Q4 2022 Alvopetro Energy Ltd Earnings Call
Speaker 1: 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. You know, I think if you contrast it with a U.S. natural gas producer since Christmas.
Speaker 1: US producer, they've seen their price go down by over two-thirds. So this really highlights the kind of hedging 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 Mercantil 2 asset and our other assets using GLTA as our reserve evaluators. I'll just go through some of the highlights of that report. So from an evaluation perspective, our...
Speaker 2: 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 that are at our Mirka-2-2 asset here. So having said that, I'll end this webinar presentation by providing better studies before we begin. Thank you very much. The chair with ID, yay for you all.
Speaker 2: 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 Merkur 2-2 contingent and prospective resource reports. The valuations of these are highlighted in reports so we look forward to those assets.
Speaker 1: 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 dashed line is our current enterprise value. What you see there is that we're trading at just below our 1P NPV. It's basically a poets insertion or just a plant Gemini scenario where and servers or saving market value.
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 Albo-Petro today when you look at the potential additional value that we can...
Speaker 1: 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.
Speaker 3: So just following on Corey's discussion on the strengths 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 of we reflected in per barrel of oil equivalent.
Speaker 3: 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 at
Speaker 3: as Q3 at $11.18 per MCA. Despite that reduction, we did see a 25 cent per BOE increase in our operating net back from Q3. We're over $60 in the quarter and that just shows kind of the strength.
Speaker 3: 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 Q4, that's 88%, which is...
Speaker 3: is pretty remarkable we would say. Overall in 2022 it's 87% and our overall net back in 2022 on a year bid-date basis is 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: 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.
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 funds flow for 2022 with the record year for elbow petro at just under.
Speaker 3: just under $50 million, which is pretty impressive overall. Our net back, which increased $27 million from the prior year, and everything else was relatively flat. So we ended the year at $50 million funds flow.
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, it's pretty impressive that 79% of our revenues. 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. We also saw a slight increase in our sales volume and current tax just with finalization of year-end.
Speaker 3: to fund slow net income, which also incorporates various non-cash items, but with that increase in fund flow from operations, again we had record net income at Albo Petro in 2022. So you know the main impact there was the net operating income was
Speaker 3: you know, significantly higher than 2021 with the higher sales volumes and realized prices. We did have some foreign exchange gains, you know, we talked about that in prior period, the gains were higher than in 2021, mostly accounting for exchange gains and losses on intercompany amounts.
Speaker 3: new base is pretty impressive.
Speaker 3: For the corridor, 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 asset.
Speaker 3: 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.
Speaker 3: So we've seen a steady increase in that since coming on production and now we're debt-free, which is great.
Speaker 1: 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, as you can see, we've already returned.
Speaker 1: also in routine blackout periods through instructions to our broker. Next, I just want to talk about our balanced capital allocation model. This is something that we introduced years ago, long before our cabaret project came on production.
Speaker 1: from operations over time. You can see we had two 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.
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 in 2022 is the first time where we really started to see a lot of the
Speaker 1: has gone to 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.
Speaker 1: The growth plan to come from a number of areas you can see first our core operating area with cabaret and our midstream assets. We did complete the gas plant expansion in the middle part of last year up to 18M 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.
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. TLJ has assigned a combination of 2P reserves, contingent and prospective reserves and
Speaker 1: you know 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 and I'll get Adrienne in a moment to walk you through in a little bit more detail what that plan looks like. On our Balm Lagar mature oil
Speaker 1: We do have up to two development locations on this field targeting the KERAS-2 formation as well as some potential in some deeper formations here. And then lastly on the exploration side, we did drill two exploration prospects last year. The good news is the traps worked. We encountered big hydrocarbon columns.
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 three one and one in seven one that we entered into this.
Speaker 2: we drilled to initially discover 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.
Speaker 2: And this really positioned ourselves to capture any additional natural gas potential.
Speaker 2: So by the end of 2021, we had stable production from Caporei here to our UPGN at the Behegacity Gate and we were ready to move our exploitation focus to the tighter gas potential in N193 and 1071 here.
Speaker 4: So then.
Speaker 2: In 2022, we continue to focus on that exploitation of this type gas project. We built that additional pipeline to the north from...
Speaker 2: from the unit from cab array to 183.1. We built an additional flow line to 197.1 and we built a facility at 183.1 to take our production of three phase separation so we can manage any liquids production, condensate production.
Speaker 2: and position ourselves, leverage the existing infrastructure, position ourselves for the first phase of field development here at Moorooka-Dootoo.
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 wellbore we built a long time ago. And we're really excited about this project. You know, this is a huge milestone for Avopatch to be able to do this multi-stage stimulation tied in the flow lines right at location right now. So we're ready to.
Speaker 2: 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 perspective resource and reserves associated with Merkah 2-2. In 2023, we're going to drill up to two development wells, 183A2 and this 183D1 area.
Speaker 2: with the potential to continue to thrill in 2024.
Speaker 2: and not de-risk the production potential of 20 million centi-p each day of this asset alone.
Speaker 1: All right, thank you. So in summary, again, I continue to think Albo-Petrardo 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.
Speaker 1: Obviously, we've got some attractive gas prices, as Alison noted. We've got best in class operating margins. We've got a clean balance sheet and extremely strong free cash for 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...
Speaker 1: 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.
Speaker 3: Okay, perfect. We have a couple of questions on the impairment charge that was booked in 2-4, so I'll start with that. I touched on that briefly. So we drilled three exploration wells in the year. The first one was 182C1. We drilled and tested that well.
Speaker 3: We ultimately wrote off the cost for that well only. We made the decision to do that. We made the decision to abandon that well. It was drilled very close to the main bounding fault and we missed the secondary target. Ultimately we proceeded with drilling a second well into that prospect, the 182.
Speaker 3: 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, the 197.1 well that is, you said you've started stimulation, when do we expect that to be on production?
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's on location and we're imminent to start the actual simulation.
Speaker 3: Perfect. Staying on Merica 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: When we drilled those initial exploration wells, they were cased with 7 inch 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 simulations. We would also case them in 5.5 inch casings so that we can stimulate that casing.
Speaker 3: Perfect. In the year-end, 2022 estimates of contingent and perspective, if 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 Balmagar were proven successful?
Speaker 1: Yeah, 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 two of the locations from contingent into reserves. I think especially as we drill the well to the north of the 183-1 pad.
Speaker 1: 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, you know, I think at least some of the perspective area would migrate into contingent and it would be kind of a
Speaker 1: evolution over a couple years or a few years of time as we develop the asset to the north.
Speaker 3: When do you see the next material increase from the exploration wells or from the development locations?
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 the Bologarre property.
Speaker 1: 40 to within the next the 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 . 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 as we get information from the America 2-2 project.
Speaker 1: 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.
Speaker 3: So speaking of production, we do have a couple of questions on that. What incremental daily production do you expect from 197.1?
Speaker 2: I can handle that. The estimated production from that specific well for the first year is 180 DOE per day. As Corey noted, we're facility limited at this point to 18 million cubic feet a day at the
Speaker 2: at the UPGN. So depending on how how the results turn out we'll be discussing making facility modifications.
Speaker 3: to adjust the plateau. Okay, 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.
Speaker 1: You know, 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.
Speaker 1: 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 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 to a facility.
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
Speaker 1: 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 1st.
Speaker 3: 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?
Speaker 3: market 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.
Speaker 1: 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. One thing that we probably won't be doing is selectively talking to people about what our trading parameters are or all those things.
Speaker 1: 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 NCIBs versus versus dividends or dividend increases and we'll balance those things going forward so it's tough to predict exactly I know I'd like to preserve some flexibility around that.
Speaker 1: The permitting processes are run by, for the most part for us, by the local environmental regulator in the state of Bahia, which is Anemma. And, 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 price gas being produced into the state.
Speaker 3: now. So the first question, once we are past the August 1st gas price reset,
Speaker 3: With lower gas prices, NVP 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?
Speaker 1: 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.
Speaker 1: 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 ceilings.
Speaker 1: I think that's one of the things that makes albopetrope so attractive.
Speaker 3: 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?
Speaker 1: 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. You know, 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.
Speaker 1: 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.
Speaker 4: Okay. Um.
Speaker 3: Another question here was around total capex for 2022. How much was exploration versus maintenance capital for stable flat production? I can start that in if Corey wants to comment. He can. We actually had total capital capex of just under $25 million in the
Speaker 3: About $18.5 million of that was for exploration projects as well as long lead purchases. And then we had spending at our Mirk 2-2 project of about $4 million, which was development in nature and not capital. We did have
Speaker 3: about $2 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 something that we have to do to maintain the current production. Hopefully that makes sense.
Speaker 1: Yeah, I think Albo-Pexor is a little bit different than the normal company where you think about maintenance capital. Obviously, we still need to be focused on replacing reserves and that, but because of our Cap-A-Ray project being fully developed in advance, like there's all the production facilities are there, there's eight wells, it's quite well delineated.
Speaker 1: and the capital, just because the nature of a gas project like that, you 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...
Speaker 3: just released yesterday, it can be found on our website or on CDER. The NPV-10 of the proof developed producing assets is $147 million. But if you have any other questions specifically on that, feel free to reach out to me. I'm just going to double check quickly here to see if we have any other questions.
Speaker 1: I do not think we do. I think that is it, unless there's any final comments for you or Adrian wanted to make. 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.