Alvopetro Energy Ltd.

Good morning. Thank you for joining us for our Q4 earnings call. And before I get started, I'm Corey Rakam, President and CEO. On my right is Allison Howard, our Chief Financial Officer, and on my left is Adrienne Adet, 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've dialed in, you can send any questions to socialmedia at elbowpetro.com. 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. So, 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, you know, 2025 really was an exceptional year for Alvo Petro. I think if you look at year over year, our production growth was about 41% to average 2,500 and 23 barrels of oil equivalent per day. And then with the strength of the 183D4 well on our 100% owned Merck 22 asset, it really helped us exit the year quite strongly. We recorded record production in the fourth quarter of 2025. up to nearly 2,900 barrels of oil equivalent per day. And that was up 22% from the third quarter. And 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. And 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. And 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.

Okay, so just going through some highlights from our results that we released yesterday. Starting with our operating net back, that's a non-GAAP measure. It's a measure of our operating profitability. We measure it in per barrels of oil equivalent. So just as a reminder, how we compute that is 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 net back. So, you'll see this quarter our operating net back was down $6.20 from last quarter. Basically, all of that was due to a reduction in our realized sales price, so 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. And then we did have a small discount on interruptible volumes or those volumes above our firm contracts. So 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. 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, so 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 our full month of higher MERC 2-2 production and some personnel added for MERC 2-2, 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 VOE were lower. So overall, that translated into the operating net back of $49.70. And when you compare that to our realized price of $59.75, that's an operating net back margin or profit margin of 83%, which Again, you know, we would argue is top tier relative to other tiers operating in Canada and internationally. And then when we layer in in Brazil, as a reminder, we are eligible for a tax incentive that reduces our effective rate to 15.25%. And also in Canada, we have sufficient tax pools such that we don't have tax in Canada at this time. You know, we have a relatively low current tax expense, and that allows us to generate significant funds flow from operations. So on that note, funds flow from operations is cash flow from operating activities before changes in working capital. So this chart just shows the change from Q3 of 10.4 to Q4 funds flow of 10.6 million. So 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 flowed for the quarter of $10.6 million and for the year was $40.6 million. Oops. Sorry. 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 U.S. compared to Q3. Most notably, Q3, we did have an impairment charge on some assets that were transferred to Health for Sale. So, without any impairment in the quarter, that was a difference of about $1.9 million this quarter. And then higher overall foreign exchange losses this quarter compared to last quarter and higher deferred tax. So overall net income of $5.6 million. So 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. And then the orange line is our credit facility or our debt balance. So 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. That was basically, you know, we did see, following on the success of our 183D4, 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. So we'll talk about those capital plans a little bit more coming up here. But overall, that loan bears interest at 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 its 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.

So, yeah, in 2025, we paid quarterly dividends at – And then in the fourth quarter, as you recall, we added a $0.02 special dividend. And then just yesterday, we announced our Q1 dividend at $0.12 per share U.S., and that represents a yield of 8%. So 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. So 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 is basically to take half of our funds sold 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. it to a rapid acceleration of the repayment of the initial private 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 operation. So as Al of about $10.6 million. And 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 of AIM Cabaret, about 52% of our funds flow has went into reinvestment and 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 183D4 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 12.5 years at our Q4 production rates. with an F&D cost of $15.4 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 Mercatutu field. We have contingent and prospective resources associated with the GOMO formation outside of our well control. Excuse me. 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. And 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. So our near-term operational objective is to improve the Mercatutu field gas egress to 600 E3M3 a day, or 21.2 million centicubic feet per day, and to maximize the gas plant capacity and flexibility. As we build out the productive capacity of the resources assigned to our core 100% owned Mercatutu project, we have a large multi-year opportunity to unlock. So I'm just going to go through a little bit more detail on the immediate projects that we're focusing on for 2026 in Mercatutu. So 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 we have done. And now we're focusing on expanding this infrastructure to meet the expected capacity of the wells. So 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 up-dip locations, the proved locations in our reserve reports in the Karawasu structure. square there. Then we're also going to increase the capacity of the Mercatuju hub. And 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. And then further down the pipeline, we have to increase the actual egress from Mercatuju hub to the Cabaret hub. Currently, there's a four-inch pipeline and we're looping it or adding in the same pipeline right away, 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, and it's called the D1 well, which you can see in that white dot, and a recompletion at improvements. So then we will focus on the drilling from the G pad on those uptick locations at the Curah Sioux structure. And then from 2028 and beyond, we will continue the development of both the Curah Sioux structure as well as the GOMO reservoirs, which are all highlighted in our reserve and resource reports. So we also have a midstream project at the UPGN Cabaret for 2026. So 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 Merck 2-2 gas, which is richer than the Cabaret gas. So the target capacity of this immediate project is an overall gas rate of 600 E3M3 a day. but will allow up to 300 E3M3D of Mercotube tube gas blended with our Cabaret 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% BRCA2 gas, which we expect this project to require additional fractionation and product streams, given the heat content from the BRCA2 field.

Thank you, Adrian. So as we've talked about in the past, I think early in 2025, we announced our strategic entry into the Western Canadian Sedimentary Basin. And then later in the year, we announced that we expanded our AMI. So it now covers this green dashed area, which pretty much covers the entire Saskatchewan side of the Manville Stack Heavy Oil Play Fairway area. 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, so 80 square miles of highly prospective land. We've now got seven gross 3.5 net wells on production. And the reserves that Adrian mentioned, 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, but we see a much broader opportunity those 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 approved plus probable type curves that GLJ established for three of our core areas. to 180,000 barrels per location. And if he was 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, so 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 Elvel Petrol with another strong growth platform as we look forward. So, just to conclude, like I said, 2025 really was a transformational year for Alvo Petrol. We continue to deliver some pretty strong results. Obviously, we benefit 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 locally year-over-year production growth of over 41%, have 2P reserve growth even after 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. And then, you know, 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 updated 2P NPVs. For yield investors, that 12 cent per share quarterly dividend that we just declared translates into a yield of about 8%. For growth investors, I think has the ability to unlock an awful lot of value for shareholders, especially when you consider the potential relative to our current enterprise value. And I think we've significantly strengthened our capital allocation stakeholder return model by combining growth opportunities in Brazil that for success are better than ever, and combine that with the deep inventory of open-hole multilateral locations that we've got in Canada. As I noted, we exited 2025 with record quarterly production. in the Q4 record monthly production in January. And like I said, if we can continue those January and February production levels, you know, 2026 will look like close to another 25% uptick relative to last year. So you consider we were up 41% year over year. Last year, that would be, in my mind, two successive years of pretty exceptional results. So 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?

So, I'll start with, we may 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 183D1 well, and it's mobilizing to location as we speak. From a credit facility standpoint, what we did want to do is, 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. You know, 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. And you're going to see, you know, to date we actually haven't used a lot of that, but with the increase higher commodity prices here. Our activity levels in Canada are really a function, you know, those returns are highly sensitive to oil prices, so we also want to have the flexibility of being able to ramp up that program as needed as well.

Okay, we have a number of questions around the Merck 2-2 expansion, so I'll try to get through all of those around the same time here. Can you provide further details regarding the timing of the MERC 22 infrastructure expansion and whether those steps, did those occur in steps or all at once?

Yeah, there's certainly steps associated with that. take the full amount of 2026. And there's a subject to pipeline permitting at the looping of the pipeline. So we do expect it to take all of 2026.

Okay. There is a question maybe just to reiterate on whether the timing of the expansion of the MERC 22 to the 600,000 ties in exactly with the estimated timing of the Q3 UPGN cabaret and And, no, you expect to have the UPGN cabaret expansion still be working on MERC 22.

Yeah, build other projects, and then there's drilling projects that will fall along the facilities projects.

Yeah, and maybe just elaborate. So the gas plant expansion will give us more flexibility to handle increasing components of MERC 22 gas, which, you know, 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 MERC 2.2 expansion happens. But the big kind of four-fold increase in MERC 2.2 takeaway capacity is timed closer to the end of the year.

Okay. There are some questions around still in the MERC 2.2 expansion, what are the biggest execution risks? whether technical infrastructure or regulatory, that could slow that ramp up?

Well, I noted that, you know, 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, which are, you know, there's always a timing risk on that. And then collecting a drilling rig and timing of these things is always a risk within the operating areas of Brazil. So probably the biggest ones I'd highlight.

Yeah, I think the nice thing is we're dealing with an existing, highly qualified contractor, Enerflex, who is a leader in kind of this gas plant technology. They did one minor expansion for us before. They've always delivered on time, so at a high confidence level in that. The benefit, I think Adrian noted to it, we're actually following existing pipeline right-of-ways that does help simplify the process. There's always risk, obviously, but that certainly kind of helps.

So still on the MERC 22 front, on the drilling plan, can you comment how many total wells will be drilled on the field this year?

Yeah, well, 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 facility's 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. The drilling up dip off of the G-pad, you know, that G-pad is, you know, in the permitting expect that fairly soon and then we've got a call it two to three month civil project to get that drilling pad ready and then at that point we'd also have the flexibility to be drilling off of off of those pads but we just you know we want to make sure that we're timing that um you know with you know relatively consistently with the facilities projects as well

So on the expansion to 600,000 cubic meters a day with MERC 22, do you expect to utilize all of that capacity?

Well, yeah, I know that's what we're ramping up towards. You know, 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. And then with that capacity increase, so 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% approximately increase in that year. And then, yeah, no, that's absolutely our target.

Okay, can you comment on the price you receive for your non-firm or interruptible or flexible volumes in Brazil?

We haven't been commenting on that only because, you know, We're respecting the confidentiality of our contracts, but, you know, we are working on our kind of gas sales portfolio. I think, you know, 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 that will take you based on current futures curves?

Yeah, so maybe just a little bit of a reminder how our contract now works quarterly. So on February 1st, we had a price reset that we've Rehub and Brent under our main contract the next price reset that happens on May 1st will be the first time that the Q1 benchmarks get used so I think we already so with Q1 that the rest of the month of March matches the futures curve that you see in the market today we would expect so 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 and a reminder about 80% of our volumes are currently being sold under that contract

Um, maybe we can jump to our CapEx budget for 2026. Uh, there's some questions if we can provide further details on, on what our CapEx budget is overall for 2026. So we did release as part of our reserves release, we did release our CapEx budget, um, in Brazil, all of those projects that we went through focused on the facilities expansion and that first, um, additional well at Merck Tutu. I believe that was 21 million was the number that we released. Yes, and then in Canada, there are some additional follow-up questions in Canada. So, we did drill the first or the last two wells, the most recent two wells in January. So, those costs were around 2 million, I believe, 2 million Canadian. And 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.

Yeah, like I mentioned, a lot of that is commodity price driven. We're also working with our other 50% working interest partners, so we'll be – I'm pretty confident we'll be implementing an additional drilling program here as the year progresses. And on a net basis, each of those wells cost us about a Canadian $1 million.

And how are you financing your capital budget in 2026?

Yeah, so 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 plans, take advantage of higher prices that we're seeing right now, or do you plan to accelerate anything given the high price environment?

Yeah. So the good news in Brazil is we had way better than expected success on this 183D4 well on our America 22 project in the Carraçu Formation. Then as a result of that, we're responding by significantly expanding the fuel takeaway capacity as Adrian walked through. You know, the reality is we need to work through those projects, time additional drilling to build productive capacity, all of that together to, you know, solidify the increases we're already seeing and set ourselves up for next year, another increase in moving into next year. uh probably so more more relevant would be the in the western canadian assets i think you know 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 one inventory of locations so 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?

Yeah. Well, I think at current oil prices, if you assume 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 Elbow get for oil in Canada? So our pricing in Canada is at WCS pricing. There's a small discount to that, but WCS pricing, which is Canadian dollar pricing. Yeah.

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

Okay, so you've outlined a 50-50 capital allocation between growth and shareholder returns. With the Planmerk 2-2 expansion and strong oil results, under what conditions would you shift the balance, either accelerating growth or increasing the dividend further?

Yeah, so ultimately the dividend decisions are made with our board of directors as well. But, you know, 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, you know, given that financial flexibility that we have. That's certainly the way that I look at it.

So a couple of things on Canada, just a couple questions. Anytime we express our share of reserves or production, that's Alvo Petro shares, so that's net to Alvo Petro. 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? So that's all trucking, clean oil trucking. the transportation costs. So it's all truck, nothing via pipeline at this time. All right. A couple questions around some legal matters. Do you have any visibility of the timing of the cabaret arbitration?

No. Well, I think if we go strictly by the timeline, we would expect an outcome sometime in the middle part of this year. But, you know, these processes sometimes take longer than initially projected. So I'm hesitant to fix it at an exact time.

On Cabaret, 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?

Yeah, there's a provision for that in our unit operating agreements based on the recovery of gas relative to the total amount of gas to be recovered from the field, and so the timing of that's really a little bit of a function of how much production is coming from Cabaret, which is partly a function of how much dispatch our partner has at their thermal electric power plant. Long story short, we from today.

And 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?

Yeah, well, 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 costs, 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. So 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 of those opportunities right now.

And there's another question here on capital expenditures. When do we expect those to peak in 2026? When do we see the most activity?

Yeah, the lumpiest activity is associated with the drilling project on our 183D1 well. So, like I said, the rig's mobilizing now. You won't start to see, you know, concrete costs really until we get into Q2 here. But, you know, yeah. to that project. And then the facilities projects, you know, are probably ramp up, you know, more as we move through the year.

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