...and on my right is Alison Howard, our Chief Financial Officer, and on my left is Adrian Audet, our Vice President, Asset Management.

Good morning, everyone. Just a few administrative points before we start.

We will be recording today's call, and we will have a replay available on our website later on this afternoon. All attendees are placed in listen-in only mode for the duration of the call.

We will have a Q&A session at the end of our presentation, and you can start logging any questions you have now using the Zoom Q&A portal that you should see on your screen if you're logged in on Zoom. If you dialed in, you can send any questions to [email protected].

Lastly, we do go through various non-GAAP measures and some oil and gas metrics, and we do make forward-looking statements throughout our presentation. I do encourage everyone to read all of the cautionary statements and various disclosures that we have both in our MD&A that was released yesterday as well as in our corporate presentation.

It's in the last few slides of our corporate presentation that's on our website.

All right. Thank you, Alison.

So, 2025 really was an exceptional year for Alvopetro. I think if you look at year-over-year, our production growth was about 41% to average 2,300—sorry, 2,523 barrels of oil equivalent per day.

Then with the strength of the 183-D4 well on our 100% owned Murucututu asset, it really helped us exit the year quite strongly. We've recorded record production in the fourth quarter of 2025 up to nearly 2,900 barrels of oil equivalent per day.

That was up 22% from the third quarter. Something to note is, in the orange bar that you see on the graph there, it did include 148 barrels of oil per day from our Canadian assets that we added last year.

Then to note, 2026 is off to an extremely strong start for us. We posted a record monthly production number in January of close to 3,100 barrels of oil equivalent per day.

If you look at the January and February average, if you projected that through just even assuming that that stays at that level through the year, averaging over 3,000 barrels of oil equivalent per day, that would be up over 22% from the 2025 average levels that we had last year.

Just going through some highlights from our results that we released yesterday, starting with our operating netback. That's a non-GAAP measure.

It's a measure of our operating profitability. We measure it in per barrels of oil equivalent.

Just as a reminder how we compute that, at the top of those bar charts, we start with our realized price, deducting off royalties, which is the orange bar, and then we've combined production expenses and transportation expenses in the gray bar, and then the green bar is our operating netback. You'll see this quarter, our operating netback was down $6.20 from last quarter.

Basically, all of that was due to a reduction in our realized sales price. Our overall realized sales price was $59.75 per BOE.

That included natural gas sales of $9.97 per Mcf. Overall, our contracted price on our firm volumes, which was about 80% of our volumes in the fourth quarter, that was actually down marginally compared to the prior quarter.

Then we did have a small discount on interruptible volumes, or those volumes above our firm contracts. Overall, our realized price was down about $6 compared to last quarter.

On the royalty side, our effective royalty rate this quarter was 6.4%, with 6% of that in Brazil and 15.8% effective rate in Canada. Brazil rate was marginally higher than last quarter.

Just Brazil, the majority of our royalties on our natural gas are based on Henry Hub pricing, and Henry Hub was higher in Q4 compared to Q3, our overall rate was marginally higher that quarter, but on a per-BOE basis overall, there was a decrease there. On the production and transportation expenses, which is the gray bar, we did see an increase overall in the dollar amount of our operating expenses, so that was up about $275,000 from last quarter, with a full month of higher Murucututu production and some personnel added for Murucututu, as well as higher overall costs in Canada with more wells on production on average in Q4 compared to Q3.

Our costs were higher, but with that higher production, that 22% increase in production, our costs per BOE were lower. Overall, that translated into the operating netback of $49.70, and when you compare that to our realized price of $59.75, that's an operating netback margin or profit margin of 83%, which again, we would argue is top tier relative to other peers operating in Canada and internationally.

Then when we layer in Brazil, as a reminder, we are eligible for a tax incentive that reduces our effective rate to 15.25%. Also in Canada, we have sufficient tax pools such that we don't have tax in Canada at this time.

We have a relatively low current tax expense, and that allows us to generate significant funds flow from operations. On that note, funds flow from operations is cash flow from operating activities before changes in working capital.

This chart just shows the change from Q3 of $10.4 million to Q4 funds flow of $10.6 million. Roughly just over $0.1 million increase from last quarter.

Most of that again was due to that 22% increase in sales volumes. Partially offsetting that was lower realized price and then the higher royalties and production expenses that I talked about on the last slide.

Our G&A was also marginally higher in Q4 with final year-end adjustments. Overall, our funds flow for the year of or for the quarter of $10.6 million, and for the year was $40.6 million.

Similarly, on net income, so that was impacted by the positive funds flow that we saw. We did have an increase in our net income of just around $1 million US compared to Q3.

Most notably, Q3 we did have an impairment charge on some assets that were transferred to held for sale, without any impairment in the quarter, that was a difference of about $1.9 million this quarter. Then higher overall foreign exchange losses this quarter compared to last quarter and higher deferred tax.

Overall, net income of $5.6 million. On the balance sheet front, this chart shows our working capital, which is current assets less current liabilities in the green bars that you see.

Then the orange line is our credit facility or our debt balance. As a reminder, we previously had a credit facility balance that was fully repaid by the third quarter of 2022, and then we were debt-free for a number of quarters.

At the end of November, we entered into a $20 million loan agreement. Following on the success of our 183-D4 well, this $20 million loan will provide us with additional financial flexibility going forward to the extent we're accelerating any of our capital plans in Brazil or in Canada.

We'll talk about those capital plans a little bit more coming up here, but overall, that loan bears interest at 7 7%, and we do have repayments of that loan starting at the end of 2026. So $4 million of that loan is actually netted in our working capital balance of $18.5 million.

If you look at it, working capital net of debt, it's a balance of $2.5 million as of Q4 2025, or as of December 2025, which is relatively consistent with September 2025.

In 2025, we paid quarterly dividends at 10 cents per share, and then in the fourth quarter, as you recall, we added a 2 cents special dividend. Then just yesterday, we announced our Q1 dividend at 12 cents per share US, and that represents a yield of 8%.

If you look at it since inception, since we started the dividend in the third quarter of 2021, we've now declared over $70 million US in dividends to shareholders, which represents just shy of $2 US per share, pretty proud of this. We've talked about this a lot.

This is the more disciplined capital allocation model that we introduced before we came on production from our core project. The model's basically to take half of our funds flow from operations and reinvest that in organic growth and take the other half and return it to stakeholders.

We've reviewed this quite a bit. Early on, as Alison noted, a big portion of the stakeholder return portion went to a rapid acceleration of the repayment of the initial project financing loan that we had.

Then we introduced the dividend in the third quarter of 2021, as I noted. The green bars here with the black dots represents the funds flow from operations.

As Alison noted, we had Q4 funds flow of about $10.6 million. Then you can see the split in yellow between what was reinvested and what was returned to stakeholders.

If you look at the pie here on the right, since inception of our production in Caburé, about 52% of our funds flow has went into reinvestment, and then 48% of it has been returned to stakeholders over time.

Three weeks ago, we released our annual reserves report. Our 2025 year-end reserve report reflects the great results we've seen at the 183-D4 well.

We saw increases in all reserve categories with the production replacement ratios of 485% and 530% for 1P and 2P respectively. Our 2P reserves life index is 12 and 1/2 years at our Q4 production rates with an F&D cost of $15.40 US per barrel and recycle ratios of over three times.

We've also updated our contingent prospective resources report. These reports highlight the large resource we have identified in the Murucututu field.

We have contingent and prospective resources associated with the Gomo Formation outside of our well control, as well as prospective resource report in the Caruaçu zone, which is just adjacent to the assigned reserves area we have that is our current focus. We continue our focus on converting these resources and reserves into production and cash flow.

We've established a strong gas production platform in Brazil. Now our focus is set on the development of the reserves and resources we've highlighted in the previous slide.

Our near-term operational objective is to improve the Murucututu field gas egress to 600 e3m3 a day or 21.2 million standard cubic feet per day and to maximize the gas plant capacity and flexibility. As we build out the productive capacity of the surface facilities and pipeline, we plan to continue our drilling and completions projects to increase the productivity from the field.

With the combination of reserves and resources assigned to our core 100% owned Murucututu project, we have a large multi-year opportunity to unlock. I'm just going to go through a little bit more detail on the immediate projects that we're focusing on for 2026 in Murucututu.

Regarding our facilities projects, and just to remind everybody, our initial facility at this field was built with a capacity of 150 e3m3 a day to prove the productive capacity of this reservoir, which we have done. Now we're focusing on expanding this infrastructure to meet the expected capacity of the wells.

Our first steps are building and constructing a G location, which will allow us to drill up to four wells from this pad and reach the updip locations, the proved locations in our reserve reports in the Caruaçu structure. This G pad will also be pipeline connected via this white line here to the Murucututu hub, which is that red square there.

Then we're also going to increase the capacity of the Murucututu hub. To do this, we need to add larger separators, larger pressure relief, flare stack, and some other processing components so that we can process up to 600 e3m3 a day at this field battery.

Then further down the pipeline, we have to increase the actual egress from Murucututu hub to the Caburé hub. Currently, there's a 4-inch pipeline, and we're looping it or adding in the same pipeline right-of-way an 8-inch pipeline, which will increase the capacity of over 600 e3m3 a day.

We're also planning a development well for 2026 at the D pad. It's called the D1 well, which you can see in that white dot.

A recompletion at the 183-1 well, which is located at the Murucututu hub. From 2028 and be- or sorry, for 2027, we'll be done these facilities improvements.

Then we will focus on the drilling from the G pad and those updip locations at the Caruaçu structure. Then from 2028 and beyond, we will continue the development of both the Caruaçu structure as well as the Gomo reservoirs, which are all highlighted in our reserve and resource reports.

Down, we also have a midstream project at the UPGN Caburé for 2026. The short-term plan is to optimize the processing capacity of the gas plant or UPGN to improve our ability to process increased amounts of Murucututu gas, which is richer than the Caburé gas.

The target capacity of this immediate project is an overall gas rate of 600 e3m3 a day, but will allow up to 300 e3m3 a day of Murucututu gas blended with our Caburé gas. This project has been initiated with our facilities partner, Enerflex, and we expect this to be online by the end of Q3.

We're also working on a medium-term plan to adapt the plant to handle 100% Murucututu gas, which we expect this project to require additional fractionation and product streams, given the heat content from the Murucututu field. All

right. Thank you, Adrian.

As we've talked about in the past, I think early in 2025, we announced our strategic entry into the Western Canadian Sedimentary Basin. Then later in the year, we announced that we expanded our AMI.

It now covers this green-dashed area, which pretty much covers the entire Saskatchewan side of the Mannville Stack heavy oil play fairway, where we're looking to deploy leading-edge drilling technology using open-hole multilateral drilling. Last year, we finished drilling all of our earning wells, and we've added further to that land base.

We now have over 80 sections, 80 square miles of highly prospective land. We've now got seven gross, 3.5 net wells on production.

The reserves that Adrian walked through earlier, for the first time, actually included some of the reserves from our Canadian assets here on a 2P basis. We've booked 735,000 barrels of reserves.

That did include eight gross, or four net, undeveloped locations based on the initial well spacing that we have. We see a much broader opportunity here with over 100 gross, 50 net Tier 1 drilling locations in our inventory.

On this slide, we just show where that Tier 1 inventory sits relative to the booked locations that GLJ, our independent reserve evaluator, assigned in the table on the top right here. On the graph that you see, these are the three proved plus probable type curves that GLJ established for three of our core areas, ranging between 100,000 and close to 180,000 barrels per location.

If you assume, obviously commodity prices are moving wildly, but if you assumed even a flat WTI $70 per barrel price, the economics associated with drilling these wells range between 50 and over 130% IRR. Quite attractive.

We're extremely happy about this Western Canadian entry that we've got. I think we had a great start on this asset in 2025, and it just provides Alvopetro with another strong growth platform as we look forward.

Just to conclude, like I said, 2025 really was a transformational year for Alvopetro. We continue to deliver some pretty strong results.

Obviously, we benefit from from high realized gas prices, industry-leading operating netbacks and operating netback margins. I think in particular, when you consider that we returned over 45% of our funds flow from operations to stakeholders in 2025, and we were still able to generate year-over-year production growth of over 41%, have 2P reserve growth even after the the close to million barrels of production that we had last year of 43%, and considering we replaced that production over five times from a reserve perspective, I think it really was an exceptional year for us.

We do have very strong free cash flow generation capacity, and that really helps underpin that disciplined capital allocation model that I talked about. Then, from an investment thesis perspective, we really do feel like this is a value, yield, and growth story that continues.

We're trading at just over 55% of our 2P our updated 2P NPVs. For yield investors, that 12 cents per share quarterly dividend that we just declared translates into a yield of about 8%.

For growth investors, I think we've got an extremely exciting capital program that that has the ability to unlock an awful lot of value for shareholders, especially when you consider the the potential relative to our current enterprise value. I think we've significantly strengthened our our capital allocation stakeholder return model by, combining growth opportunities in Brazil that, I think based on the 183-D4 success are better than ever, and combine that with the deep inventory of of open-hole multilateral locations that we've got in Canada.

As I noted, we exited 2025 with record quarterly production in Q4, record monthly production in in January. Like I said, if we can continue those January and February production levels, 2026 will look like a close to another 25% uptick relative to last year.

You consider we were up 41% year-over-year last year. That would be, in my mind, two successive years of of pretty exceptional results.

Pretty happy with where we are, and with that, I'll turn it over to the question-and-answer period.

Sure, we've got a few questions in. Can you comment on what the $20 million loan proceeds were used for?

Did we purchase new processing facilities, or did we lease those? Do we own our drilling rigs, or do we lease them?

We work backwards. The drilling equipment, no, we would rather stay out of that business and have service providers provide those services.

We do have some peers in Brazil that take a different approach. We have contracted a new drilling rig for the upcoming drilling program that Adrian spoke about for that 183-D1 well, and it's mobilizing to location as we speak.

From a credit facility standpoint, by the end of last year, we wanted to put in place this facility. It was I think a pretty good opportunity to add flexibility at a relatively low cost, given the evolution of our business.

A 7% loan seemed like a smart thing for us to do, and it just creates a lot more flexibility on the timing at which we can deploy our capital program through this year. You're going to see, to date, we actually haven't used a lot of that, but with the increase in capital activity through this year and potentially with higher commodity prices here, those returns are highly sensitive to oil prices, we also want to have the flexibility of being able to ramp up that program as needed as well.

We have a number of questions around the Murucututu expansion, I'll try to get through all of those around the same time here. Can you provide further details regarding the timing of the Murucututu infrastructure expansion and if those occur in steps or all at once?

There's certainly steps associated with that. We're basically bottlenecked at a lot of different spots at the same time right now, just due to the initial build-out of Murucututu.

The pipeline needs to be expanded, which is a project in itself. The field facility needs to be expanded, pads need to be tied in, and the UPGN needs to be expanded.

I did note that the UPGN is expected to be done at the end of Q3, but those other projects are going to take the full amount of 2026, and they're subject to pipeline permitting at the looping of the pipeline, it's expected to take all of 2026.

There is a question, maybe just to reiterate, on whether the timing of the expansion of the Murucututu to the 600,000 ties in exactly with the estimated timing of the Q3 UPGN Caburé, and no, you expect to have the UPGN Caburé expansion, still be working on Murucututu up to the end of the year?

Those other projects, and then there's, yeah, drilling projects that will follow on the facilities projects.

Maybe just elaborate. The gas plant expansion will give us more flexibility to handle increasing components of Murucututu gas, which, for the most part, we've been producing at the 150,000 cubic meters a day range.

We can kind of push that a little bit higher. That plant expansion would give us the flexibility of doing that while the Murucututu expansion happens.

The big kind of fourfold increase in Murucututu takeaway capacity is timed closer to the end of the year.

There are some questions around, still on the Murucututu expansion, what are the biggest execution risks, whether technical, infrastructure, or regulatory, that could slow that ramp-up?

I noted that we are awaiting a permit for our pipeline expansion. This is something we've done before, but it is always a risk in timing.

A large portion of this is surface facilities, there's always timing risk on that. Then as we expand Murucututu, we'll be drilling.

Like Corey mentioned, we're contracting a drilling rig, and timing of these things is always a risk within the operating areas of Brazil, probably the biggest ones I'd highlight.

I think the nice thing is we're dealing with an existing, highly qualified contractor, Enerflex, who's a leader in kind of this gas plant technology. They did one minor expansion for us before.

They've always delivered on time, we have high confidence level in that. The benefit, I think Adrian noted, too, of we're actually following existing pipeline right-of-ways, that does help simplify the process.

There's always risk, as obviously, but that certainly kind of helps.

Still on the Murucututu front, on the drilling plan, can you comment how many total wells will be drilled on the field this year?

Right now we've got a plan for one location. We are making contingency plans that if we're happy with the rig performance, and depending on the pace of the facilities capital projects, we do have flexibility.

Part of the reason that we added that credit facility is if we wanted to continue drilling off of existing locations, we could do that from either the D pad or the 197-1 pad, target some of the prospective area that we've got assigned in our resource reports. That G pad is in the permitting process.

We would expect that fairly soon, and then we've got a call it two- to three-month civil project to get that drilling pad ready. Then at that point, we'd also have the flexibility to be drilling off of those pads.

We want to make sure that we're timing that with relatively consistently with the facilities projects as well.

On the expansion to 600,000 cubic meters a day with Murucututu, do you expect to utilize all of that capacity?

No, that's what we're ramping up towards. We increased our firm sales volumes last year to 400,000 cubic meters a day.

We're producing up to close to 500,000 cubic meters a day today. Then with that capacity increase, if you look at that, that's a 41% year-over-year production growth in 2025, roughly 25% increase again in 2026, and then if we can be up to the 600 capacity for 2027, that'd be another 20 20%, approximately increase in that year.

Then yeah, no, that's absolutely our target.

Okay. Can you comment on the price you received for your non-firm or interruptible or flexible volumes in Brazil?

We haven't been commenting on that only because we're respecting the confidentiality of our contracts. We are working on our kind of gas sales portfolio.

I think roughly right now, even at these higher production levels, about 20% of our gas sales are happening on a spot basis. I think you'll see that show up in our Q1 results.

The vast majority of it's under our base contract.

Can you provide an estimate of what your next Brazilian gas price reset will take you based on current futures curves?

Maybe just a little bit of a reminder how our contract now works quarterly. On February 1st, we had a price reset that we've already announced.

That was using the Q4 commodity prices for Henry Hub and Brent under our main contract. The next price reset that happens on May 1st will be the first time that Q1 benchmarks get used.

With Q1, we're over two well, three quarters of the way through the quarter. If you assumed that the rest of the month of March matches the futures curve that you see in the market today, our price today is $10.75 US per Mcf.

We would expect under our main contract that price to go to about US $11.80 per Mcf with those spot prices. A reminder, about 80% of our volumes are currently being sold under that contract.

Maybe we can jump to our capex budget for 2026. There's some questions if we can provide further details on what our capex budget is overall for 2026.

As part of our reserves release, we did release our capex budget in Brazil. All of those projects that we went through focused on the facilities expansion and that first additional well at Murucututu.

I believe that was $21 million was the number that we released. Yes.

Then in Canada, there are some additional follow-up questions in Canada. We did drill the first or the last two well the most recent two wells in January.

Those costs were around $2 million, I believe, $2 million Canadian. Then maybe Corey, you can comment on future plans in Canada as well.

We haven't included anything else in our budget that we released at the end of February at this time, but Corey can comment further on that.

No, like I mentioned, a lot of that is commodity price driven. We're also working with our other 50% working interest partner.

We'll be looking at it, I'm pretty confident we'll be implementing an additional drilling program here as the year progresses. On a net basis, each of those wells costs us about a Canadian $1 million.

How are you financing your capital budget in 2026?

The most significant chunk of it comes from our existing cash flows, but like we alluded to earlier, we did add that credit facility late last year to give us some additional flexibility.

Can you ramp up production beyond plan to take advantage of higher prices that we're seeing right now, or do you plan to accelerate anything given the high-price environment?

Yeah. The good news in Brazil is we had way better than expected success on this 183-D4 well on our Murucututu project in the Caruaçu Formation.

As a result of that, we're responding by significantly expanding the field takeaway capacity, as Adrian walked through. The reality is we need to work through those projects, time additional drilling to build productive capacity, all of that together to solidify the increases we're already seeing and set ourselves up for next year another increase in moving into next year.

Probably, more relevant would be in the Western Canadian assets. I think, with the drilling that we did last year and early this year, we've really solidified three core areas within our land base and built out a pretty solid Tier 1 inventory of locations.

I think we've got lots of flexibility to increase activity there, and like I said, we'll be working through that with our partner here in the coming weeks and months.

Can you comment on the payback period for the wells in Canada in the current oil price environment?

I think at current oil prices, if you assumed that persisted, they'd be well less than a year. At the $70 price, I don't have those numbers off the top of my head, but I think the payouts would range anywhere between probably a year and 18 months would be my guess, depending on which type curve we're talking about.

What price does Alvo get for oil in Canada? Our pricing in Canada is at WCS pricing.

There's a small discount to that, but WCS pricing, which is Canadian dollar pricing.

WCS is a Canadian heavy oil benchmark price that's quoted. It's generally been between a $12 to $14 US discount to WTI.

Okay. You've outlined a 50-50 capital allocation between growth and shareholder returns.

With the planned Murucututu expansion and strong well results, under what conditions would you shift the balance, either accelerating growth or increasing the dividend further?

Ultimately the dividend decisions are made with our board of directors as well, but with the growth opportunities in front of us and the credit facility that we put in place, we do have the flexibility to go above the 50% number for capital expenditures, given that financial flexibility that we have, it's certainly the way that I look at it.

A couple things on Canada, just a couple questions. Anytime we express our share of reserves or production, that's Alvopetro share, so that's net to Alvopetro.

There was a question about that. There's also a question on the transportation costs in Canada.

Are those pipeline or other forms of transport? Are there any limitations that you see?

That's all trucking. Clean oil trucking is the transportation cost.

It's all truck, nothing via pipeline at this time. Sorry.

Couple questions around some legal matters. Do you have any visibility of the timing of the Caburé arbitration?

I think if you go strictly by the timeline, we would expect an outcome sometime in the middle part of this year, but these processes sometimes take longer than initially projected. I'd hesitate to kind of fix an exact time.

On Caburé, there's also a question about the second redetermination. Any thoughts on when that should be, and how will that work given the first redetermination is still being contested?

There's a provision for that in our unit operating agreement based on the recovery of gas relative to the total amount of gas to be recovered from the field. The timing of that's really a little bit of a function of how much production's coming from Caburé, which is partly a function of how much dispatch our partner has at their thermal electric power plant.

Long story short, we would expect that to be sometime in the kind of two- to three-year range from today. Then

there is also a question about we have those assets that we entered into an agreement to sell, subject to ANP approval. Is there any status update on that?

I think everything's been submitted, and we're just purely waiting for the ANP approval at this time. Okay.

At what point does the Canadian heavy oil asset become material enough to compete for capital with Brazil, and how do you prioritize between the two regions long term?

Again, it's commodity price driven, obviously. At current spot prices, it competes extremely well.

The other nice thing about it is the individual wells, as I mentioned, are relatively lower capital cost, pretty high or quick payouts, and they can be executed. I think every one of these eight-leg multilats that we've been drilling has been completed within a two-week period of time.

There's a lot of flexibility on the Canadian side to ramp up or ramp down activity. I think the nice thing is, with our strong free cash flow generation capacity and the credit facility we put in place, we're not having to make investment decisions at the expense of the other business unit.

We can co-invest in both those opportunities right now.

There's another question here on capital expenditures. When do we expect those to peak in 2026?

When do we see the most activity?

The lumpiest activity is associated with the drilling project on our 183-D1 well. Like I said, the rig's mobilizing now.

You won't start to see concrete costs really until we get into Q2 here, but, yeah, we'll have more capital costs in Q2 related to that project. Then the facilities projects are probably ramp up more as we move through the year.

Great, just looking to see if we have anything else. I think that's it for now.

No further questions.

All right, well, I want to thank you all for attending, and thank you for all your support. If you've got additional questions, feel free to give us a call, and thank you.

Thanks, everyone.