Alvopetro Energy Ltd.

All right, good morning and welcome to our fourth quarter results webcast. I'm joined today by Allison Howard, our Chief Financial Officer, and it's really a pleasure to be addressing our shareholders today. We posted another great quarter on a collective basis. You know, our strong results not only allowed us to start our dividend program to shareholders Mark Warren, About six months, I had a schedule last year in the third quarter and we've now been able to announce a 33% increase in the dividend effect of the first quarter of this year with continued strong gas prices. Mark Warren, Obviously we'll spend some time talking about our fourth quarter results today, but we'll also talk about I think a very exciting 2022 capital plan for Alvo Petro. we'll let you read the cautionary statements at your leisure, and we'll just start with production. We've been announcing this on a monthly basis, but you can see since we came on production July 5th of 2020, we've had very strong production results, way exceeding expectations. I think the first quarter that we announced in the third quarter of 2020 was more indicative of kind of what our pre-commercialization expectations were and you can see we've been well above that all the way through last year and that's continued into the early part of this year. Our fourth quarter production at 2,432 barrels of oil equivalent per day was up 25% year over year and virtually flat with the prior quarter. And with that, I'll turn it over to Alison.

Thanks and good morning, everyone. This first chart here is our operating net back, which is one of our non-GAAP measures and refers to our profitability per barrel of oil equivalent. So we start with our realized sales price at the top of the chart there, which was just over $44 in the fourth quarter. um and that was um our average realized sales price from natural gas which makes up the bulk of our production was just over seven dollars per mcf and then we deduct off our royalties which are shown in in orange and our production expenses which are shown in yellow and the green bar is our operating net back which is our profitability and and overall you can see that's been growing um steadily since we came on production and on a on a net back margin basis relative to our sales price, we're at over 80% and over 82% in the fourth quarter, which I think compares very strongly to our peers. As everyone knows, we did announce a sales price increase as of February 1st. So when we announced Q1, you should see a much higher realized price. And as most of our costs are fixed in nature, that shouldn't change too much. So Q1 should be looking pretty good going forward. This is our funds flow from operations, which is our cash flows from operating activities before changes in working capital. So there was a $1.5 million decrease compared to Q3. If you recall back when we had our Q3 results, we did have some one-time non-recurring amounts recognized in other income in Q3. So there was a decrease of about $800,000 in other income. So our Q4 is more recurring other income amounts in nature. So that will be more consistent going forward. And then the other item was we did have just a half a million increase in GNA just following our full year results and our funds flow from operations 25 million in the year. We did have an increase in our bonus accruals, so that was recognized in the fourth quarter. Despite that reduction in funds for net income actually went up 1.1 million from Q3. So that was mostly due to non-cash charges. So things that you won't see going through our statement of cash flows. So these are things that get adjusted back out on our statement of cash flows. So a couple of the bigger items are foreign exchange losses and deferred tax. I talked a little bit about the foreign exchange losses last quarter, but we do have some accounting foreign exchange losses recognized on intercompany loans. And that for accounting purposes have to be reflected on our consolidated financial statements, even though they are intercompany in nature. So there was a lower foreign exchange loss in the fourth quarter compared to the third quarter, just because the Brazilian currency devalued less from Q3 to Q4 than it had from Q2 to Q3. So you will see fluctuations on foreign exchange going forward. When we see an appreciation in the Brazilian currency as we've seen thus far in Q1 of this year, then you'd expect to see more of a foreign exchange gain, but ultimately it will depend on the ending foreign exchange rate at the end of the period that we're looking at. Um, deferred tax in the third quarter, we did, um, recognize the benefit of the Sudanese tax incentive. We were qualified. We received notification that we were qualified for that. That reduces our overall tax rate in Brazil from the statutory rate of 34% to 15%. Um, so overall that's a benefit and you can see that reflected in a relatively low current tax relative to our income overall for the year. Amy Nunez, But because we have what what's called a deferred tax asset when that's valued at a lower tax rate that creates a deferred tax expense so that was higher in Q3 when we recognize that the benefit of that lower tax rate. Amy Nunez, And Q4 is is lower than because that adjustment went through and then moving on. Our working capital and cash balances have increased steadily. So our working capital is our current assets, less current liabilities. And that's the green bar that's shown there. So as of December 31st, our working capital was 9.1 million. And the orange line shows our credit facility balance. So back when we commenced operations, we were fully drawn on our credit facility at just over $15 million owing. and we were down to $6.5 million as of December 31st. So you can see that our working capital, the height of the green bar there, exceed that credit facility balance by $2.6 million as of December 31st. And we did announce that we repaid another $1.5 million of that credit facility in February. So our balance reduced to $5 million as of today after that payment.

all right thank you allison yeah i think to put that in perspective we repaid two-thirds of our project financing loan in in the first six quarters of production and and at the five million level you can see our drawn debt balance is actually down to less than one quarters funds flow from operations So we had some requests from our shareholders to talk a little bit more about natural gas prices and how all that works and there's a lot of lines here but I'll try to slow down and take some more time today to talk through these. It's probably the good time to do it because we just announced our new reserve report. I'll walk through the results of that but we did have some big increases in values. We talked about kind of what the the gas price forecast was looking like when we met last time. But just to explain this chart a little bit more, the way our gas sales agreement works is we have a formula that blends three international benchmark prices over a kind of relatively long period of time. And the three of them are the lower dotted line here is Henry Hub U.S. gas price. The longer dashed line in the middle here is Brent oil equivalent. And then the upper dashed line here is UK NBP natural gas prices. So to the left of this red dotted line, those are all the historical prices. And then to the right of the dotted line is what was used in generating these price forecasts that you see below. So the graph on the left hand side are the forecasts that GLJ, our independent reserve evaluator, used as of the end of last year in the NPVs that we announced on March 7th or 8th. So you can see here relative to the kind of spot pricing at the time, they forecast a pretty steep decline in NBP. They forecast lower Brent prices and then similarly as well, the same thing for Henry Hub. So the net effect of all that is that we have a calculated gas price that's the blue line that you see here. But we, as you know, have a ceiling which is in green and a floor within our contract, which is in red. So what happens is in the first few years of this, we actually end up with a gas price that's capped at the ceiling out to August 1st of 2024. And then you can see based on their forecast, it would dip back down below the ceiling on this chart. so the other a couple key things to talk about is within these assumptions on on both of these charts uh we use u.s inflation for 2022 of five percent three percent in 2023 and then two percent thereafter so i think know relative to current expectations um you know there's a i think a consensus that inflation will be higher than that and what the impact of that is which is particularly relevant because our forecast price is actually at the ceiling is that those inflation numbers um adjust both the floor and the ceiling so if we have higher inflation than that then you'll see higher prices uh going forward What we're showing on the right-hand side here is if we redid this as of March 16th using futures pricing, this is what the futures curves looks like for each of these three benchmark prices. So again, Henry Hub on the bottom, Brent Oil here, and NBP is the upper line that you see here. And then that effect is if we were to use today's forward pricing is we have, you can see the black line and the green line, they're at the same level because that's the ceiling. The ceiling pricing extends quite a bit further. It actually goes out to February 1st of 20, sorry, of 2026. And you can see it's much closer to the ceiling after that. So the net effect after that period of time is it's about a 15 to 20% increase in the forecast price. the other thing to point out is if you actually look at the actual calculated price again that's in blue so there's a significant spread in what the price formula says and what the ceiling is so it's much higher than what you saw on the graph on the left hand side and what that means is that's kind of the cushion on how much these prices could reduce before you would see a reduction below the ceiling within our contract. So I think we're well positioned. Obviously, we've got a strong gas price. It certainly will have less volatility than what our peers will see going forward here. The last point I'm going to make on this slide is to just talk a little bit about currency. In reality, what happens every six months is our price gets set in local Brazilian currency. Right now it's $1.94 per cubic meter. And then that price stays in Brazilian currency for six months. So all these graphs here assume a Brazilian currency rate of 5.4 to 1. I think we're currently around 5.04. So if that persists, you know, you would actually see a higher price than what we're reflecting on the graphs here. So we also recently announced, I think, a fairly positive reserve and resource update that was on March 8th. We had virtually no revisions to our volumes other than the reflection of the production from 2021. We'll talk about our 2022 capital program, but it's obviously very focused on growing our reserves in 2022. With the increase in prices that I just finished talking about, we realized a 52% increase in our 2P NPV 10 before tax. One other thing to point out is our 2P after tax NPV is at 10%. is actually 256 million dollars so quite close to this number um that was up 51 year over year as well but our before tax pvs are about 86 of the before tax numbers so very high percentage it reflects the strength of being in brazil it reflects the sudani benefit that allison talked about earlier but i can assure you that that compares extremely favorable favorably to our peers Our contingent resource that's associated with our America 2-2 GOMO project had similar increases in NPVs. The contingent value increased 61% to $61 million, and the prospective resource value increased up to $209 million, which was a 44%. James J Mullooly, Ph.D.: : increase obviously none of these PVs include the potential associated with the two exploration wells that we're drilling the first of right now. James J Mullooly, Ph.D.: : So how this translates into our net asset value on a 2P reserve only basis, we almost We increased that to over $11 Canadian per share. And if you layer on the contingent and prospective resource value associated with our America Tutu project, that number almost doubles. So, you know, I think we've done pretty well off the benefit of some of those increased prices that we talked about earlier. so now i'm going to just shift and talk about our 2022 capital program i think up to this year we've been very focused on aggressively repaying debt returning uh value to stakeholders building an extremely strong balance sheet we basically pre-funded a good portion of our capital program um so we're excited to be be uh be drilling again uh to put it in perspective our near-term goal is to achieve a a production rate of 18 million cubic feet a day so that's uh 3 000 barrels of oil equivalent per day plus on top of that we would have condensate and we've got a longer term vision to build a business model out to roughly 35 million cubic feet a day and it's it's really a three-pronged uh strategy it's all for the most part 100 working interest projects Starting with, we do have some growth plans associated with our cabaret project and our midstream infrastructure. We're in the process of expanding our gas plant up to 18 million cubic foot a day capacity. We're hoping that it will actually be more than that with this expansion. I'll talk on the next slide about our plans at the unit, but we do have one well that's a combination development and exploration potential plan this year. And then we've sped the first of two conventional exploration prospects, the 182C1 location. I'll spend some time showing you what we're targeting there and then talk about the timing. Immediately after that, we'll drill our 183B1 location. You can see best estimate perspective unrisked resource of 4.6 and 5.9 million barrels of oil equivalent, respectively, with pretty high chances of success. And then the third leg of the stool really is our America 2-2 project. As many people know, we've got two existing wells. They were our original wells drilled in Brazil, the 197-1 and the 183-1 wells. We've completed the extension of our pipeline network from the Cabaret unit area up to the 183 location. And we're well positioned now to execute our 2022 capital program. And I'll walk you through what that looks like. So just touching on Cabaret, we've got seven existing wells here. For the most part, the field's fairly fully developed. We actually increased our unit production capacity with our partner up to 600,000 cubic meters a day, or just over 21 million cubic feet a day. If you recall, this was originally designed to be just under 16 million cubic feet a day. on a gross basis the unit you know we've had many many days and months where we're up around the 20 million cubic feet a day mark um uh production it's really capped by our existing capacity in our gas processing facility but one of the things we're going to be doing here uh starting uh next quarter is drilling this unit c well and it's a combination of a development well targeting these shallow pajuca formations um But more excitingly probably is that we're going to extend the well deeper and target this deeper Karasu exploration target. So these are the same reservoirs that we're producing from on the eastern side of this main bounding fault here. And this is where most of the production and reserves are associated with right now. And we have similar prospectivity on the down thrown side of this fault and we'll get results from that next quarter. so moving on to the conventional exploration program um we've got our 182 c1 prospect that you see here that's what we're drilling right now we spud that on march 2nd and then right after that's completed we'll move over and drill the 183 b1 location so you can see them um here and here on the yellow acreage they're both 100 prospects um we've got some You know just to give you this is some of our reprocessed 3D seismic. It's an agua grande structure map. What you're looking at is there's a main bounding fault that runs northwest to southeast here that separates the main parts of the basin. You can see all the analog pools circled in red. And all the black lines here are all the different fault blocks. So we're trying to drill into two undrilled fault blocks based on these other analog pools. You can see at this depth that the faults have good sealing capacity. And because we're close to production in a proven area with that good fault sealing capacity, that's why GLJ, our independent reserve evaluator, has been able to assign pretty good chances of success on both these prospects. So just a little bit of a zoom in on the well we're drilling right now. This is a 2900 meter location. It's a combination, a multi-zone pre-rift prospect. So we're targeting the Agua Grande formation and the Sergi formation here. And this is, you know, the typical pretty good place set up. We've got prospective reservoir sands. On the right here, stacked up across the fault against Basement and Shale. So that's typically a pretty good, like I said, play set up and again contributing to the higher chances of success. We expect to have results from this to announce to shareholders sometime around the middle part of April. So with that, we'll move on to our America 22 project. Again, this is 100% project. You can see some more of our reprocessed seismic here in the two existing wells. We've got 197.1 and 183.1. Both of these wells tested gas in this lower sequence. We can map this sequence. It's the area between the yellow and red lines over a very large area. It's about a 5,500-acre geobody that we've identified, so that's about eight and a half sections of land. Like I said, we've finished the pipeline extension from the Cabaret Hub up to the 183-1 well, and we're in the process of finishing our surface production facilities. You can see a picture of that on the bottom left. So we expect to have that well on production here early in the second quarter. And then we'll be positioned to complete the rest of our 2022 development plan. And what that's focused on is step one would be to stimulate the 197-1 well, tie that back into 183, and then start our fit for purpose development drilling program. What that looks like is a Google Earth image here, but you can see our existing well pads at 183-1 and 197-1. We would have a new pad to drill the MERS-1. And you can see it's deviated directionally to the south. um and it not only targets these prospective uh uh tight gomo sands but there's also some interesting uphole exploration potential that will target with that well and then the second development well will go north from the 183 one location uh the mer one location that you see immediately north of that so you can see it's a deviated well the little circles are all the bottom hole locations On the charts on the right, these are the accumulation of our 2P reserves, our contingent resource and our prospective resource. The 2022 program really targets this lower wedge, so the lighter green color, that's our 2P reserves. And in that, we've got our two existing wells, 197-1, 183-1, and then these two undeveloped locations, MERS-1 and MER-1. And then our capital program in future years, you can see it stacking in on the capital graph on the bottom, but that would be targeting contingent and prospective resource. And the plan would be, you know, with this pad-based development to just hopefully continually migrate in resource into reserves and production over time here. so uh this is just a slide from our new investor presentation to give you a sense for all these near-term catalysts we've got we've got a very busy program in 2022 obviously we started drilling the 182 c1 well uh in march that's underway we'd follow that with the second exploration well the little flames here show that right you know the timing of if we have success on all these things when would the production come on so for those two because we're going to build if we had a success we would build a pipeline after that we wouldn't see the production until 2023. Right now the unit seawall is forecast to be roughly drilled late in the second quarter and then a much shorter it's right offsetting the unit hub area so we'd be able to with our partner bring that on production fairly fairly quickly. moving to the america 22 project because we've got the pipeline already built as soon as our our production facility construction is complete we'll be able to put that well on production um We're just waiting on our permit to do the stimulation and tie in for the 197-1 well, but hoping to have that on early in the third quarter. And then when we finish drilling our two exploration wells, that's when we'll start drilling our two development wells within the GOMO. You can see those slotted in here with production coming on late in the year and in the fourth quarter. We talked about our gas processing facility, but that's scheduled to be on stream actually in June to increase our capacity up to 18 plus million cubic feet a day. So in conclusion, again, this is a summary slide from our corporate presentation, but I think we've had a lot of good announcements of late. Obviously, our gas price increase to over $11 US per MCF becomes effective on February 1st. As Alison pointed out, I think that will drive even stronger results and was really the Mayor Mrakas, The driving reason for for us being able to increase our dividend by 33% this quarter. Mayor Mrakas, Allison pointed to the margins, but at 82% margins and growing with these new gas prices, they really are best in class profitability per per unit of production produced. We've been aggressive repaying debt. We were actually in a positive working capital net of debt position at the end of the quarter with $2.6 million outstanding. And I think we've done a good job of creating an extremely strong balance sheet. Really, really good increases in our 2P net asset values and our and reserve values, I think we're still trading at an extremely attractive price relative to 2p net asset value at 46%. And when you combine that with a close to 8% yield, I think we really are quite a unique yield plus growth investment opportunity, especially when you consider all these near term and fairly high impact catalysts that we have from a really exciting 2022 capital program. With that, we're going to turn it over to the question and answer portion of our session here. Maybe Allison, you can remind people how to log their questions.

Yeah, so you should be able to see a question and answer button at the bottom of your screen. If you just want to go in there and type any questions you have, we will answer them. For anyone that's dialing in, you can send an email to socialmedia at alvopetro.com and we can ensure that gets included. And if you have questions and afterwards want to follow up with any of us, obviously feel free to do that as well. um maybe the first question that has come in is if you do have an exploration success at either of of the two wells so the 182 c1 or the 183 b1 that would follow um is all the natural gas from that expected to be sold under the same gas sales agreement or would you have to negotiate a new gas sales agreement

yeah you know one of the things we didn't talk about on those gas pricing slides is although our price looks pretty attractive if you compare it to what the state oil companies charging the local distribution companies right now we're still selling at a significant discount for that but that being said we're very happy with our counterparty here they've expressed uh interest in demand for as pretty much as much gas as we could possibly give them so you know we're confident that our longer term 35 million cubic foot a day target you know could be completely uh absorbed by the local distribution company um at those levels that would account for you know roughly close to about a quarter of their their demand and on the gas price is there potential to sell incremental volumes at an even higher price than Well, yeah, I touched on that, I guess, in theory, yes, because the state oil company selling at a higher price. But i think for now you know like i said we're happy selling to to bahia gas at these prices where you we have a big advantage relative to our peers and that we have a connection directly into the city gate in the basin that we're producing so it's you know we're positioned extremely well we're 15 kilometers north of the main industrial complex where most of the gas gets gets consumed And we're, you know, one of the only companies, again, with a direct tie-in. So for a lot of peers, if they were to have to ship gas through the national infrastructure to a city gate, you know, they'd have about $1.50 in MCF disadvantage relative to Algo Petro.

On success of those exploration wells, how long to get to production?

Yeah, so I touched on that on the catalyst slide, but it's It's roughly a year. We've done a lot of upfront work assuming success. We're doing some final engineering in them such that we'd be able to immediately upon success submit a permit. So we've done all the early lead time items and would be, like I said, positioned almost immediately after a success be in a position to be able to submit those. So if you said six to... six to nine months for permitting and then you've got uh you know roughly three to three to five months for for construction what is your capex guidance for 2022 and production expectations and cash tax payable yeah well we haven't provided guidance uh for 2022 but we have walked through um you know each of those pieces of capital that show up on that near-term catalyst you know we could walk through that uh quickly i don't have it on the screen but i can i can do that for you the the two exploration wells that we're drilling are roughly 3.5 3.6 million dollars each if we were to test those they'd be roughly half a million dollars each to test them Our share of the Unit C well, you know, roughly is about, let's call it a million dollars. And Alison will correct me if I make any mistakes through the piece here. The tie-in of the 183-1 well and the EPF construction project um did span year end so that one's a little bit more complicated i might need allison's help with the portion that would show up in 2020 yeah there's about another 1.3 million to finish that project in in 2022 here um thank you and then we've got can you give me the budget yeah So I'll come back to the 197.1 stimulation and tie in. The fit for purpose GOMO wells that we have here would be roughly $6 million a piece. And then the gas processing facility, this was actually within our gas processing agreement when we originally did our deal. This isn't really a capital cost. It will increase our capital lease payment by $35,000 a month when that comes on production.

And the 197-1 stimulation and tie-in is budgeted at $3 million.

And then there are some other miscellaneous costs that will show up in our financial statements, like some capitalized G&A, etc. But those are the big components.

um the next question we'll go to is what are your thoughts on uses for excess free cash flow and liquidity will you have a more formal dividend policy uh yeah so you know we've been talking about this for literally years our plan has always been to take roughly half of our cash flows

and return those to stakeholders and the other half invest in organic growth opportunities and I think you know with the resurgence of oil and gas pricing you're seeing almost all of our peers adopt you know similar policies I would say that the half that's been going to stakeholders and frankly, we've probably been more than half to date because the capital is just starting here this year. You know, it's really been focused on on a very aggressive basis, repaying the debt, the debt that we have outstanding. And we would probably expect to continue to do that. So, you know, the obvious question goes when we get to zero debt, which is not too far at the pace we've been going, it's not too far into the into into the horizon here. You know, what do we do with that other portion of the bucket that's getting allocated to stakeholders? So, you know, that's a decision for the board to make at that time. And, you know, there's, you know, we get questions about, you know, would you do share buybacks and dividends? And, you know, but that's roughly our policy that we've been pursuing. And I think we've been sticking pretty close to it.

The next question goes back to the exploration wells. Will your open hole logs pretty reasonably define the productive nature of those wells?

Yeah, I think we've had good success with our logs defining what's net pay and what the quality of the net pay is. Ultimately, that will help. It will show what the porosity is, but the permeability portion of that equation is really, you know, we need to test the wells. So we would do that with a success. You know, we didn't put that on our timeline that I showed you before, but that would happen, you know, very quickly after open hole logs. We'd move the rig off, come in, test the well in parallel with drilling the second well.

Great. And there are no other questions at this time. But again, as I mentioned before, if anyone has any questions afterwards, feel free to reach out to us and we'll ensure your questions get answered.

All right. Well, thank you again, everyone, for attending. It's been a really exciting time and we're looking forward to updating you on our progress as our 2022 capital program progresses. Thank you again.