Alvopetro Energy Ltd.

All right. Good morning.

And welcome to our Fourth Quarter Results Webcast. I’m joined today by Alison 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, our strong results not only allowed us to start our dividend program to shareholders about six months ahead of schedule last year in the third quarter, and we’ve now been able to announce a 33% increase in the dividend effective the first quarter of this year with continued strong gas prices. 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 Alvopetro.

I’ll let you read the cautionary statements at your leisure and will 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 have had very strong production results, way exceeding expectations.

I think that 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 netback, 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. And that was our average realized sales price from natural gas, which makes up the bulk of our production was just over $7 per Mcf.

And then, we deduct off our royalties, which are shown in orange and our production expenses, which are shown in yellow, and the green bar is our operating netback, which is our profitability. And overall, you can see that’s been growing steadily since we came on production and on a netback margin basis relative to our sales price.

We’re at over 80% and over 82% in a fourth quarter, which I think compares very strongly to our peers. As everyone knows, we did announce sales price increase as of February 1st.

So, when we announce 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 $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 another 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 $0.5 million increase in G&A just following our full year results and our funds flow from operations of $25 million. In the year, we did have then increase in our bonus accruals, so that was recognized in the fourth quarter.

Despite that reduction in funds flow, net income actually went up to $1.1 million from Q3. So, that was mostly due to noncash 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 from 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 last from Q3 to Q4 than it has from Q2 to Q3. So, you will see fluctuations on foreign exchange going forward.

When you see an appreciation in the Brazilian currency, as we’ve seen thus far in Q1 of this year than that -- you’d expect to see more of a foreign exchange gain. But ultimately, it will depend on that ending foreign exchange rate at the end of the period that we’re looking at.

A deferred tax in the third quarter, we did recognize the benefit of the SUDENE tax incentive. We were qualified.

We received notification that we’re qualified for that. That reduces our overall tax rate in Brazil, from the statutory rate of 34% to 15%.

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.

But because we have, let’s call, a deferred tax asset, when that’s valued at a lower tax rate, that creates a deferred tax expense. So, that was higher into Q3 when we recognized that, the benefit of that lower tax rate and Q4 is lower than -- because of that adjustment.

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 highlighted green bar there exceeds that credit facility balance by $2.6 million as of December 31st.

And we did announce that we’ve retained another $1.5 million of that credit facility in February. So, our balance reduced to $5 million as of today, after that payment.

Great. Thank you, Alison.

Yes, I think to put that in perspective, we repaid two-thirds of our project financing loan in the first six quarters of production. And at the $5 million level, you can see our drawn debt balance is actually down to less than one quarter’s 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 these are -- 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 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 graphs 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 we 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 forecasts, it would dip it back down below the ceiling on this chart. So, the other couple of key things to talk about is within these assumptions on both of these charts, we use U.S.

inflation for 2022 of 5%, 3% in 2023, and then 2% thereafter. So, I think relative to current expectations, there’s I think a consensus that inflation will be higher than that, and what the impact of that is, which is particularly relative because our forecast price is actually at the ceiling is those inflation numbers adjust both the floor and the ceiling.

So, if we have higher inflation than that, then you’ll see higher prices 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 the net effect is that we were to use today’s forward pricing is we have you can see the black line and the green line there 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 2026.

And you can see it’s much closer to the ceiling after that. So, the net effect after that period of time is 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 in the graph on the left hand side. And what that means is that’s kind of a cushion on how much these prices could reduce before you would see a reduction below the ceiling within our contract.

So, I think we are 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 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 a $1.94 per cubic meter.

And then, that price stays in Brazilian currency for six months. So, all these graphs here assume Brazilian currency rate of 5.41 and currently around oh 5.04.

So, if that persists, you would actually see a higher price than what we are 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 2020.

With the increase in prices that I just finished talking about, we’ve realized a 52% increase in our 2P NPV10 before tax. One other thing to point out is that our 2P after tax NPV 10% is actually $256 million.

So, quite close to this number. 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 SUDENE benefit that Alison talked about earlier.

But I can assure you that that compares extremely favorably to our peers. Our contingent resource that’s associated with our Murucututu/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% increase. Obviously, none of these PVs include the potential associated with the two exploration wells that we’re drilling, the first got right now.

So, how this translates into our net asset value on a 2P reserve-only basis? We almost -- we increased that to over C$11 per share.

And if you layer on the contingent and prospective resource value associated with our Murucututu project, that number almost doubles. So, I think we’ve done pretty well off the benefit of some of those increased prices that talked we 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 value to stakeholders, building an extremely strong balance sheet.

We basically pre-funded a good portion of our program. So, we’re excited to be drilling again.

To put it in perspective, our near-term goal is to achieve a production rate of 18 million cubic feet a day, so that’s 3,000 barrels of oil equivalent per day. Plus on top of that, we would have condensate.

And we’ve got the longer-term vision to build a business model out to roughly 35 million cubic feet a day. And it’s really a three-pronged strategy.

It’s all for the most part 100% working interest projects. Starting with, we do have some growth plans associated with our Caburé project and our midstream infrastructure.

We’re in the process of expanding our gas plant up to 18 million cubic feet per day capacity. We’re hoping there 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 spud the first of two conventional exploration prospects the 182-C1 location.

I’ll spend some time showing you what we’re targeting there and talk about the timing. And immediately after that we’ll drill our 183-B1 location.

You can see best estimate prospective unrisked resource of 4.6 million 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 Murucututu project.

As many people know, we’ve got two existing wells that we -- 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 Caburé 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 Caburé.

We’ve got seven existing wells here, for the most part of the fields, 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 we’ve had many, many days and months where we’re up around the 20 million cubic feet a day mark 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, starting next quarter is drilling this Unit Sales well.

It’s a combination of a development well targeting the shallow Pojuca formations, but more excitingly probably is that we’re going to extend the well deeper and target this deeper Caruacu exploration target. So, these are the same reservoirs that we’re producing from on the eastern side of this main bounding fault here, and it’s where most of the production and reserves are associated with right now.

And we have similar prospectivity on the down side of this fall. And we’ll get results from that next quarter.

So, moving on to the conventional exploration program. 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 here and here on the yellow acreage, they’re both 100% prospects.

We’ve got some -- just to give you, this is some of our reprocessed 3d seismic. It’s 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 basin.

You can see all the analog pools circled in a red, and all the black lines here all the different fault blocks. So, we’re just -- we’re trying to drill into two line [ph] drill fault blocks.

Based on these other analog pools, we can see at this depth 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, a little bit of a zoom-in on the well we’re drilling right now, this 2,900-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 the typical pretty good place that we’ve got perspective reservoir sands, on the right here, stacked up across the fault against basement shale. So, that’s typically a pretty good, like I said, the place that happen 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 Murucututu project.

Again, this is a 100% of 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 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 8.5 sections of land. Like I said, we finished the pipeline extension from the Caburé 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, 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 197-1 well tie that back into 183 and then start our fit-for-purpose development drilling program.

What that looks like is that 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 MURS-1.

And you can see it’s deviated directionally to the south. And it not only targets these prospective type Gomo sands, but there’s also some interesting up-hole exploration potential that we’ll target with that well.

And then the second development well we’ll go north from the 183-1 location, the MUR-1 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 continued resource and our prospective resource.

The 2022 program really targets this lower way, 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 MURS-1 and MUR-1. And then, our capital program in future years, you can see the stacking in on the capital graph on the bottom, but that would be targeting contingent and prospective resource.

And the plan would be with this pad-based development to just hopefully continually migrate in resource into reserves and production over time here. So, 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 in March that’s underway.

We’d follow that with the second exploration well. The little flames here show that - the timing of, if we have success on all these things, when would the production come on?

So, for those two, because we are 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 C well 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 quickly.

Moving to the Murucututu project, because we’ve got the pipeline already built, as soon as our production facility construction is complete, we’ll be able to put that well on production. We are just waiting on our permit to do the stimulation and tie in to 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 summary slide from our corporate presentation, but I think we’ve had a lot of good announcements of late.

Obviously, our gas price increased to over U.S.$11 per Mcf becomes effective on February 1st. As Alison pointed out, I think that will drive even stronger results and was really a driving reason for us being able to increase our dividend by 33% this quarter.

Alison pointed to the margins, but at 82% margins and growing with these new gas prices, they really are best-in-class profitability 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 reserve values. I think, we are 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 footprint. So, with that, we’re going to turn it over to the question-and-answer portion of our session here.

Maybe Alison, you can remind people how to log their questions.

[Operator Instructions] Maybe the first question that has come in is, if you do have an exploration success at either of the two wells, so the 182-C1 or the 183-B1 one that would follow, 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?

Yes. 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 to that.

But that being said, we’re very happy with our counterparty here. They’ve expressed interest in demand for as pretty much as much gas as we could possibly give them.

So, we’re confident that our longer term 35-million-cubic-foot in a target yield could be completely absorbed by the local distribution company. At those levels, it would account for roughly close to about a quarter of their demand.

And on the gas price, is there a potential to sell incremental volumes at an even higher price then?

Yes, I touched on that. I guess, in theory, yes, because the state oil is company selling at a higher price.

But I think for now -- like I said, we’re happy selling to -- the gas at these prices, where 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 -- we’re positioned extremely well.

We’re 15 kilometers north of the main industrial complex where most of the gas gets consumed. And we’re 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, they have about $1.50 an Mcf disadvantage relative Alvopetro.

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

Yes. So, I touched on that on the catalysts slide.

But it’s roughly a year. We’ve done a lot of upfront work, assuming success.

We’re doing some final engineering and then 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, position almost immediately after a success -- be in a position to be able to submit those.

So, if you -- six to nine months for permitting, and then you’ve got roughly three to five months for construction.

What is your CapEx guidance for 2022 and production expectations and cash tax payable?

Well, we haven’t provided guidance for 2022. But we have walked through each of those pieces of capital that show up on that near-term catalyst, we could walk through that quickly.

I don’t have it on the screen, but I can do that for you. The two exploration wells that we’re drilling are roughly $3.5 million $3.6 million each.

If we were to test those, they’d be roughly $0.5 million each to test them. Our share of the Unit C, well, roughly there about -- let’s call it $1 million.

And Alison will correct me, if I make any mistake through the piece here. The tie-in of the 183-1 well and the EPF construction project did span year-end.

So, that one’s a little bit more complicated. I might need Alison’s help with the portion that would show up in 2022.

Yes. There’s about another 1.3 million to finish that project in 2022 here.

Thank you. And then, we’ve got…

Yes.

So, I’ll come back to the 197-1 simulation and tie-in. The fit-for-purpose Gomo wells that we have here would be roughly $6 million apiece.

And then, the gas processing facility, this is actually just an -- this was actually within our gas processing agreement when we originally did our deal. So, 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, et cetera, but those are the big components.

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?

Yes. So, 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 with the resurgence of oil and gas pricing, you’re seeing almost all of our peers adopt similar policies, I would say that the half that’s been going to stakeholders, and frankly, probably been more than half today because the capital is just starting here this year, has really been focused on a very aggressive basis, repaying the debt that we have outstanding, and we would probably expect to continue to do that.

So, 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 horizon here, what do we do with that other portion of the bucket that’s getting allocated to stakeholders. So, that’s a decision for the Board to make at that time.

And we get questions about would you do share buybacks and dividends, and -- 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?

Yes. 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. Like, it will show what the porosity is.

But, the permeability portion of that equation is really, we need to test the wells. So, we would do that with the success.

We didn’t put that on our timeline that I showed you before. But, that would happen very quickly after open hole locgs.

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 2020 capital program progresses.

Thank you again.

Thanks.