Alvopetro Energy Ltd. (ALV) Earnings Call Transcript & Summary

Good morning. Thank you for joining us today for our second quarter 2022 results webcast. I'm Corey Ruttan, President and CEO. And this is Alison Howard, our Chief Financial Officer. And I'm going to turn it over to Alison to start.

Thanks, Corey, and good morning, everyone. Just a reminder that this webcast is being recorded today, and there will be a replay available on our website shortly after the call. All participants are in listen only mode for the duration of the webcast, but we will be hosting a Q&A session after our presentation. [Operator Instructions] These are our cautionary statements. I'm not going to go through these in detail, but I do encourage you, do visit our website and review those within our corporate presentation. So just starting things off today. I think you'll have seen that we did a financial statement -- restatement of our prior year financials. So I just wanted to give a bit of a summary on that. So this all stems from accounting for actually the 2012 acquisition of these Brazil assets and purchase price accounting with respect to some fair value adjustments. So under IFRS, we are required to carry certain fair value adjustments in local currency of our subsidiary, which is the Brazilian Reais, and we had carried these in U.S. dollars. And so when we correct for this and we carry in local currency, every period end date, it gets revalued based on the new U.S. dollar foreign exchange rate at that time. So what happens is when we look at the adjustments in aggregate is there's an overall reduction in the carrying value of our E&E and PP&E asset on our balance sheet just due to the devaluation of the Brazilian reais relative to the U.S. dollar since 2012. That's partially offset on the balance sheet by the recognition of a higher deferred tax asset because we have lower accounting carrying value. And then overall, our retained earnings actually increases from what we reported previously due to lower impairment charges in U.S. dollar equivalent and lower depletion expense and that higher deferred tax recovery. So I think the key takeaway here is that this doesn't have anything to do with our operations. There's no change in our cash or our working capital. There's no change overall in funds flow from operations that we reported or cash flows from financing or investing activities. There's no change in our business overall. These are all accounting adjustments. But I do encourage you to review the financial statements and the note disclosure that goes through this in even more detail. And of course, if you have any questions, feel free to contact me directly, and I'm happy to walk through that in more detail. And I will now turn it back over to Corey.

All right. Thank you. So we obviously continue to post some pretty strong production results ahead of the pre-commercialization expectations that we've set. Our Q2 production was impacted, as we previously announced, by our planned 5-day shutdown of our gas plant in connection with the expansion, which is now complete. And you can see our July production was another good month for us at over 2,500 barrels of oil equivalent per day, which is up 7% over Q2 average. With the [indiscernible] expansion now complete, we have the capacity to produce -- or to process and produce up to about 3,000 barrels of oil equivalent per day. If you look at our past production, obviously, it's been incredibly stable. The limiting factor really was the plant capacity. Going forward, our production will be more dictated by production availability from the unit in combination with our partner as well as the timing and quantum of future production additions from our new projects, which we'll talk about during this presentation. So that being said, we do have the ability to produce at higher levels, which is great, but you may also expect a little bit more volatility, certainly than what you've seen from the past experience. This is a graph that we show on all our quarterly earnings calls. It shows our gas pricing mechanism within our gas sales agreement. Just as a reminder, the 3 different gray dash lines that you see there are the 3 international benchmark prices that get used to calculate our realized gas price: those being U.K. and NBP gas price, U.S. Henry Hub gas price and Brent oil equivalent. The black dark line is our actual realized price for Alvopetro. If you recall, we had a very large increase in that effective February 1 of this year. It's about a 50% increase. And then in addition to that, we had an appreciation of the local currency which actually ended up meaning that we realized through the first half of this year a price higher than our contractual ceiling, which is noted in green. We then did have another price redetermination. We just announced that. That was effective August 1, just 10 or 12 days ago. We did have an increase in our U.S. dollar-denominated ceiling price by about 6%, up to over USD 10 per MMBtu. But because of this appreciation that we benefited from through the first half of the year, the local currency-denominated price stayed pretty consistent at reais $1.94 per cubic meter. The net effect using the July closing FX rate was USD 11 -- just over USD 11 per Mcf. If we look at this going forward, so the red dash line to the right of that, what we're doing is we're forecasting the prices going forward based on the strip pricing on August 10. So these are the market forward prices for each of the benchmark prices. You can see the NBP prices actually off the graph, to the north or -- to the top, in the near-term portion. The net effect of that is if you calculate using the formula, you get this dark blue line. And as we've talked about before, because of our ceiling, obviously, our price would match the ceiling. And what's changed from the last time we looked at this is this gap has widened quite a bit and it's also extended. So we now are forecasting based on these prices that we would be at the ceiling all the way through the 2027 period that you see on this graph. And what this really means is that commodity prices have the ability to be actually quite a bit lower than these forecast prices before we would realize any reduction in our realized gas price. So it really does highlight the hedgey nature of our gas sales agreement.

So this chart here shows our operating netback, which is the height of the green bar that you see there. And that's our profitability per barrel of oil equivalent. So we start at the top there, is our realized sales price. So Q2 was just over $73 over $11 higher than Q1 now that we had 3, 4 months at that ceiling price that Corey was just talking about. And then we reduce that by royalties you see in orange and then production expenses in gray. And we had a record netback for Alvopetro in Q2 of almost $64, over $10 higher than Q1. And that line you see at the top there is our netback margin, and that's our operating netback compared to our actual price in the period. And we would say that Alvopetro has best-in-class operating netback margin. This year-to-date is 87%, and last year, average 82% or 83%. And if we look at the next slide here, this compares our netback margin to other publicly traded oil and gas companies that have released and are operating in Latin America or Canada. And Alvopetro at 87% is close to 30% higher than the average of 68%. So that just shows the profitability of our production. And with that profitable production, our funds flow improved $1.5 million in Q2. So despite that 6% drop in production, with that shutdown -- that planned shutdown in May, our overall fund flow again, also record funds flow for Alvopetro of $12.4 million. From a net income perspective, we did see a decrease. If you recall, we talked about this on prior calls. We are subject to some foreign exchange fluctuations that are noncash in nature, largely on our intercompany amounts, because under IFRS, we are required to reflect the foreign exchange gains or losses that our subsidiary has on amounts that we've lent them even though the balances don't show up on the consolidation. So it's a bit of an accounting adjustment, noncash in nature. Because we had a $5 million foreign exchange gain in Q1 and a $3 million loss in Q2, that's a swing of $8 million on our net income, partially offset by lower deferred tax. But overall, our net income was $6.6 million, which was $4.5 million lower than Q1. From a working capital and overall financial resources position, we're still very, very strong with these record quarter we had here. Working capital, which is current assets less current liabilities, that's the green bar that we show there, $11.6 million as of June 30, with cash, which is the black line, of close to $14 million. Our credit facility is that orange line. And we repaid another $2.5 million in the quarter, so our balance outstanding is actually $2.5 million, which is well under one month of cash flow. And if you look at the side of that green bar relative to the orange line, the difference there is what we call our working capital net of debt, and that increased to $9.1 million. So our working capital exceeded our credit facility by $9.1 million, which was an improvement of $1.8 million compared to March 31.

All right. Thank you. So like Alison said, our second quarter was our strongest quarter yet in terms of funds flow from operations, up to $12.4 million. You can see that on the line on the graph on the top left here. That was a 14% increase quarter-over-quarter and 127% increase from the funds that we generated in the second quarter of last year. This graph on the upper left is meant to just show how we're allocating that cash flow out pursuant to our capital allocation model. You can see, in the first year of our project coming on stream, the vast majority of this was allocated to repaying debt and paying interest, which is in the orange bars. We did that in a very accelerated fashion. There was a small amount of investing in capital projects happening, which is in yellow. But based on the strength of our results, we did initiate our dividend program about 6 months ahead of schedule. You can see that in the green bars there. We started that in the third quarter of last year at a level of USD 0.06 per share. We did increase that by 1/3 in the first quarter of this year, coincident with the gas price increase that I reviewed earlier. And then the other thing to note here is you can see that we've been investing more in earnest here starting in the first and second quarters of this year with a more balanced approach, and obviously, complementing our strong results with reinvestment in organic growth that you see in yellow. So we've now got 2 full years of operations under our belt. And you can see, in those 2 years, we've had fund flow from operations of close to $56 million. Just under 1/3 of that's been reinvested, a little under 30% of it has been dedicated towards accelerated debt repayments and interests, a little under 20% to dividends. And at the same time, as Alison noted, we've built financial resources over that time by over $9 million. So that takes us over to our organic growth plan. To reiterate, our near-term goal is to get to 18 million cubic feet a day, with a longer-term vision to basically double that up to 35 million cubic feet a day. It's a 3-pronged approach, starting with our core assets, our Caburé unit and our midstream infrastructure. I'll show you what this looks like. But the gas plant expansion that we've talked about was completed in July. And we've got some growth at the unit that we're underway with the Unit C drilling. It's a combination of development and exploration that I'll review. We had a 2-well exploration program this year. We're very excited about the results. I'll review those, but we're off to a great start. And then we've got our Murucututu Gomo project, where GLJ, our independent reserve evaluator, has assigned a combination of 2P reserves. And contingent and prospective resource, we've got a multiyear development plan here, and I'll review our progress. So just talking about the unit. Obviously, it's been performing very well. Along with our partner here, we did increase the gross production plateau capacity that we had originally agreed to by 1/3, up to over 21 million cubic feet a day. As a recap, the vast majority of the production to date has been coming from the east side of this main bounding fault. You can see it on the seismic shift section on the bottom right here. There are 6 wells. You can see it on the cross sections. So the vast majority of the production comes from this Caburé [indiscernible] on the east side of the fault. When our partner is dispatching gas, this well on the west side of the fault also produces from the shallow Pojuca sands. So of note, we're currently drilling with our partner, the Unit C Well, targeting not only a development upside in the Pajuca and these deeper sands that were encountered in that original well. But more notably or most notably, it's an exploration target, targeting the same Caruacu sands that we produce from on the eastern side of the main bounding fault in this western down throne location. So with success here, we're hopeful that we can expand the unit production capacity even further. And we would expect to have results announced from this hopefully later this month. On our gas plant expansion, like we said, that's complete. The capacity is now 0.5 million cubic meters a day, which is 18 million cubic feet a day. The project consisted of adding a fourth compressor that you can see right here, Joel Thompson valve at the inlet to the cold separator that you can see right here and then also a vapor recovery unit that you see right here. So at the end of the day, the project not only results in the higher capacity that we've talked about, but it further stabilizes the condensate, results in better condensate yields. It minimizes our flaring. And we're better equipped to handle richer gas like the gas that we're going to be producing from our Gomo Murucututu project. Moving on to the conventional exploration. The 182-C1 well, we talked about this on our last call, but just to recap, because we're in the middle of testing it right now. This was a well that encountered a nice 30. So this log on the left-hand side here, the yellow highlights where we've got sands within the Agua Grande formation. And there's 36 meters of gross sand here. Of that 36 meters, and you can see this on the red pay flags on the right-hand side, 25 meters of that means our net pay cutoff. So 6% porosity, 50% water saturation and 50% B shale. We've perforated pretty much this whole section, and we expect to announce results again also this month. In addition, once that's done, we plan -- we're doing the completion actually with the drilling rig. Once that's done, we're going to move the drilling rig about 6 meters over and we're going to drill a well further to the east from the same location. So it might be hard to see my cursor. But it's mostly east and a tiny bit north is the bottom hole location. And the objective of that is kind of threefold. First of all, that will help us define the aerial extent of the Agua Grande. It will help define the reservoir quality further away from the main bounding fault because we're quite close here. And then the third thing is -- because what happened is as soon as we drill through -- virtually as soon as we drill through the Agua Grande formation, we ended up crossing the main bounding fault. So we didn't end up drilling through the Sergi formation, which was the second target in this formation. And in that more easterly location, we fully expect to still encounter that, and we'll talk about the Sergi a little bit on the second well that we drilled, which is our 183-B1 location. We just recently announced results from this. We're very excited about it based on logs as well as fluid samples that we collected but -- during that process. We've got a multi-zone discovery here, it looks like, over 3 different formations. We've assigned 34 meters of potential net pay based on that. We're organizing to start the formation testing here in September. And just to walk you through what we've got. Starting from the bottom, this is the Sergi formation. So again, the yellow highlights the sands within here. It's about a 78-meter gross section. For reference, the Sergi is typically about 220 meters. So we didn't actually, we stopped because we scrapped the bit and our rates of penetration dropped, and we look like we had a pretty good well. But our next wells would drill deeper, and we would fully expect to encounter the full Sergi formation here. Of the 78 meters, you can see again with the red pay flags that we've got here, we've assigned 17.5 meters of potential oil pay. Where the little black arrow sits right here, we actually recovered light oil from that, which is encouraging. And then the last thing to talk about in the Sergi is all this red cross hatching that you see here is -- denotes areas where we had bad hole or wellbore washouts. So it makes it difficult to rely on the log analysis. But while drilling it looked obviously very similar to everything else and we think we have possible additional net pay in all these red cross at sections, that we will be able to validate through the testing operation. If we move up hole. This next section that you see here is the Agua Grande. Same formation that we talked about in the last well. Of that, 11.4 meters of it meets our net pay thresholds. Again, this black arrow here shows where we tested gas from this. The other thing to note is that we've got a very nice looking section at the top of this. So there's about 3 meters of the net pay here that has average porosity, around 17%. It obviously peaks at higher than that. And what that's indicative of is that this is a [ oleinpases ] that has typically very good permeability, and you can see the porosity here. So we're optimistic about that. And then the third thing is a bit of a bonus here, this certainly wasn't envisioned in our resource report that we did in advance of this. But we've got this very nice-looking Candeias sand. It's 5.4 meters or 5.3 meters of net pay here. And again, very good porosity, averaging almost 16%. And with the little black arrow, again, we did recover light oil from this as well. So we're really excited about this and hopefully get started testing this in early September. Moving on to our Murucututu Gomo project. The key here initially was getting all our production facilities in place. You can see a picture of that in the center. We're in the commissioning phase. We're just waiting for an inspection from the A&P to approve the fiscalization system. And then we'll be in a position to turn the 183(1) on production. And then at the same time here, we're constructing the flow line from the 197{1 well and pad to tie that back into this facility at 183(1). And you can see a picture of that on the right-hand side. that's going quite well. We're over 65% complete on that project. And then once all that's in place, we've obviously turned all those wells on. And then we'd be in a position to start a multiyear development drilling program. Obviously, with the success we've had on the conventional exploration side, we are planning some follow-up there. So the timing of the drilling of those wells is looking more like the very early part of 2023. One of the other things we announced just last week is our inaugural sustainability report. We all [indiscernible] a copy of that. And the report really highlights our accomplishments and our focus on growing a strong and sustainable business, but it also creates visibility on our approach to ESG. We've talked about this. But our commitment certainly to social and environmental responsibility goes well beyond what's required by Brazil's already stringent regulatory requirements. I would say, our approach, it really focuses on trying to minimize our impact. Our team pays special attention to preventing erosion and preserving biodiversity. A good example that, just last year was the construction of our 8-kilometer Murucututu pipeline. We designed that in a way that 90% of it followed either existing right of ways or use directional boring, so horizontal directional boring to minimize our impact. We were able to spare -- we had 65% fewer trees and vegetation impact than what we were permitted for, and we're pretty proud of that. We did finish our Scope 1 and Scope 2 emissions intensity as part of the project. 4.7 kilograms of CO2 equivalent per BOE is certainly top decile. That's about 4 times less than what a typical or average U.S. producer would be. From a consumption perspective, obviously, burning natural gas relative to fuel oil has another over 50% reduction in greenhouse gas emissions. And lastly, we don't produce a lot of water. But any water that we do produce now or in the future, it all gets reinjected. From a safety perspective, we've had 2 years of operations now, 0 lost time incidents. And from a community perspective, we have allocated $0.20 per barrel of oil equivalent produced to invest in voluntary social programs. And the report highlights the first 2 of those programs. And lastly, on the governance side of things. We've always had a high standard of corporate governance. We inherited it from our predecessor company, Petrominerales. It's based off our value system that governs all of our interactions. So in conclusion, I certainly think Alvopetro continues to offer maybe more than ever a very attractive investment proposition, no matter what your investing focus is. From a results perspective, obviously, we continue to deliver ahead of initial expectations. Q2 was another record quarter for us. July another very solid month of production. Attractive gas prices, leading operating margins or profitability per unit produced. We've got a strong balance sheet, great free cash flow generation capacity that really helps underpin our much more balanced reinvestment -- sorry, reinvestment and stakeholder return model. For value investors, we're trading at under 60% of our 2P net asset value. And that's before taking into account these recent exploration results and before taking into account the full Deep Basin Gomo potential that we have. We're trading at about 3.5x annualized funds flow. For yield investors, we're delivering just under a 6% yield right now, with quarterly dividends paid in U.S. dollars. And for growth investors, obviously, I think we've got a very exciting capital program this year, some exciting early results that we'll be able to define more here in the very near future. So there's a lot of near-term catalysts, especially when you consider the quantum of those relative to our market capitalization. So with that, we're going to turn it over to the Q&A. I see people have already started to log those in. [Operator Instructions] And I'm just going to stop sharing the presentation so that we can see us a little bit better.

Okay. Perfect. We'll start off with some questions on plant expansion. How quickly can processing operations ramp up to 18 million cubic feet per day? And do we expect to see production at those levels in the near term? Or does it require 183(1) and 197(1) to come online?

Yes. So there's still a little bit of fine-tuning that's happening at the plant. When you see our August numbers, which we'll announce in early September, you'll get a sense for where we've been producing. But we're ramping the plant up towards the full capacity. We have been producing kind of ahead of where we've been, which is great, will let us get the whole month complete. But like I said, the main thing that's going to impact the production in the near term is just -- to the extent our partner is obviously dispatching and taking their share of unit production, the available production for us can fluctuate. So that's one impact. The Gomo project or Murucututu project, those wells, because we have the facilities in place or will soon have the facilities in place, we do have the ability to add production from those as the projects get completed. With respect to the exploration wells that we just drilled, the expectation, we're in the final phases of getting the permit application for the pipeline done. There's an approval process associated with that, and then a construction timing. So I don't think -- I think from an expectation perspective for additions from those discoveries, to the extent they're natural gas, those will be tied in more in the second half of next year.

So with production capacity at the unit still above processing capacity of the plant, even with the expansion, are there other small processing plant expansion possibilities?

Yes. There is a -- so without getting into too much complexity, there are some facility constraints. There's a high-pressure and low-pressure separation stream. Our gas gets processed through the high-pressure separation. So we technically couldn't take the full 600,000 cubic meters from the unit with the way it's structured.

Okay. Does the next processing plant expansion and movement towards 35 million per day depend on successful expansion into the 182(1) and 183-B1 field?

Yes. So we're just looking to get the testing results from these 2 wells, get our initial couple of wells on at the Gomo and partly -- part of it is not just expanding the plant from a volume perspective. What you need to do is you need to look at the gas composition of all the different projects, how much production do you think will contribute from each one to properly design that expansion. So we're pretty close to that decision point, but I think we'll be in a better position closer to the end of the year.

Okay. It seems that you found gas and oil on the 183-B1 well. Does this make testing more complicated? Or can you test all zones?

Yes. The decision tree is certainly a little bit more complicated. Obviously, the Sergi is very prolific throughout the entire basin. So we're really excited about the lower part of the well that I reviewed there. Frankly, if we have a very good oil result in there, we'll have to stack that up against all of our other projects. But that's something we could bring on production and cash flow relatively quickly, and obviously would also be a focus for us. So yes, we can test everything. But depending on the results, the decision tree going forward evolves.

And then does that change your strategy on focusing on natural gas?

No. I think to me, it's just additive. Like our -- we've got some highly strategic infrastructure in the basin. We've expanded it. The key objective, make sure that that's full day in, day out. We've got lots of projects, I think, to do that. But if we can add a leg of profitable oil production to that to complement it, then that's excellent for our stakeholders.

And if you test oil, can you keep producing?

Yes. So the way that works is, the formation testing regime that I think our shareholders have been used to in some of our past wells, for each of the different zones that we would test, we would have 72 hours to test those. And then we would make an application to do a long duration test, which would take at most, call it, 60 days. And then we would be in a position to put the well on a long duration test, which could go up to 6 months. And in parallel, we'd be working to declare commerciality and be in a position that we could continue production. Obviously, there's a lot of work that has to be done. The other thing we need to consider is that our plan, just like at 182, to drill a follow-up, we're fully expecting to drill a follow-up location of the 183-B1 pad as well. So we just -- it's not the biggest pad in the world. So we just have to be thinking about simultaneous operations and the timing of that. But with a good oil success, I think we can have that on production this year.