Alvopetro Energy Ltd.

a few administrative points before we start. We are recording today's call and there will be a replay on our website later on this afternoon. In addition, all attendees have been placed in listen-in only mode for the duration of the call. As per usual, we will have a Q&A session at the end of the presentation and you can start logging any questions now using the Q&A button that you should see on your Zoom screen. If you've dialed in by phone, you can send us any questions to socialmedia at elvopetro.com. And lastly, just before we start here, we do make various forward-looking statements and we go through non-GAAP measures throughout the presentation. And so just please review all of the cautionary statements and other disclosures that you can find at the end of our presentation, which is posted on our website and also in our most recent MD&A, which we just released yesterday.

Thank you, Alison. So let's start off with our production results here. Just as a recap, if you remember, before we came on production from our Cabaret project, our pre-commercialization production guidance was basically equal to our firm sales under our Bahia gas contract at that time. and it was also equal to the unit productive capacity multiplied by our working interest in the unit. Since we started production in July of 2020, We've either met or significantly exceeded that expectation. I would say there was a considerable amount of time through 2021 through to 2023 where Bahia Gas was able to take a lot of flexible gas in addition to the firm volumes that we had committed to. In 2024, that did change a little bit. Bahia Gas had committed to their firm supply quite a ways in advance, and they did have some demand disruptions. So what we did is late in 2024, two things happened. Bahia Gas reduced their overall amount of firm commitments. And at the same time, Albo Petro increased, we increased our share or our firm volumes under our Bahia Gas contract by a third. And what you can see is that's resulted in a pretty nice uptick in production in the first quarter, which we had previously released. 2,446 barrels of oil equivalent per day, which is up about 41% quarter over quarter. And you can see we just announced April production here yesterday as well. And you'll notice it does include the very initial parts of our newly added Canadian oil production as well, but overall pretty flat from the first quarter and we'll talk about our plans on all those assets, but our strategy basically through the rest of the year is to add more 100% working interest natural gas production from Brazil, and also we expect to drill up to another four wells in Canada to further expand the oil production platform.

Okay, so we just released our Q1 2025 results yesterday afternoon, and we'll just go through some of the key highlights. Just to start here, this is our operating net back. It's one of those non-GAAP measures I talked about earlier. It's a measure of our operating profitability. We measure that on a per barrel of oil equivalent basis or per BOE. Just a reminder, that's calculated. We start with our realized sales price, which is the top of the bar chart. We deduct off royalties in orange, production expenses in gray. And then the operating net back is the green bar that you see on the chart. So looking at Q1 2025 here on the pricing basis, we are very consistent with last quarter decrease of about 21 cents per BOE. That incorporated our natural gas sales price of $10.44 per MCF for the quarter. The royalties, which is the orange bar, you'll see a big jump there in our royalties in Q1. That stems from some additional royalties we recognized this period relating to our gross overriding royalty that we have on some of our blocks in Brazil, including a block that is on both our Cabaret and our Merc 2-2 natural gas fields. And the dispute just stemmed from the computation of that gross overriding royalty on natural gas. So we have recognized an additional amount this quarter for that. Important to note that that amount that we've recognized in Q1 does include the historical amounts going back to since natural gas sales commenced in July 2020. So we aren't expecting this level of royalty rate going forward. Ultimately, it will depend on forecasted commodity prices, but We are expecting more in the 5% to 6% range as a percentage of our realized price. On the production expenses, that's the gray bar. Production expenses were relatively consistent with last quarter. They were up just about $100,000 overall on a dollar basis. We did start our compression operations this quarter, so there were some additional costs associated with that. But overall, we saw a decrease of $1.34 per BOE on the cost because we did have higher production this period and most of our production expenses are fixed in nature. So with higher volumes, we have lower costs per BOE. Overall, our net back for the period, $50.77. So again, a decrease of, of over $4 compared to last quarter, but still very strong net backs and relative to our realized price margin of 80%, even with that additional royalty amount recognized this period. So this has allowed us to generate really strong cash flows and funds flow from operating activities on this base level of production. So if we move on to funds flow, So this chart is just showing the change compared to last quarter. So last quarter, just under 7 million of funds flow from operations compared to 9.2 million this quarter. So an increase of 2.3 million. Most of that was the 41% increase in sales volumes that we saw. Offsetting that partially was the additional royalties and that slight addition in our production expenses. And then current tax was also higher with the higher earnings, G&A was lower. So that helped on the plus side. Similarly, on net income, we saw a significant increase in our net income this period for the same reasons that we just went through on the funds flow. But also impacting net income is various non-cash items. So the big one being foreign exchange, we had a foreign exchange gain this period of about 900,000 US compared to a loss of 2 million last quarter. So that's a swing in net income of 2.9 million. And then offsetting that is higher depletion with the higher production and then higher finance expense and then overall current and deferred tax as well. Moving on to the balance sheet, this chart shows our working capital, including cash balances. We go back to when we started natural gas sales in Q3 of 2020. And this is our working capital balance at the end of each period. A reminder, we are debt-free and have been since we repaid our initial credit facility back in fully repaid by September of 2022. This quarter, our working capital was 9.7 million, including cash of 17.3 million. So still very strong. Working capital and strong balance sheet, which positions us well going forward. We did see a decrease in our working capital. We had capital projects running in both Canada and Brazil. So our CapEx was higher this quarter, but overall still very strong balance sheet.

Right, thank you, Alison. So as we announced previously with the increase in production that we saw in Q1, we did make the decision to increase the dividend to 10 cents US per share for Q1. Everyone should have received that already. And what that does is it brings up the total amount of dividends that we've paid since we've started paying dividends in Q3 of 2021 up to US $1.50 per share. That dividend translates into a current yield of over 10%. So as hopefully most of you know, we've been following this, in our opinion, a more balanced and disciplined capital allocation model of reinvesting roughly half of our cash flows in organic growth and then taking the other half and returning that to stakeholders. A reminder at the beginning of the project, all the various shades of green are the returns to stakeholders in the bars. To start with, sorry, all the cash inflows each quarter are denoted by the black dots on the green line here. As Alison noted, we had an increase up to $9.2 million US in Q1 of 2025. Um, over the life of the project, you can see all the different cash outflows each quarter of the stacking bar. So the green are the, are the stakeholder returns. Like Alison said, we, uh, repaid the debt on an accelerated basis. We then introduced the dividend and more recently in yellow, you've seen, um, you know, more investments, uh, in our organic growth. And in particular in Q1, like Alison noted, uh, we had drilling projects happening in Brazil. as well as our first two earning wells on the project in Western Canada. So certainly a higher spending period for us. In total, since we've come on production from Cabaret, we've now generated just under $173 million of fund slope from operations. 47% of that's been reinvested. 48% has been returned to the various form of stakeholders. and the remaining roughly 5% is the portion where we build cash and working capital for future financial flexibility.

All right. We've established a strong platform and now our focus is firmly set on our next growth objectives. Our near-term target is to be at 18 million standard cubic feet or 3,000 BOE per day and fill our current gas plant to capacity to maximize the revenue from these strategic assets. And our long-term vision is to double this with the growth plan to come from our existing land base. So the field on the south, our core field of operations, which is Cabaret, has been performing quite well over the last five years. And we're looking forward to expanding this unit capacity with the addition of five development wells that we expect to start this quarter. But our biggest growth opportunity is set to come from our Merc 2-2 field, which is the field to the north of that. And this is our larger land base. It's 5,500 acres of mapped gas resource. GLJ is assigned a combination of 2P reserves, contingent and prospective reserves to this opportunity. Our 2P reserves alone are 4.1 million barrels of oil equivalent. So we're looking to migrate this reserve base into production and cashflow in support of our longer term growth objective. So I just want to talk a little bit more about about America to do in this in this project, so this is 100% of a petrol working interest it's a multi zone gas play, both in the gomo and the chorus you formation. And like I said this project leverages on our existing infrastructure, so our existing sales point everything is pipeline connected to our gas processing facility. We've utilized 3D seismic to plan this field development, and right now it's allowed us to target the Takara-Rosu formation, which is the focus of our development in the short term. So our most recent drilled well, which is 183A3, which is the well log that you see on the right, we encountered 128 meters of net pay. 116 of these meters were in the Takara-Rosu formation, or four sequences, which is shown on that well log. When we brought it on production in September, we had over 2 million cubic feet per day of gas flow rates was significantly above our expectations. In April, we just completed a work over to this well to isolate some lower sections of the reservoir, which were flowing water, and we've now brought it back online and are flowing and recovering the completion fluids with the gas. Currently, we're drilling a well which is the white dot you see on the map there. It's called 183D4 and this is targeted to be 100 meters up dip of the A3 well. We've had some operational setbacks and we're currently drilling a sidetrack after we became differentially stuck in a certain portion of this reservoir. The portions of the reservoir that we had drilled previously to becoming stuck were very encouraging, showed good sand development and velocity, which may or may not have led to this differential sticking issue. Our team remains focused on ensuring we execute the finalization of this project effectively. And we look forward to logging and casing this well so we can take these geological results and plan the future wells in this Turo-Su structure.

All right, thank you, Adrian. So, moving on to the strategic entry into the Western Canadian Sedimentary Basin that we announced on February 5th. Our initial focus area here is the Manville Stack, which sits on the eastern side of Alberta and on the western side of Saskatchewan, just south of Lloyd Minister here is where we're located. It's a multi-zone. Depending on where you're at in the play, you can sometimes get several of these sands. but there's eight different zones depending where you are. Very good porosity, so you end up with an awful lot of original oil in place on a per square mile basis, even if you're only talking about a three to five meter sand. With that excellent reservoir quality, you can pack a lot of oil in place in a small area. One of the things that we're doing here, this graphic just shows you the evolution of the technology that's been deployed into this resource. Historically, if you were to develop, say, a quarter section of land using vertical wells, you would have had to drill 32 wells into that quarter section that you see on the left-hand side. Then if you would have used horizontal wells, you'd drill roughly four of them to access the same amount of reservoirs. And now what's being widely deployed, and we successfully deployed this with our first two wells, is you drill into the target formation and you get roughly horizontal at that stage. That's the intermediate casing point. You run casing and then you drill out of that and you drill, in our case, roughly six mile long open hole horizontal legs to maximize your access to the reservoir. So instead of fracking, you're basically getting that access to the reservoir through the drill bit. And we're pretty excited about the first two wells. We've drilled in total those two wells accessed over 15 kilometers of open hole. So like I said, the first two earning wells have been drilled. We've added, in addition to that, we've been adding to the land base. We're now 50% working interest owner in 25 sections of highly prospective land in this play. That's over 7,900 acres of net land to Albo Petro. And, you know, we had some questions, you know, just asking us, okay, well, why Canada and all that. And I just thought I'd walk through kind of the thought process a little bit on this. You know, when we were looking, you know, we're always looking for opportunities to add to our inventory. And, you know, obviously our first priority would be in Brazil to be able to bring additional gas into our strategic infrastructure that we built. The reality when you look in Brazil, Because there's not that many transactions and the ones that do happen tend to be very large relative to our market capitalization and the prices tend to be pretty high. So we'll continue to do that, to be clear. But when we started to look elsewhere, Western Canada really rose to the top for us. We always look for things that have the best combinations of geological prospectivity and fiscal regime. And we also like to be able to apply technology to opportunities that maybe haven't been applied, where it hasn't been applied before. So this was a pretty good fit. We've got low geological risk. And the other thing we wanted to do is kind of contrast the risk profile and timelines that we've got with our Brazilian assets. They're very high rate of return, but the timelines tend to be a bit longer and we do operate in a more challenging service environment. So you'll see from the first two wells that we drilled, we've got an excellent and competitive service environment. The individual well costs are quite low by comparison. And, you know, like I showed you on the previous slide, we can apply leading edge technology to this play. Very strong economics. We've got very short cycle times and rapid payouts. You know, we're targeting under a year payouts. And the other thing is when you look at Western Canada, there's a lot of opportunities. And especially when you see, you know, commodity prices dip down a little bit like we've seen over the last little bit, I think it creates even more opportunities. And we're very well positioned to with our balance sheet and our strong basic cash flow to be positioned to capitalize on those. So the last point I'll make to really maybe resonate this is to put this all in perspective. We signed the farming agreement on February 5th. From that date with our partner, Two locations licensed, two surface land acquisition agreements executed, two separate drilling pads constructed, and two wells drilled sequentially, all drilled, like I said, drilling six legs each, accessing 15 kilometers of open hole. And that was all done within 45 days, and both of those wells were on production by early April. Pretty stark contrast, I would say. And, you know, the other nice thing is both of the wells were drilled under budget. And I would say the early production results were, you know, there's a cleanup period during April as well. The first full month from both wells will be in May. But we're pretty excited about the results. And they're certainly exceeding our pre-farming expectations. And we've got plans to drill up to another four of those locations this year. So with that, you know, we continue to strongly believe that Albo Petro offers an attractive investment proposition no matter what your investing focus is. As Alison highlighted, I think we continue to deliver some pretty strong results with very attractive natural gas prices, industry-leading operating netbacks and margins. Our 41% increase in production in Q1 obviously, you know, continues to deliver some very strong free cash flows and with a clean balance sheet I think that all underpins our more balanced and disciplined capital allocation model that we've got. For value investors, we're trading still at less than our 1P NPVs, about 40% of our 2P NPVs. For yield investors, our quarterly dividend, US $0.10 per share, translates into a yield of over 10%. And for growth investors, I think we've got a very exciting and organically funded capital program this year that I think can unlock an awful lot of value for shareholders, especially when you contrast it to our current enterprise value. So I think we've significantly strengthened our disciplined capital allocation and stakeholder return model by combining our growth inventory in Brazil that's underpinned by our high natural gas prices with a new inventory of attractive oil drilling locations in Canada and in an opportunity-rich environment. So we're certainly looking forward to the capital program this year, and we look forward to updating you as the year progresses. And with that, I think we'll turn it over to the question and answer period. I'll just stop sharing here.

Okay, so we do have a few questions in. Now that Canada operations are online and producing, how will you balance investment decisions between Canada and Brazil?

Sorry, I was just writing up my desktop there. Yeah, so at the end of the day, I think a lot of this comes down to the rates return available in both the prospects. I think it's also important to note we continue to realize extremely strong natural gas prices in Brazil, and we've invested in some highly strategic infrastructure. So there's always going to be a motivation to maximize the value associated with that. I think the reality in Brazil is we do have timelines that are longer. So in my opinion, it's really nice to have a complement of oil drilling locations that can be executed on a quick timeline in smaller individual chunks to complement that. So there'll be a bit of a balance and obviously we'll be watching commodity prices as well.

Okay. On the Canadian side, can you comment on how the Canadian oil sales are contracted and how the pricing works on that?

Yeah, there's, you know, It gets basically bid out every month or for a period of time. And there's roughly six different off-takers that can take it. Typically, the oil is trucked between 20 and 30 kilometers to a delivery point. The oil prices... off of Western Canadian Select. So Western Canadian Select has typically been trading, right now I think it's about $13 US discount to WTI. And then on top of that, between the trucking and some quality adjustments would typically price about $10 Canadian below Western Canadian Select.

And will the off-takers happily take increased volumes?

Yeah, no, that's not a restriction.

Okay. Could you run through the royalty rate payable in Canada and how tax will work on the Canadian assets? So on these particular assets in Saskatchewan, there's a royalty incentive for multilateral wells of two and a half percent. And then there is a gross overriding royalty of an additional 6% that's payable on the Saskatchewan operations. On the tax side, we do have tax losses that we haven't recognized any benefit for from a deferred tax perspective. As of December 31st, that was around 7 million US. So there is a lot of tax pools existing already to offset future earnings. And then obviously these new investments are also deductible going forward for tax purposes. A couple more questions here on Saskatchewan. Is there any other capex above and beyond the approximately 1.3 million US per well in Canada?

Not on a note. Right now, it's really just the drilling completion and equipping costs. Like I said, those first two wells came in under AFE. I think on a development basis, we would, with our partner, both expect those costs to come down probably at least 10% or more.

And do you have any expectation on the operating costs per barrel in Saskatchewan or in Canada?

Yeah, I think, you know, over the life cycle of the well, I think we'd modeled in $20. But I think, you know, it's a function of your oil production rates and your oil cuts. But I think it'll be much lower than that as we start out new productions.

Based on the wells that you have drilled and analog wells, what is the expectation of the average first year production rate for these Manville wells?

Yeah, so on a pre-farming basis, we basically had modeled a type well that came on production between 100 and 120 barrels of oil per day, ultimately targeting expected ultimate recoveries on a per well basis of between 100 and 120,000 barrels per well. And with that, you would be able to generate rates of return, excuse me, approaching 100% and have payouts of less than a year.

Okay. Is there any oil price that would have you reducing your planned additional four wells this year in Canada?

Yeah, obviously we'd be working with our partner to make those decisions. I think these investments make sense regardless, but obviously the oil prices, especially in the first six to 12 months are important to the rates of return. But with the rate production rates, I think they're pretty robust even at current prices.

And at the current forward curve, how many wells do you, are you commenting on how many wells you expect to drill in 2026?

No, we're not commenting on that yet. I think we'll incorporate the results from the program this year and then continue to roll it out. But some of these areas we do have stacked potential and have the opportunity for, you know, wells into multiple formations.

Okay, so just moving on. On Merica 2-2, has there been any success drilling in the deeper formation? Is this still a viable prospect or are you focused on Karasu going forward in Murukotutu?

Yeah, so just talking about the evolution of Murukotutu, I guess the first wells we drilled there were into the GOMO. Our 197 well continues to produce from the GOMO at a pretty consistent rate with the success that we had late last year. at 183A3 in the Karasu. This is a shallower part of the reservoir, and with the rates that we were able to achieve there, obviously we're pretty excited about that, so we're going to prioritize that. The GOMO in that shallower area actually, based on our seismic, thins a little bit, and as we go to the north, the GOMO gets quite a bit thicker, but I would say, yes, that we'll do this in a stepwise fashion and focus on the Karasu first, and then move, you know, further and further down dip into the GOMO as a second phase.

Okay, there have also been a number of unsuccessful wells. What has been learned from these wells?

Yeah, I think the question, this one came in beforehand, the question listed off some of the wells, so I'll just first of all start with sometimes we do get a bit of confusion because Block 183, the eastern part of the block is part of America Tutu. So we have wells with a 183 name that are really America Tutu wells. And then on the western side of that block, we have drilled an exploration prospect. So I'll just break that down. In the list, it listed 183.83. So to be clear, that's a very successful well. That's the well that we completed and brought on production, I think, in September of last year, that really was the catalyst for the Karasu development at Murukutu. So, again, that's very successful. Similarly, 183D4 is the well that Adrian talked about. the white dot on that map. It's the well that we're also drilling into the Karasu Formation south of 183 A3, so up dip about 100-110 meters up dip from that well and is currently being drilled. So carve those ones out. Yes, 183 B1 was one of the wells that was listed. We did, as you recall, have a very high rate test, a natural gas test in the Agua Grande formation, but unfortunately, it was a very small compartment, so we had depletion right out of the gate. We also tested oil from the Sergi formation deeper, but in our opinion, at rates that were probably sub-economic, so it really wasn't a focus for us. The 182C1 well was an unsuccessful exploration. Well, and I would say, you know, hasn't really met our expectations. And as a result, we've been focusing on our natural gas opportunities. And then with respect to, you know, I guess it's probably worth talking about, you know, the EMP business is a risky business. So our chance of success on exploration wells is typically, let's call it 20 to 30%. So we need to keep that in perspective. But we also need to realize that every time we have a success, that leads to ultimately, ideally, a big development and a lot of value that we can create. And we've seen that at both Mercatuju and Karasu. What we do is when we're making these investment decisions, we're trying to use the best information possible. We do all the work we can to try to de-risk the prospects in advance as best we can. We can't eliminate the risk, obviously. Things that we do are like we've reprocessed all the 3D seismic in the basin to a much higher level. standard and and that's one of the tools that we use um and then the other thing we do is you got to make sure you're drilling a portfolio of opportunities so that you're drilling many wells and increasing your overall chances of success and and i think we've done that like i said with our with our as demonstrated by cabaret and murica tutu um the other thing we do is obviously we learn from all the successes and and the the wells that aren't successful and we incorporate those learnings into our future investment decisions. And then lastly, I would say operationally, we do have a continuous improvement culture at Albo Petro. I think we're constantly working with our service providers to try to improve our operations. We look at all of our operational practices and procedures to find improvements. Then we get subject matter experts in when required to really improve the execution of the projects. And the other thing that we've done as demonstrated in 183A3 and with the seismic is we're trying to bring North American ideas and innovations and technologies to bear where they maybe haven't been applied before. So that's a little bit about our approach on that.

Just one follow up on that. Would it be worthwhile to contract a more expensive drilling contractor in the market to access drilling and services expertise? Has that been a consideration?

Yeah, no, for sure it is. And every time we do a drilling project, we go out for a request for proposal, we get all the bids in possible and we're evaluating, you know, price is just one small component of that evaluation. The quality of the equipment and all that is a massive part of the selection. So the reality is, you know, we don't have as many choices as we would in Western Canada. So we have to you know, work with our service providers. There's other companies in Brazil that have taken, you know, things into their own hands and built their own entire service businesses, which, you know, in some cases, I think leads, you know, there's an example of one of our peers in Brazil that's done that. And I think they've got some good quality equipment. They've also got 15 or 1700 employees that are managing that business. And You know, the other reality is, you know, if we had a more continuous drilling program, it does help with that. So, you know, our reality is, you know, we've got a little bit more of a lumpy drilling program. So we just need to try to manage that as best as possible.

Okay, just moving back on Brazil here. Can you clarify the expected Brazilian royalty going forward? So as I mentioned that the Q1 had included some historical documents Royalty adjustments, so hence it was about 11.9% effective royalty rate in Q1. Going forward, ultimately, it'll depend on forecasted commodity prices, but we're forecasting more like 5% to 6%. Back to Canada, do you have a set WTI price that would be required to hit payback in 12 months?

Yeah, so that was basically at the economics that we ran when we entered into the farming, so we were probably closer to $70 WTI.

And then on the corporate side, to what extent would major players in Brazil be interested in acquiring your Brazilian assets?

Yeah, well, it's hard to speculate on that, but I think we built a pretty impressive platform and, you know, we have some highly strategic midstream infrastructure and a very attractive gas sales agreement. So, yeah, no, I would think that's attractive, but, you know, we don't, you know, think too much about that. We try to focus on the business and making sure we're growing the business and adding value for shareholders.

Okay, and with that, we have no further questions.

Alright, well thank you everyone for attending. If you've got any questions after the fact, feel free to give any of us a call and again we look forward to doing this again in three