling what the original plant size was. I think if I build on the response that I made to the previous question, I think you can see we've been growing our business in steps. So we're up 40% in 2025, up about 25% this year. We're positioning ourselves with the capital program, both facilities and drilling for the next step to be about another 20% up with that. So another good way to maybe look at how we think about what the right size of facilities capacity and gas sales capacity is maybe in a quantitative way is our reserve life index. So if you look at the end of last year, our reserve life index, I think, on a 2P basis was about 12.5 years. So that's a pretty good number. But if we have continued success at Murucututu and export nearby exploration and things like that, and that number starts to grow higher than that, we have a choice basically, do we produce at that same level that we're building towards for longer? Or do we expand the plant and the gas sales again. And I would say if that reserve life index gets considerably longer than that 12.5%, what it's pointing you to is that, okay, we should build more steps and continue the growth towards that kind of 6,000 number. And that's just in the area that we're talking about there. If the number falls below that, then it tells you we should be focusing more of our attention on drilling new opportunities and building the inventory and things like that. And hopefully, we're doing both of those things. I think the 6,000 goal is still a rational goal, especially when you consider things like the 183-C1 exploration prospect that we're drilling next year. We just added over a 460 square kilometer exploration land position in the adjacent basin in the Tucano Basin. So although that's early stage, that has a lot of potential for a company our size. So obviously, it's success-based, but that's what that looks like. And then from a numeric perspective, I talked about the 20% uplift in Brazil. So that would get us just shy of, say, 4,000 BOEs per day. The Canadian platform, we're not putting detailed production guidance out there. But if you look at the type curves that we presented and the inventory that we have, depending on the levels of success and the pace at which we're drilling those wells, which is somewhat oil price dependent as well, we certainly think that, that asset has the potential to grow to a couple of thousand barrels a day without adding too much more to that inventory. So I think things are looking pretty good. And then the drilling inventory, I think I just answered part of that. So I think next year, we have a little bit of a balance between exploration and ongoing development at Murucututu, which will, I think, help us position us quite well for that next stage of growth there. And then the Canadian program, we've got a pretty deep inventory of opportunities there. We'll drill these next 5 earning wells. We'll get the results from those, and then we'll design a capital program for next year and the years beyond. But I think there's a pretty deep inventory there. And then I talked about the new exploration position in the Tucano. But we're always looking for new opportunities, and we have a pretty long-term view on the business.

Maybe we'll just jump. We have a couple of questions on Canada. So looks like Canada activity is increasing now, but there was relatively little activity earlier in the year. Can you comment on why that was, especially in the context of the oil pricing being so high in that period?

Yes. With our initial partner, we're trying to work through a collaborative drilling program with that counterparty. So it ended up -- the timing of the next 2 wells, we just finished drilling them, and then we're going to work to design next year's program. But with the addition of -- we just added this Courser second joint venture, the 2026 joint venture in September. So I think we've pretty quickly moved to drilling there, and we look to have -- we probably won't get all 5 wells drilled in the fourth quarter. They'll probably extend into the first quarter, but hopefully, at least 4 of the 5 will be drilled in the fourth quarter. So it's a pretty active program.

So in Canada, one of the questions is how many total wells are we drilling in Q4. So we've just finished the 2 with the original partner, the 2025 joint venture partner and then we have these 5 earnings wells with the 2026 partner. And then -- and as we mentioned, that could potentially -- some of those could be into early 2027. And then the other question is how many in 2027 after that, I guess, would be the question on that.

Yes. I think we're going to define that based on the results that we see. And yes, stay tuned.

Staying on the Canada front, how have the existing wells in Canada produced relative to your type curve, declines seem to have accelerated recently? And do you have an expectation of flow rate for the 2 wells that just came on production?

Yes. So unlike maybe these kind of higher -- individually higher impact wells in Brazil, partly because we have partners and partly because the data is a little bit delayed publicly, we're not going to kind of announce initial production rates from individual wells. The other nuance with these heavy oil wells that we're drilling is you go through a cleanup period where you're producing back the drilling fluid and then you're slowly kind of ramping up the oil production. So the pace at which that starts to show up in our sales can vary. If you look back, it's not in this presentation, but in some presentations we've had of late, the type curves, we've got kind of a range. But if we can be between 150 and 200 barrels a day gross per well and cumulatively produce upwards of anywhere above 100,000 barrels per well, ideally in the 120,000 to 150,000 or 180,000 barrels per well, these wells can generate some pretty impressive rates of return, especially with current oil prices.

Okay. Let's move back to Brazil. We have a number of questions around our most recent wells that we've drilled there. So on an H2 well, we just announced initial kind of production results from that well. What rate do you expect once it's cleaned up? And how does this compare to what you expected before drilling?

Yes. So I think we've had kind of variable results from our Murucututu project, which is a little bit to be expected. Geology is variable after all. Some of them probably below kind of what our expectations were and some certainly well above it. So maybe I'll talk about it altogether. And it's a little bit difficult, like we announced net pay in our presentations and things like that. It's a little bit difficult to contrast them apples-to-apples because petrophysics is more complicated than just the net pay, but I'll try and give you a little bit of a sense. And every well is a little bit different. The data that we get from each well is a little bit different. But like a good example would be our D4 well, which is one of our better wells, we were only able to get that drilled to kind of the bottom of Caruaçu Sequence 6.2. We had some challenging hole conditions in the well. And as a result, we cased that very quickly without open hole logs. We had good gas shows while drilling and cased hole logs. So we basically define the net pay and completed that well based on that. The H2 well, the good news is we drilled that into the prospective resource area. So it looks like we were migrating resource to reserves here. That well was drilled in a kind of down dip orientation and the net pay that we had defined was just in the lower 2 sequences of the Caruaçu formation. So this is a lot of information. And then if we contrast the G2 well that we just drilled, we were able to actually drill that well very effectively all the way through up and tag the upper Gomo portion of the reservoir. So we got all 4 Caruaçu sequences into the upper Gomo. We were able to get sidewall cores, open hole logs. We're able to do all that, I think, for about 10% under our AFE budget. And we've got, I think, some pretty impressive gas shows while drilling with the open hole logs, we defined about 97 meters of potential net pay through all 4 of those Caruaçu sequences and the upper Gomo sequence. And then that structurally, that G2 well is about 65 meters up dip or up structure from that good well that we drilled with the 183-D4. So hopefully, that kind of puts some of that in perspective. But no, certainly, we've had -- the H2 production results are below the D4 well. But like I said, it was only completed in 2 of those sequences. And as far as cleanup goes, we've recovered a decent amount of the completion fluid. We'll see how the well performs. All these wells we'll continue to monitor that, and we also run production logging tools and try to improve our understanding of what's happening on the subsurface.

Great. Maybe a little bit more on G2 because there's a lot of questions around the significance of the 97 meters of potential net pay and also around the timing of the completion? And will that be done in Q1? And why aren't you doing that right away?

Yes. So the first part of that, I think I touched on in the earlier response. So we're pretty happy about this between the gas shows that we saw while drilling and the quality of the net pay that we see on the open hole log. So we're certainly looking forward to getting this completed. The timing is more driven. I think Adrian talked about that. That G well pad, unlike where H2 was drilled, that H2 well pad was already pipeline connected. It was off the 197(1) lease. So we were able to put that on production right away. The difference is that G pad was just recently constructed. That's the first well drilled off of it, and we always had this facilities plan to tie that back into the 183(1) lease, which was that upper picture that Adrian showed. So it really has to do with the fact that when we complete, stimulate and bring these wells on production, we want to do that as quickly as possible to get all the fluids back out of the well. So what it means is we're going to make sure that we have that pipeline connected and then we can go from completion to production to sales instantaneously basically.