Q4 2022 Alvopetro Energy Ltd Earnings Call
Speaker 1: 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 spit out our gas sales price, which is the dark black line that you see here.
Speaker 1: moving forward you can see it's really limited by the ceiling in our contract. What we've also done is add this black dashed 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.
Speaker 1: by over two-thirds. So this really highlights the kind of hedgy nature of our gas sales agreement and the much lower volatility that we see.
Speaker 2: In the last month, we've updated our reserves and our Contingent Perspective Resource reports associated with our Mercututu asset and our other assets using GLTA as our reserve evaluators. I'll just go through some of the highlights of that report.
Speaker 2: So from a valuation perspective, our before tax and after tax valuation increased by 17% and 15% respectively.
Speaker 2: 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 Merica 2-2 asset here.
Speaker 2: The
Speaker 2: The current reserve life index for our assets are 9.7 years. And Alpapetra continues to focus on de-risking and unlocking the potential of the Merkle 2-2 contingent and prospective resource reports. You know, the valuations of these are highlighted in reports, so we look forward to those assets.
Speaker 1: 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 dashed line is our current enterprise value. What you see there is that we're trading at just below our 1P NPV basically.
Speaker 1: 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 albopetro today when you look at the potential additional value that we can realize from both our 2P reserves, our costs are possible.
Speaker 3: agreement, this chart here is operating that back which is shown in the height of those green bars which is our profitability per barrel of oil 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 increase in oil production.
Speaker 3: in the quarter and that just shows kind of the strength of this 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 net back as a percentage of our realized sales price in.
Speaker 3: is pretty remarkable we would say. Overall in 2022 it's 87% and our overall net back in 2022 on a year to date basis was over $59.
Speaker 3: 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 yeah, our operating netback is 88% or our netback margin is 88% in Q4 compared to an average.
Speaker 3: know with the strength of our you know very we have a very low tax rate in Brazil with a tax incentive that we are eligible for you know again it's just highlights how great it is to be operating in Brazil from the fiscal regime
Speaker 3: So, moving on, this is our fund flow, so just that builds off of that chart and how profitable our production is. Our fund flow for 2022 was a record year for elbow petrol at just under.
Speaker 3: 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 a $50 million fund slope.
Speaker 3: And if you compare that to, you know, we had revenues of just under $64 million, to have funds flow, you know, after G&A, after tax of $50 million is pretty impressive, that's 79% of our revenue. So that was pretty remarkable.
Speaker 3: Q4 funds flow was pretty much consistent with Q3. We did see a slight increase in our sales volume and that was mostly offset by some increased GNA and current tax just with finalization of year-end.
Speaker 3: Similar to funds flow net income, which also incorporates various non-cash items, but with that increase in funds flow from operations, again, we had record net income at Albo Petro in 2022.
Speaker 3: 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.
Speaker 3: mostly accounting for exchange gains and losses on intercompany amounts, so all non-cash 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 net income on that revenue basis.
Speaker 3: So yeah, with those strong funds low, we ended the year with working capital of $14.7 million. 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.
Speaker 1: The yield now represents over 11%. Since inception of the dividend, you can see we've already returned or will have already returned $0.62 USD to shareholders. That totals US$22M. In addition, we have announced an intention to tweak our normal core.
Speaker 1: Next, I just want to talk about our balanced capital allocation model where we're, you know, this is something that we introduced years ago, long before, frankly, even our cabaret project that came on production. And the model was to roughly reinvest half of our cash flows in the business and in organic.
Speaker 1: scores here to finish out 2022. They both had, sorry, are average for 2022 as well as our average for Q4. Both represent over 100% increases over the prior year comparative periods that's out so highlighted.
Speaker 1: The bars that you see below this, it just showed 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 crosshatch bars that you see here.
Speaker 1: 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, you know, in 2022 is the first time where we really started to see that.
Speaker 1: stakeholders a little over a third to capital expenditures and 15% has gone to building that cash and working capital position that Allison showed you earlier up to almost 15 million dollars as of the end of the year and that certainly gives us a lot of flexibility as we move forward.
Speaker 1: 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 are...
Speaker 1: the unit facilities.
Speaker 1: Probably the most significant part is our Merica 2-2 asset. Adrian showed the addition of a couple of additional locations into our reserves.
Speaker 1: GLJ has assigned a combination of 2P reserves, contingent and prospective resource, and we're now in a position that we can start a multi-year development plan and really look to migrate that into production, cash flow and reserves. I'll get Adrian in a moment to walk you through in a little bit more detail what that plan looks like. On our bone laguerre mature oil field.
Speaker 1: the challenge is, you know, when we tested them the permeability certainly seems lower than what we would have expected based on the porosity of logs. 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.
Speaker 2: Earth map here shows the two initial wells, one in the 31 and one in the 71 that we entered into this.
Speaker 2: we drilled to
Speaker 2: initially discovered the gas project here and we followed that up with the discovery of our Kura-Su conventional production at Cabaret. At 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.
Speaker 4: level one here.
Speaker 2: So then in 2022, we continue to focus on that exploitation of this type gas project. So we built that additional pipeline to the north from.
Speaker 2: from the unit from Cabaret to 183.1. We built an additional flow line to 197.1 and we built a facility at 183.1 to take our production, three phase separation so we can manage any liquids production, condensate production.
Speaker 2: position ourselves, leverage the existing infrastructure, position ourselves for the first phase of field development here at Morook Atootoo.
Speaker 2: Today, we're currently, you know, we've got ongoing work at 197 to do our first multi-stage stimulation here at that well bore we drove a long time ago. And we're really excited about this project. You know, this is a huge milestone for Alopec. She'll be able to do this.
Speaker 2: multi-stage 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 .
Speaker 2: So, in the future, you know, we've got, as we noted before, we've got this contingent resource, this contingent.
Speaker 2: of prospective resource and reserves associated with Merk atutu. In 2023, we're going to drill up to two development wells, 183A2 in this 183D1 area.
Speaker 2: move with the potential to continue to drill in 2024 and de-risk the production potential of 20 million centi-feet a day of this asset alone.
Speaker 1: All right, thank you. So in summary, again, I continue to think Elvipetro 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.
Speaker 1: 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 Allison noted. We've got best in class operating margins.
Speaker 1: We've got a clean balance sheet and extremely strong free cash flow generation capacity that 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 1 pnPV, about half of our 2 pnPVs.
Speaker 1: and just over three times annualized funds from operations.
Speaker 1: yield investors, we offer over 11% dividend yield right now with quarterly dividends paid in US 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...
Speaker 3: the middle of right now. So with that I think we'll turn it over to the question and answer period. 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
Speaker 3: 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 so we've just written off the cost of that one the C1 well in the period
Speaker 3: Going forward, Corey touched on this, we do have some engineering work that we're doing on 183B and 182C2 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.
Speaker 3: 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
Speaker 2: Yeah, like I noted before, the objective is to have this thing online, producing to our UPGN by the end of April . So, equipment is on location and we're imminent to start the actual simulation.
Speaker 3: Perfect. Staying on America 2-2, you're drilling these development wells. How is that different than the existing wells? You mentioned the concept of fit-for-purpose wells. What does that entail exactly?
Speaker 2: Yeah, so when we drilled those initial exploration wells, you know, they were cased with 7 inch casing and we went through a testing program and test a number of uphole zones for hydrocarbon potential and the fit for purpose idea we wouldn't do any of that because that makes it very difficult to do these simulations.
Speaker 2: And we would also case them in 5.5 inch casings so that we can stimulate found casing and that provides a lot more flexibility to these completions that we're planning. And the other addition that makes it a bit for purposes, we're incorporating a sliding sleeve technology to make the multi-stage vertical stimulation a lot more effective.
Speaker 2: so that we can stimulate found casing and that provides a lot more flexibility to these completions that we're planning. And the other addition that makes it a bit for purposes, we're incorporating a sliding sleeve technology to make the quality stage vertical stimulation a lot more effective and realizable. Clinical
Speaker 3: Perfect. In the year-end estimates of contingent and perspective resources are accurate, how much of these would potentially shift to 2P reserves if the 2023 Capital Expenditure Plans for America 2-2 and BOMB
Speaker 1: 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.
Speaker 1: And then, you know, I think, at least some of the perspective 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 assets to the north.
Speaker 3: When do you see the next material increase from the exploration wells or from the development locations? Why do you see the next material increase from the development locations or from the
Speaker 1: Yeah, so I think that the drilling.
Speaker 1: To focus on the Bologarre property first, the drilling there is expected to commence sometime in April here. So we would have that well drilled within.
Speaker 1: 40 to within the next two 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.
Speaker 1: From a gas perspective, as Adrienne noted, the 197.1 well would come on here by the end of April and then the result is the wells, the other two wells that we would drill, that production would be added later this year.
Speaker 1: Keeping in mind that from a gas perspective that all gets kind of managed together with cabaret and through the UPGN. So, in the near term, we've probably got 18 million a day of capacity at the plant. It's possible that could be higher, but...
Speaker 1: you know as we get information from the America 2-2 project then we can make decisions on you know do we want to make other modifications to the plant to accommodate even higher production levels so you know that's something we're probably talking about later this year. So speaking of production we do have a couple of
Speaker 2: But as Corey noted, we're facility limited at this point to 18 million centicubic feet a day at the UPG end. So depending on how the results turn out, we'll be discussing making facility modifications.
Speaker 3: to adjust the plateau. Do you have an exit target for production in 2023?
Speaker 1: Well, no more than what we've kind of put in our plan. I think
Speaker 1: You know, we've got this near term objective of 18M cubic feet equivalent per day. I think we're closing in on that and then.
Speaker 1: Yeah, some of the facility side of things, you know, to get to our 35 million cubic feet a day goal, you can see us how the Merck 2-2 asset will layer in based on that chart that Adrian showed earlier. So that gives you a sense and in parallel, we would be doing the facility modifications.
Speaker 3: Are they putting in any roadblocks on the onshore industry that could impact elbow petro?
Speaker 1: So yeah, I know that was announced. It's a four-month measure. I think there's a regulation or a legal that are allowed to do that. But then if it lasts for basically more than that period of time, it needs to be voted on and converted into law. So it remains to be seen whether that will be
Speaker 1: palling 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 1st. We do have a couple of questions on the automatic.
conditions and you know there's questions around the fact that you know albopetro is fairly thinly traded and the impact that this could have and how we will monitor that.
Yeah, so a couple 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. You know, one thing that we probably won't be doing is you know, selectively talking to people about what our trading parameters are, or all those things, because I think that's just
you know, not appropriate. From a budget perspective to touch maybe based on the first question, you know, we're gonna manage this in the context of our stakeholder return model, where 50% of the, you know, 50% of the cash flows roughly are going to stakeholders. So.
you know, really what the board will be doing is looking at the budget for MCIBs versus 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.
Yeah, you know, the permitting processes are run by, for the most part for us, by the local environmental regulator in the state of Ahia, which is ANEMA. You know, other than that 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 Ahia.
So the first question, once we are past the August 1st gas price reset,
With lower gas prices, NDP and Henry Hub, which are expected to be seen through multiple prices, will we not see a lower gas price under our gas sales agreement and how are we preparing for that?
Yeah, 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 dashed line to basically answer that question. So that represents
If you assume the forward script prices as of today are more reflective, then that would be the expectation. So you still wouldn't see any sort of gas price reduction until basically the end of 2024. It's quite modest, just barely under our ceiling.
I think that's one of the things that makes albopetrope so attractive.
So given the lower, well if there are
investing in topics and dividends may be challenging. Why would you increase your dividend now?
Yeah, 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 two 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 yeah, no, we think it's a proving level and like I said, we're much more partly because of the kind of heady 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 US natural gas producer.
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 Canadian heavy oil producer or a Canadian or US natural gas producer.
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 in if Corey wants to comment, he can. So we actually had total capex of just under $25 million in
about four million which was was development in nature and not capital. We did have about two million in spending on cabaret. 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...
of our cabaret project being fully developed in advance. Like there's all the production facilities are there, there's eight wells, it's quite well delineated and the cap 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.
the 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, approved, developed, producing asset value, NPV10. So, that is included in our AIF, which was just released yesterday. It can be found on our website or on CDER.
I do not think we do. I think that is it. Unless there's any final comments, sorry or Adrian wanted to.
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 into the next call in May. If you have any questions in the interim, as always, feel free to call us and we look forward to your calls. Thank you.