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

I may need to start again. Sorry. So good morning, and thank you for joining us for our Q4 earnings results webcast. I'm Corey Ruttan, President and CEO. And I'm joined by Alison Howard, our Chief Financial Officer; and Adrian Audet, our Vice President, Asset Management.

Good morning, everyone. Just a couple of administrative points. We are recording this webcast today, and a replay will be available later on today after this call on our website. All attendees are in listening only more for the duration of the webcast. But if you have a question, we will be doing a Q&A session at the end of the call. And so you can log your questions right away here, using a Q&A portal through Zoom. If you are calling in, please send your questions to [email protected]. Lastly, just encourage everyone to review the cautionary statements on our website. There's a -- in our corporate presentation that just goes through a lot of details on non-GAAP measures, et cetera. So we won't go through those in detail here, but review them at your leisure when you get a chance.

Thank you, Alison. So really, if you look at our results from 2022, it really was a banner year for Alvopetro. Since starting production in July of 2020, we've really been delivering some strong production results. 2022 was a new record year for us at 20 -- sorry, 2,557 barrels of oil equivalent per day of production, that was up 8% over the prior year. If you look at our Q4 results, we produced 2,724 barrels of oil equivalent per day, which was up 3% over the third quarter and up 12% from Q4 last year. And then you can see again in January and February, we had successively strong months there. February was another record month for us at 2,866 barrels of oil equivalent per day. And I think that should set the stage for what should be another strong quarter for us in the first quarter of this year. So this is a chart we like to show on these quarterly calls. It just kind of walks through how our gas sales agreement works. Just as a reminder, our price gets reset semiannually on February 1 and August 1 of each year. The 3 different dash gray lines that you see here are the 3 benchmark prices that are used in our pricing formula. So the lower one is U.S. Henry Hub, this middle one is Brent oil equivalent prices and the upper one is UK NBP gas prices. So left of this red dash line is the historical pricing. And on the right side is the forecast that were used in our reserve report, which are based on our independent reserve evaluator, GLJ's price forecast as of the end of the year. So in addition, we have a floor and a ceiling. They're the red and the green lines that you see here. Those do get escalated based on U.S. inflation and the assumptions that were used in our reserves were 3% inflation for this year and 2% thereafter. So arguably, maybe a bit on the conservative side. The net effect is you blend these over a period of time and you spin out our gas sales price, which is the dark black line that you see here. Moving forward, you can see it's really limited by the ceiling in our contract. What we've also done is add this black dash line. And what that represents is, if we were to redo these price forecasts based on the forward strip pricing that was in effect at the end of the day on yesterday or the day before that's the impact that you would see on our realized price. So a very small impact relative to what our peers would have experienced. I think if you contrast it with a U.S. natural gas producer since Christmas, a U.S. producer, they've seen their price go down by over 2/3. So this really highlights the kind of hedging nature of our gas sales agreement and the much lower volatility that we see.

In the last month, we've updated our reserves and our contingent prospective resource reports associated with our Murucututu asset and our other assets, using GLJ as our reserve evaluators. I'll just go through some of the highlights of that report. So from a valuation perspective, our before tax and after-tax valuation increased by 17% and 15%, respectively. Our 2P production ratio was 132%, meaning that in 2022, we produced just over 900,000 BOE, and we replaced more than this on a 2P basis, mainly associated with additional undeveloped locations at our Murucututu asset here. The current reserve life index for our assets are 9.7 years. And Alvopetro continues to focus on derisking and unlocking the potential of the Murucututu contingent and prospective resource reports. The valuations of these are highlighted and reported. So we look forward to those assets.

Yes. I think the other point to make is, we've just updated the chart on the bottom here. You can see based on our current share price, the black dash line is our current enterprise value. And what you see there is that we're trading at just below our 1P NPVs basically, roughly half of our 2P value. But we'll talk about this at the conclusion from a value perspective. This represents the value proposition of investing in Alvopetro today when you look at the potential additional value that we can realize from both our 2P reserves, our possible reserves as well as the contingent and prospective resource that Adrian talked about there. So I think there's still a lot of opportunity.

So just following on Corey's discussion on the strength of our gas sales price under our gas sales agreement, this chart here is operating that back, which is shown in the height of those green bars, which is our profitability per barrel that we reflected in per barrel of oil equivalent. So starting at the top with our realized price per BOE, Q4, we saw a very slight decrease from Q3. That was just due to the reduction in Brent and the impacts on condensate pricing. Our gas sales price under our gas sales agreement was exactly the same as Q3 at $11.18 per Mcf. But despite that reduction, we did see a $0.25 per BOE increase in our operating netback from Q3. We're over $60 in the quarter, and that just shows kind of the strength of the fiscal regime in Brazil and how profitable this production is, which is shown again in that line on the top. So looking at our operating netback as a percentage of our realized sales price in Q4, that's 88%, which is pretty remarkable, we would say. Overall, in 2022, it's 87% and our overall netback in 2022 on a year-to-date basis is over $59. So just we would say that's best-in-class, and we like to show kind of how that stacks up to other companies operating in Latin America and in North America or in Canada, sorry. So yes, our operating netback is 88% -- or our net back margin is 88% in Q4 compared to an average. We show 8 other producers that have published their Q4 results here, the average there is 65%. So over 35% higher, and this is our net operating income, so before tax. But if we looked at it after tax, with the strength of our very -- we have a very low tax rate in Brazil with a tax incentive that we are eligible for. Again, this just highlights how great it is to be operating in Brazil from the fiscal regime. So moving on, this is our funds flow. So just that builds off of that chart and how profitable our production is. Our funds flow for 2022 was a record year for Alvopetro at just under $50 million which is pretty impressive overall. Our netback, which increased $27 million from the prior year and everything else was relatively flat. So we ended the year at $50 million funds flow. And if you compare that to, we had revenues of just under $64 million to have funds flow after [ G&A ], after tax of $50 million is pretty impressive. That 79% of our revenue. So that was -- it's pretty remarkable. Q4 funds flow was pretty much consistent with Q3. We did see a slight increase in our sales volumes, and that was mostly offset by some increased G&A and current tax just with finalization of year-end. Similar to funds flow, net income, which also incorporates various noncash items but with that, increase in funds flow from operations. Again, we had record net income at Alvopetro in 2022. So the main impacts there were the net operating income was significantly higher than 2021 with the higher sales volumes and realized prices. We did have some foreign exchange gains. We talked about that in prior period. The gains were higher than in 2021. It's mostly accounting foreign exchange gains and losses on intercompany amount. So all noncash related. The big impact going the other way was we did recognize an impairment in Q4 of $6.3 million. But again, $31.7 million of net income on that revenue basis is pretty impressive. For the quarter, we did see a bit of a decrease from Q3. Again, the main driver for that was that impairment charge that we recognized on one particular well in our E&E assets. So yes, with that -- those strong funds flow, we ended the year with working capital of $14.7 million. You remember recall that our credit facility is fully repaid as of Q3, and now we have cash and working capital of $14.7 million. So we've seen a steady increase in that since coming on production, and now we're debt free, which is great.

All right. Thank you. So happy to announce that we've now increased our dividend for a third time since introduction of this and since, frankly, the first increase that we did in Q1 of last year. The yield now represents over 11%. Since inception of the dividend, you can see we've already returned or will have already returned USD 0.62 to shareholders that totals USD 22 million. In addition, we have announced an intention to tweak our normal course issuer bid that we announced earlier to an automatic share purchase plan that allows us to purchase shares also in routine blackout periods through instructions to our broker. Next, I just want to talk about our balanced capital allocation model where we're -- this is something that we introduced years ago, long before frankly, even our Caburé project came on production and the model was to roughly reinvest half of our cash flows in the business and inorganic growth and return the other half to stakeholders. So this is kind of how this all looks. The chart on the left-hand side here, the lines and the dots just plot our funds flow from operations over time. You can see we had 2 successive -- our best quarters here to finish out 2022. They both had -- sorry, our average for 2022 as well as our average for Q4, both represent over 100% increases over the prior year comparative periods, as Alison highlighted. The bars that you see below this is just show where we put the capital basically. So if you look at the first year of coming on production, the huge majority of the cash outflows went to repaying our credit facility on an accelerated basis. So that's the green cross hash bars that you see here. Then in the third quarter of 2021, we introduced the dividend, which is in the dark green. We also did a share restructuring in that quarter, which is the lighter solid green color, and we repurchased a bunch of our shares. And then just -- in 2022 is the first time where we really started to see the reinvestment in our business in the yellow bars that you see down here. So that's how it's looked quarter-over-quarter. In total since coming on production, in July through to the end of the year, you can see how this looks. Almost exactly half has gone to stakeholders, a little over 1/3 to capital expenditures and 15% has gone to building that cash and working capital position that Alison showed you earlier, up to almost $15 million as of the end of the year, and that certainly gives us a lot of flexibility as we move forward. So just focusing in on our organic growth plan, we've had a near-term goal of achieving 18 million cubic feet equivalent per day. We're actually closing in on that now, and we've got a longer-term vision to basically double that. The growth plan to come from a number of areas. You can see, first, our core operating area with Caburé and our midstream assets. We did complete the gas plant expansion in the middle part of last year, up to 18 million cubic feet a day. And then this year, along with our partner, we're looking at drilling a couple of additional development wells and expanding the unit facilities. Probably the most significant part is our Murucututu asset, Adrian showed the addition of a couple of additional locations into our reserves. GLJ has assigned a combination of 2P reserves, contingent and prospective resource. And we're now in a position that we can start a multiyear development plan and really look to migrate that into production, cash flow and reserves. And I'll get Adrian in a moment to walk you through in a little bit more detail what that plan looks like. On our Bom Lugar mature oilfield, we do have 2 -- up to 2 development locations on this field targeting the Caruaçu Formation as well as some potential and some deeper formations here. And then lastly, on the exploration side, we did drill 2 exploration prospects last year. The good news is the tracks work, we encounter big hydrocarbon columns. The challenge is when we tested them the permeability certainly seems lower than what we would have expected based on the porosity on log. So we're going to do a bunch of engineering work this year to evaluate alternatives to enhance that, probably low from a capital spending perspective, but high from a sweat equity perspective to really try to unlock those discoveries.

I'm just going to walk you through the genesis of Murucututu and Caburé and how we got to where we are today. The Google Earth map here shows the 2 initial wells, 183(1) and 197(1) that we entered into this -- we drilled to -- initially discovered the gas project here, and we followed that up with the discovery of our Caruaçu conventional reaction at Caburé, which period of time we developed the infrastructure, we signed our long-term gas sales agreement that Corey went over earlier. And this really positioned ourselves to capture any additional natural gas potential. So by the end of 2021, we had stable production from Caburé here to our UPGN at the Bahia Gas City Gate, and we were ready to move our exploitation focus to the tighter gas potential in 183 and 197(1) here. So then in 2022, we continue to focus on that exploitation of this tight gas project. So we built that additional pipeline to the north from the unit -- from Caburé to 183(1). We built an additional flow line to 197(1). And we built a facility at 183(1) to take our production, have 3-phase separations, so we can manage any liquids production, condensate production and position ourselves, leverage the existing infrastructure, position ourselves for the first phase of field development here at Murucututu. Today, we're currently -- we've got ongoing work at 197 to do our first multistage stimulation here that well where we drilled a long time ago, and we're really excited about this project. This is a huge milestone for Alvopetro to be able to do this multistage stimulation, tied in the flow lines right at location right now. So we're ready to finish this completion and then our target is to have this thing online by the end of April. So in the future, we've got -- as we noted before, we've got this contingent resource -- this contingent prospective resource and reserves associated with Murucututu. In 2023, we're going to drill up to 2 development wells, 182-A2 and this 183-D1 area, with the potential to continue to drill in 2024 and derisk the production potential of 20 million standard cubic feet a day of this asset alone.

All right. Thank you. So in summary, again, I continue to think Alvopetro offers an extremely attractive investment proposition no matter what your investing focus is. I think, hopefully, you're convinced we've been delivering results certainly ahead of the expectations that we set before this project came on, again, new record production in February this year. We had record cash flow in 2022, and very strong quarters in both Q3 and Q4 to close out the year. I think that puts us on track for another strong quarter in Q1 this year. Obviously, we've got some attractive gas prices, as I also noted. We've got best-in-class operating margins. We've got a clean balance sheet and extremely strong free cash flow generation capacity to help underpin that balanced stakeholder return and organic reinvestment model that we have. For value investors, just to recap, we're currently trading at under our 1P NPV, about half of our 2P NPVs and just over 3x annualized funds flow from operations. For yield investors, we offer over 11% dividend yield right now with quarterly dividends paid in U.S. dollars. And then for growth investors, as I highlighted earlier, I think we certainly have a lot of leverage relative to our current enterprise value with our organically funded capital program that we're in the middle of right now. So with that, I think we'll turn it over to the question-and-answer period.

Okay. Perfect. We have a couple of questions on the impairment charge that was booked in Q4. So I'll start with that. I touched on that briefly. So we drilled 3 exploration wells in the year. The first one was 182-C1. We drilled and tested that well. We ultimately wrote off the cost for that well only. We made the decision to do that. We've made the decision to abandon that well. It was drilled very close to the main bounding fault, and we missed the secondary target. So ultimately, we proceeded with drilling a second prospect into -- a second well into that prospect, the 182-C2 well. So we've just written off the cost of that one, the C1 well in the period. Going forward, Corey touched on this, we do have some engineering work that we're doing on 183-B and 182-C2 going forward. So we will have some additional work there, probably not very extensive in terms of dollars. But as Corey mentioned, in terms of work from the team on sweat equity. So hopefully, that answers that question. The next question was this -- the 197(1) well that is you said you've started stimulation. When do we expect that to be on production?

Yes. Like I noted before, the objective is not this thing online producing to our UPGN by the end of April. So equipment's on location and we're imminent to start the actual simulation.

Perfect. And staying on Murucututu, you're drilling these development wells, how is that different than the existing wells, you mentioned the concept of fit-for-purpose well, what does that entail exactly?

Yes. So when we drilled those initial exploration wells, they were [indiscernible] casing, and we went through a testing program and tested a number of uphole zones for hydrocarbon potential. In the fit-for-purpose idea, we wouldn't do any of that because that makes it very difficult to do these stimulations. And we would also case them in 5.5-inch casing so that we can stimulate down casing and that provides a lot more flexibility to these completions that we're planning. And the other addition that makes it a fit-for-purposes, we're incorporating a sliding sleeve technology to make the multistage vertical stimulations a lot more effective and realizable.

Perfect. In the year-end 2022 estimates of contingent and prospective, if the -- sorry, if the year-end estimates of contingent and prospective resources are accurate, how much of these would potentially shift to 2P reserves if the 2023 capital expenditure plans for Murucututu and Bom Lugar were proven successful?

Yes. I think it's hard to predict exactly how GLJ will go about that. But I think you can see what happened this year is just based on our imminent development plans for the asset, we were able to convert 2 of the locations into -- from contingent into reserves, I think, especially as we drill the well to the north of the 183(1) pad. With success there, I think it would in all likelihood open the door to migrating another big chunk or maybe all of the contingent into perspective. And then I think at least some of the prospective area would migrate into contingent and it would be kind of an evolution over a couple years or a few years of time as we develop the asset to the north.

When do you see the next material increase from the exploration wells or from the development locations?

Yes. So I think the drilling -- to focus on the Bom Lugar property first, the drilling there is expected to commence sometime in April here. So we would have that well drilled within 40 to -- within the next 2 months following that. There are some small facility modifications that we do on location, but we'd be able to bring that well on production reasonably quickly thereafter. So sometime in, hopefully, Q3 that production would be added. From a gas perspective, as Adrian noted, the 197(1) well would come on here by the end of April. And then the result -- the wells -- the other 2 wells that we would drill up that production would be added later this year. Keeping in mind that, that from a gas perspective, that all gets kind of managed together with Caburé and through the UPGN. So in the near term, we've got [ 18 million ] a day of capacity at the plant. It's possible that could be higher. But as we get information from the Murucututu project, then we can make decisions on do we want to make other modifications of the plant to accommodate even higher production levels. So that's something we're probably talking about later this year.

So speaking of production, we do have a couple of questions on that. What incremental daily production do you expect from 197(1)?

Yes, I can handle that. The -- well, the estimated production from that specific well for the first year is [ 180 ] BOE per day. But as Corey noted, we're facility limited at this point to 18 million standard cubic feet a day at the UPGN. So depending on how the results turn out, we'll be discussing making facility modifications to adjust the plateau.

Okay. Do you have an exit target for production in 2023?

Well, no more than what we've kind of put in our plan. I think we've got this near-term objective of 18 million cubic feet equivalent per day. I think we're closing in on that. And then yes, some of the facility side of things to get to our 35 million cubic feet a day goal, you can see us how the Murucututu asset will layer in based on that chart that Adrian showed earlier. So that gives you a sense in parallel, we would be doing the facility modifications to accommodate higher production levels. So no, we don't have a public exit target, but that's kind of how we would expect to see production grow over time here.

Okay. So just shifting gears a little bit. There are reports about Brazil putting in an export tax on crude products. Are they putting in any roadblocks on the onshore industry that could impact Alvopetro?

So yes, no, that was announced. It's a 4-month measure. I think there's a regulation or legal -- they are allowed to do that, but then it lasts for basically more than that period of time, it needs to be voted on and convert it into law. So it remains to be seen whether that will be permanent or not. It doesn't impact us, obviously, because we're not exporting oil. And we haven't seen any impediments, if anything, it's been -- you can see based on the slides at Alison showed, we've got a pretty compelling fiscal regime here. And quite frankly, we just recently qualified for a tax incentive on our gas that helped increase our gas price further than what probably the market was expecting when it reset on February 1.

We do have a couple of questions on the automatic share purchase plan that we announced yesterday. So I think I'll just try to combine these a little bit. But do we expect that there will be modest or substantial NCIB purchases based on the current share price and market conditions. And there's questions around the fact that Alvopetro is fairly thinly traded and the impact that this could have and how we will monitor that?

Yes. So a couple of things. I think within the regulations, there's guidelines on not having undue influence in the market. So we'll make sure that we're trying to use best practices to abide by that. One thing that we probably won't be doing is selectively talking to people about what our trading parameters are or all those things because I think that's just not appropriate. From a budget perspective to touch maybe based on the first question, we're going to manage this in the context of our stakeholder return model where 50% of the -- 50% of the cash flows roughly are going to stakeholders. So really, what the Board will be doing is looking at the budget for NCIBs versus dividends or dividend increases and we'll balance those things going forward. So it's tough to predict exactly. I'd like to preserve some flexibility around that as well. And it really is -- it depends on what the market does as well.

Okay. We do have a question on permitting and whether the new regime has made the permitting process easier in Brazil? Or if you have any commentary on that?

Yes. The permitting processes are run by -- for the most part for us by the local environmental regulator in the State of Bahia, which is a [indiscernible] and other than they're busy, they've continued to be quite supportive. And obviously, they're keen to see more activity and more attractively priced gas being produced into the state of Bahia. So overall, between that regulator and the A&P, we've had very positive experiences and we haven't seen a change there.

Okay. We do have a couple of questions that have come through on our social media e-mail that I'll just go through now. So the first question, once we are past the August 1 gas price reset, with lower gas prices, NBP and Henry Hub, which are expected to be seen through multiple prices, will we not see a lower [ GSA ] price under our gas sales agreement and how are we preparing for that?

Yes. So we thankfully anticipated that, that might be a question. So that's why on that graph that I showed right near the beginning of the presentation, we added a thick black dash line to basically answer that question. So that represents -- if you assume the forward strip prices as of today are more reflective then that would be the expectation. So you still wouldn't see a gap -- any sort of gas price reduction until basically the end of 2024, it's quite modest, just barely under our ceilings. So I think that's one of the things that makes Alvopetro so attractive.

So given the lower -- well, if there are lower expected revenues and investing in CapEx and dividends may be challenging, why would you increase your dividend now?

Yes. Well, I think a lot of people could ask why we didn't increase it more given the production levels that we have in Q1 and the gas price we have in Q1. So you can look at it 2 different ways. We're trying to be conservative with that. I think the new level that we've got is very sustainable even if we had lower gas prices or lower production levels, quite frankly. So no, we think it's a prudent level. And like I said, we're much more -- partly because of the kind of hedging nature of our gas sales agreement, but also partly because our operating margins are so much higher than any of our peers, our sensitivity on commodity price decreases are way less than what you would see with a, say, a Canadian heavy oil producer or a Canadian or U.S. natural gas producer.

Okay. Another question here was around total CapEx for 2022. How much was exploration versus maintenance capital for stable, flat production. So I can start that and if Corey wants to comment he can. So we actually had total capital CapEx of just under $25 million in the year, about $18.5 million of that was for exploration projects as well as long lead purchases. And then we had spending at our Murucututu project of about $4 million, which was development in nature and not capital. We did have about $2 million in spending on Caburé. That was for drilling an additional well and some facility expansion. So for the most part, it's kind of development and expansion capital, not really something that we have to do to maintain the current production. Hopefully, that makes sense.

Yes. I think Alvopetro is a little bit different than the normal company that you -- where you think about maintenance capital. Obviously, we still need to be focused on replacing reserves and that. But because of our Caburé project being fully developed and advanced, like there's all the production facilities are there. There's 8 wells. It's quite well delineated and the -- just because the nature of a gas project like that, you've kind of pre-invest all the capital, you build a facility to a production plateau. But frankly, there's excess production capacity above that and then you just produce to the plateau basically. It's different than maybe another company where they're drilling wells and then having immediate production declines and constantly having to kind of be mindful of replacing that.

Perfect. So the other question was just on our PDP, Proved Developed Producing asset value NPV10. So that is included in our AIF, which was just released yesterday, can be found on our website or on SEDAR. The NPV10 of the Proved Developed Producing assets is $147 million. But if you have any other questions, specifically on that, feel free to reach out to us. Just going to double check quickly here to see if we have any other questions. I do not think we do. I think that is it, unless there's any final comments for you or Adrian wanted to.

No, I just want to thank everyone again for attending today. And I also want to thank you for your support and look forward to updating you on this call, in the next call in May. And if you've got any questions in the interim, as always, feel free to call us, and we look forward to your calls. Thank you.