Q4 2025 Alvopetro Energy Ltd Earnings Call

March 18, 2026

Speaker #1: For, Q4, earnings call. and, before I get started, I'm Corey Ruttan, President and CEO, on my right is Alison Howard, our Chief Financial Officer, and on my left is Adrian Audet, our Vice President, Asset Management.

Speaker #2: 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.

Corey Ruttan: Before I get started, I'm Corey Ruttan, President and CEO. On my right is Alison Howard, our Chief Financial Officer, and on my left is Adrian Audet, our Vice President, Asset Management.

Speaker #2: 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.

Alison Howard: 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 info@alvopetro.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.

Speaker #2: But you should see on your screen if you're logged in on Zoom. If you've dialed in, you can send any questions to social media at various non-GAAP measures and some oil and gas metrics, and we do make forward-looking statements throughout our presentation.

Speaker #2: 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.

Alison Howard: 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.

Speaker #1: All right. Thank you, Alison. so, you know, 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, or sorry, 2,523 barrels of oil equivalent per day.

Corey Ruttan: All right. Thank you, Alison. So, you know, 2025 really was an exceptional year for Alvopetro. I think if you look at year-over-year, our production growth was about 41%, average 2,523 barrels of oil equivalent per day. With the strength of the 183-D4 well on our 100% owned Murucututu asset, it really helped us exit the year quite strongly. We recorded record production in Q4 of 2025, up to nearly 2,900 barrels of oil equivalent per day, and that was up 22% from Q3.

Speaker #1: And then with the strength of the 183D4, well, on our 100% owned market to two assets, w it really helped us exit the year quite strongly.

Speaker #1: 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.

Speaker #1: 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.

Speaker #1: 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.

Corey Ruttan: 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. 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 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.

Speaker #1: and if you look at, the January and, 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 that we had last year.

Speaker #2: Okay. So just going through some highlights from our results that we, we released yesterday. starting with our operating net back, that's a non-GAAP measure.

Speaker #2: 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.

Alison Howard: Okay. 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 per barrels of oil equivalent. 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 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.

Speaker #2: 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.

Speaker #2: 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.

Speaker #2: 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.

Speaker #2: 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.

Alison Howard: 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 Q4, 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. In 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.

Speaker #2: 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, so our overall rate was marginally higher that quarter.

Measure of our operating profitability. We measure it in per barrels of oil equivalent. So just as a reminder, um, how we compute that is at the top of those bar charts, we start with our realized price, um, 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. Um, 6.20 cents from last quarter. Um, 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, um, that included natural gas sales of 9.97 per mcf. Um, overall our contracted price on our firm volumes which was about 80% of our volumes in the fourth quarter, um, that was actually down marginally compared to the prior quarter, and then we did have a small discount, um, on interruptible volumes or those small

Speaker #2: 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.

Volumes above our firm contract. 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 a 15.8% effective rate in Canada. The Brazil rate was marginally higher than last quarter—just Brazil. The majority of our royalties on our natural gas are based on Henry Hub.

Alison Howard: Our overall rate was marginally higher that quarter. 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. That was up about $275,000 from last quarter. With our 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. With that higher production, that 22% increase in production, our cost per BOE were lower. Overall that translated into the operating netback of $49.70.

Speaker #2: with our, full month of higher Merck Q2 production, and some personnel added for Merck Q2, as well as higher overall costs in Canada with more wells on production on average in Q4 compared to Q3, our costs were higher.

Speaker #2: But with that higher, production, that 22% increase in production, our costs per BOE, were lower. So overall, that translated into the operating net back of 4,970, and when you compare that to our realized price of 5,975, 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.

Alison Howard: When you compare that to our realized price of $59.75, that's an operating netback margin or profit margin of 83%, which again, you know, we would argue is top tier relative to other peers operating in Canada and internationally. 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. You know, 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.

Speaker #2: 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.

Pricing and Henry Hub, um, was higher in Q4 compared to Q3. So our overall rate was marginally higher that quarter. But on a per um, Boe basis. Overall, there was a decrease there on the production and transportation expenses, which is the gray bar. Um, we did see um, an increase overall in the dollar amount of our operating expenses. So that that was up about 275,000 from last quarter, um, with our full month of higher Merck, 22 production, and some Personnel added for Merck 22, 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, um, production that 22% increase in production, our cost per Boe, um, were lower. So overall that translated into the operating that back of 4970. And when you compare that to our realized price of 5975, that's

Speaker #2: 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.

Speaker #2: 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.

An operating net back margin or profit margin of 83%. Which again, you know, we would argue, is top tier relative to other, um, peers operating in Canada and internationally. And then when we layer in, in Brazil, as a reminder, we are eligible for um, a tax incentive, that reduces our effective rate to 15.25%. And also, in Canada, we have sufficient tax tools. Such that we don't have tax in Canada at this time. Um, you know, we have a relative to the

Low tax expense and that allows us to generate um significant funds flow from operations.

Speaker #2: 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.

Alison Howard: This chart just shows the change from Q3 of 10.4 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 quarter of $10.6 million and for the year was $40.6 million.

Speaker #2: 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

Speaker #1: Oops.

Speaker #2: 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, just around $1 million US compared to Q3.

Speaker #2: most notably, Q3, we did have an impairment charge on some assets that were transferred to help for sale. So without any impairment in the quarter, that was a, a difference of about 1.9 million this quarter.

So on that note funds flow from operations is, um, cash flow from operating activities before changes in working capital. So this chart just shows the change from Q3 of 10.4, um, to Q4 funds flow of 10.6 million. So roughly, um, just over 0.1 million increase from last quarter, most of that. Again, was due to that 22% increase in sales volumes, um, partially offsetting that was, um, lower realized price and then the higher royalties and production expenses. Um, that I talked about on the last slide, our GNA was also marginally higher in Q4 with, um, final year-end adjustments. Um, overall our funds flow for the year of or for the quarter of 10.6 million and for the year was 40 points, 6 million,

Corey Ruttan: Sorry.

Alison Howard: Similarly on net income, 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 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. And 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.

um, sorry I see

Speaker #2: 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.

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 um just around 1 million dollars US compared to Q3 um most notably. Um Q3 we did have an impairment charge on some assets that were transferred to help for sale. So without any impairment in the quarter, that was a, a difference of about 1.9 million this week.

Speaker #2: 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, a number of quarters.

Porter. Um 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

Speaker #2: 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 183(g)(4) well.

Alison Howard: As a reminder, we previously had a credit facility balance that was fully repaid by Q3 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 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. Overall, that loan bears interest at 7%, and we do have repayments of that loan starting at the end of 2026.

Speaker #2: This $20 million loan, 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.

Facility or our debt balance. So, as a reminder, we previously had a credit facility balance, um, that was fully repaid by the third quarter of 2022. And then we were debt free for a number.

Speaker #2: so we'll talk about, those capital plans a little bit more coming up here, but, overall, the, that loan bears interest at, at 7, 7%, and we do have repayments of that loan, starting at the end of 2026.

A number of quarters. Um, at the end of November, we entered into a 20 million loan agreement. Um, that was basically, you know, we did see um, following

Speaker #2: 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.

Alison Howard: Four 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.

Speaker #1: so yeah, in, in 2025, we paid quarterly dividends, at, 10 cents per share for, and then in the fourth quarter, as you recall, we added a, a 2-cent special dividend, that 12 and then just yesterday, we announced our Q1, dividend at 12 cents.

Corey Ruttan: In 2025, we paid quarterly dividends at $0.10 per share. In Q4, as you recall, we added a $0.02 special dividend at that $0.12. Just yesterday we announced our Q1 dividend at $0.12 per share, and that represents a yield of 8%. If you look at it since inception, since we started the dividend in Q3 2021, we've now declared over $70 million in dividends to shareholders, which represents just shy of $2 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.

Speaker #1: per share US, 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 US in dividends, to shareholders.

Speaker #1: which represents just shy of $2 US per share, so pretty proud of this. we've talked about this a lot. This is the, the more disciplined capital allocation model that we introduced, before we came on production from our core project.

Speaker #1: 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.

Um, so yeah, in 2025 we paid quarterly dividends um at uh 10 cents per share for um and then in the fourth quarter, as you recall, we added a 2 cent, special dividend um, uh, that 12. And then just yesterday, we announced our q1, um, dividend at 12 cents, uh, per share us, 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, uh, We've now declared over 70 million dollars. US in dividends, uh, to shareholders, uh, which represents just shy of $2 us per share. So pretty proud of this.

Speaker #1: We've reviewed this, quite a bit. early on, as Alison noted, a, 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.

Corey Ruttan: The model is 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. We introduced the dividend in Q3 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. And then you can see the split in yellow between what was reinvested and what was returned to stakeholders.

Speaker #1: 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.

Speaker #1: So as Alison noted, we had Q4 funds flow of about 10.6 million dollars. and then you can see the split in yellow between what was reinvested a-and, and what was returned to stakeholders.

Um, 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 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.

Speaker #1: If you look at the pie here on the right, since inception of, of our production of, of AM Cabaret, about 52% of our funds flow, has went into reinvestment and, and 48% of it has been returned to stakeholders over time.

Corey Ruttan: If you look at the pie here on the right, since inception of our production at 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.

Speaker #1: Three weeks ago, we released our annual reserves report. the our 2025 year-end reserve report reflects the great results we've seen at the 183(d)(4) well.

The, uh, green bars here. Uh, with the black dots represents the funds flow from operation. So as Allison noted, we had Q4 funds flow of about 10.6 million. Um, and then you can see the split in yellow between what was reinvested. Uh, and and what was returned to stakeholders, if you look at the P here on the right, since Inception of, of our production of of paying Cabaret,

Speaker #1: 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.

About 52% of our funds flow, uh, it has went into reinvestment and then 48% of it has been returned to stakeholders over time.

Adrian Audet: 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 3x. We've also updated our contingent and 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. 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.

Speaker #1: With an F&D cost of 15.4 US dollar per barrel, and recycle ratios of over three times. We've also, updated our contingent prospective resources report.

3 weeks ago, we released our annual Reserve support. Uh, the our 2025 year, end Reserve report, reflects the great results we've seen at the 183 D4. Well,

Speaker #1: These, these reports highlight the large resource we have identified in the MercA22 field that we have contingent and prospective resources associated with the GOMO formation outside of our well control.

we saw increases in all reserved categories with the production replacement ratios of 495% and 530% for 1 p and 2p respectively.

Speaker #1: Excuse me. As well as prospective resource report in the Kawarasu zoned, which is just adjacent to the assigned reserves area we have that is our current focus.

Our 2p reserves, life index is 12 and a half years. At our Q4 production race, with an fnd cost of 15.4 US dollar per barrel and recycle ratios of over 3 times.

We've also updated our Contingent Perspective Resources report.

Speaker #1: 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.

These these reports highlight the large resource, we have identified in the merka, 22 Fields. So, we have contingent in perspective, resources associated with the goal more formation outside of our wall control.

Excuse me.

Speaker #1: Now our focus is set on the development of the reserves and resources we have we've highlighted in the previous slide. So our near-term operational objective is to improve the MercA22 field gas egress to 600 E3M3 a day, or 21.2 million centicubic feet per day.

Adrian Audet: 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/d or 21.2 million 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.

As well as prospective resource report in the kowasu 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.

Speaker #1: And to maximize the gas plant capacity and, and flexibility. As we build out the productive capacity of the surface facilities and pipeline, we plan, plan to continue our drilling and completions projects to increase the productivity from the field.

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

Speaker #1: With the combination of reserves and resources assigned to our core, 100% owned MercA22 project, we have a large, multi-year opportunity n to unlock. So I'm just gonna go through a little bit more detail in the immediate projects that we're focusing on for, 2026 in MercA22.

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.

Speaker #1: 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, to produce to, to prove the productive capacity of this reservoir, which we have done.

With the combination of reserves and resources, assigned to our core 100% owned, Merit, 22 project. We have a large multi-year opportunity, uh, to unlock.

Adrian Audet: I'm just gonna 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/d 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-Pad, 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 Caruaçu structure.

Speaker #1: And now we're focusing on expanding this infrastructure to meet the expected capacity of the wells. So our first steps are, 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 Kawarasu structure.

So, I'm just going to go through a little bit more detail on the immediate projects that we're focusing on for 2026 and Merit 22.

So, regarding our facilities projects,

And just to remind everybody, our initial facility at this field was built with a capacity of 1,503 and 3 a day to produce, to prove the productive capacity of this reservoir, which we have done. And now we're focusing on expanding this infrastructure to meet the expected capacity of the wells.

Speaker #1: And so this G pad will also be pipeline connected, via this white line here, to the, MercA22 hub, which is that red s-square there.

Speaker #1: Then we're also going to increase the capacity of the MercA22 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, up to 600 E3M3 a day at this at this field battery.

Adrian Audet: This G-Pad will also be pipeline-connected via this white line here to the Murucututu hub, which is that red square there. 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/d at this field battery. Further down the pipeline, we have to increase the actual egress from Murucututu hub to the Caburé hub. Currently, there's a four-inch pipeline, and we're looping it or adding in the same pipeline right away an eight-inch pipeline, which will increase the capacity of over 600 e3m3/d.

So our first steps are are building and constructing a gel location which will allow us to drill up to 4 Wells from this pad and reach the up dip uh locations that proved to locations in our Reserve reports in the car russu structure. And so this gPad will also be pipeline connected via this white line here to the uh Merck 22 Hub, which is the Red Square there.

Speaker #1: And then further down the, the pipeline, we have to increase the actual egress from MercA22 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 eight-inch pipeline, which will increase the capacity of over 600 E3M3 a day.

Then we're also going to increase the capacity of the Merit to job and to do this, we need to add larger separators larger uh pressure relief, flare stack. And some other processing components so that we can process up to 600 E3 up to a day at this at this field battery.

Speaker #1: We're also planning, a development well for 2026 at the D-D pad, and it's called our D1 well, which you can see in that white dot.

Speaker #1: And, a recompletion at the 183(1) well, which is located at the MercA22 hub. From 2028 and beyond or, sorry, for 2027, we'll be done these facilities improvements.

Adrian Audet: We're also planning a development well for 2026 at the D pad, and it's called our D-1 well, which you can see in that white dot. A recompletion at the 183-1 well, which is located at the Murucututu hub. For 2027, we'll be done these facilities improvements, so we will focus on the drilling from the G-Pad and those up-dip locations at the Caruaçu structure. From 2028 and beyond, we'll continue the development of both the Caruaçu structure as well as the Gomo reservoirs, which are all highlighted in our reserve and resource reports. We also have a midstream project at the UPGN Caburé for 2026.

And then further down the the pipeline. We have to increase the actual egress from worker 22 top Hub to the Cabaret Hub. Currently, there's a 4-inch Pipeline and We're looping it, or adding in the same, uh, pipeline right away, an 8 inch pipeline, which will increase the capacity of over 600 E3 M3 a day.

Speaker #1: So then we will focus on the drilling from the G pad, and those updip locations at the Kawarasu structure. And then from 2028 and beyond, we'll continue the development of both the, the Kawarasu structure, as well as the GOMO reservoirs, w-which are all highlighted in our reserve, and resource reports.

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

and uh, a recomp completion at the 1831, well, which is located at the Merc to do a

Speaker #1: So down 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, or UPGN, to improve our ability to process increased amounts of MercA22 gas, which is richer than the, the Cabaret gas.

From 2028, b or sorry. For 2027. We'll be done these facilities improvements so that we will focus on the drilling from the gPad. On those up tip locations at the kerosene structure.

And then from 2028 and Beyond, we'll continue the development of both the, the kerosene structure as well as the go reservoirs.

Uh, which are all highlighted in our Reserve uh and resource reports.

Speaker #1: So the target capacity of this immediate project is an overall gas rate of 600 E3M3 a day. But we'll allow up to 300 E3M3 a day of MercA22 gas blended with our Cabaret gas.

Adrian Audet: 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 Caruaçu gas, which is richer than the Caburé gas. The target capacity of this immediate project is an overall gas rate of 600 e3m3/d, but will allow up to 300 e3m3/d of Caruaçu 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.

So down, we also have a Midstream project at the UPG Cabaret uh for 2026.

Speaker #1: 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% MercA22 gas, which we expect to we expect this project to require additional fractionation and product streams, given the heat content from the MercA22, field.

So the short-term plan is to optimize the processing capacity of the gas planter or UPG to improve our ability to process increased amounts of Merc 22 tasks which is richer than the the cap rate gas.

so the target capacity of his immediate project is an overall gas rate of 6003 at 3 a day,

But we'll allow up to 300 E3 and 3 days of Mercy, 22 gas blended with our Cabaret gas.

Adrian Audet: 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.

This project has been initiated with our facilities partner and our flex, and we expect this to be online by the end of Q3.

Speaker #2: Great. Thank you, Adrian.

Speaker #3: So as we've talked about in the past, I think early in, in, 2025, we announced our strategic entry into the Western Canadian sedimentary basin.

Speaker #3: And then later in the year, we extend a-a-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, where we're looking to deploy leading-edge drilling technology using open-hole multilateral drilling.

We're also working on a medium-term plan to adapt the plant to handle 100% for a 222 gas, which we expect to. We expect this project to require additional fractionation and product streams, given the heat content from the nerve 22.

Uh, field.

Corey Ruttan: 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. 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, so 80 square miles of highly prospective land. We've now got 7 gross, 3.5 net wells on production.

Speaker #3: we 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.

Right. Thank you, Adrian. So as we've talked about in the past, uh, I think early in, in, uh, 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 we now cover this green dashed area, which pretty much covers the entire SOC.

Speaker #3: We've now got seven gross 3.5 net wells on production. and, the reserves that Adrian, walked through earlier for the first time actually included some, some of the reserves from our, our Canadian assets here on a 2P basis.

Speaker #3: We've booked 735,000 barrels, o-of reserves. that did include eight gross or four net undeveloped locations, based on the initial well spacing that we have.

Corey Ruttan: 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 booked 735,000 barrels of reserves. That did include 8 gross or 4 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 one drilling locations in our inventory. On this slide, we just show where that tier one inventory sits relative to the booked locations that GLJ, our independent reserve evaluator, assigned in the table on the top right here.

Scatch when side of the mannville stack heavy oil play, Fairway where we're looking to deploy Leading Edge, drilling technology, using open hole, multilateral drilling. Um, we last year, we finished drilling all of our earning Wells and we've added, uh, further to that, uh, land base. We now have over 80 sections, so 80 square miles of Highly prospective land. We've now got 7 Grouse 3.5 net Wells on production. Um,

Speaker #3: But we see a much broader, opportunity. here with over 100 gross 50 net tier one drilling locations in our in, in our inventory. on this slide, we just show where that, tier one inventory sits relative to the booked locations that GLJ, our independent reserve evaluator, assigned in the table, on the top right here.

Speaker #3: 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.

Assets here on the 2p basis. We booked 735,000 barrels, uh, of reserves, uh, that did include 8 Grouse or 4 net undeveloped locations based on the initial. Well, spacing that we have. But we see a much broader, uh, opportunity. Uh, here with over 100 grows 50, net, Tier 1 drilling locations in our, in our inventory. Um,

Corey Ruttan: 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 you know, 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 Alvopetro with another strong growth platform as we look forward.

Speaker #3: and if you assume obviously, commodity prices are moving wildly, but, you know, if, if you assumed a even a flat WTI $70 per barrel price, the economics associated with drilling these wells range between 50 and, and over 130 percent IRR.

On this slide we just show where that uh Tier 1 inventory, sits relative to the booked locations, that glj are independent Reserve, evaluator assigned in the table, uh, on the top right here on the graph. That you see, these are the 3, uh, approved plus probable, type curves that glj established for 3 of our core areas, ranging between 100,000 and close to 180,000 barrels per uh location. Um,

Speaker #3: So quite attractive. we're extremely happy about, this

Speaker #1: Is Western Canadian entry that we've got . I think we had a great start on this asset in 2025 , and it just provides elbow petrol with another strong growth platform .

Speaker #1: As we look forward . So just to conclude , like I said , 2025 really was a transformational year for Petro . 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% .

And if you assume obviously, uh, commodity prices are moving wildly, but, uh, you know, if if you assumed that even a flat WTI, 70 per barrel price, um, the economics associated with drilling, these Wells range between 50 and and over 130% irr. So quite attractive, uh, we're extremely happy about, uh, this Western Canadian entry that we've got. I think we had a great, uh, start uh, on this asset in 2025 and it just provides double Patrol with another strong growth.

The platform as we look forward.

Corey Ruttan: 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 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 close to 1 million barrels of production that we had last year of 43%, and considering we replaced that production over 5 times from a reserve perspective, I think it really was an exceptional year for us.

Speaker #1: Have £0.02 reserve growth even after the close to 1 million barrels of production that we had last year of 43% . And considering we replace that production over five times from a reserve perspective , I think it really was an exceptional year for us We do have strong free cash flow generation capacity , and that really helps underpin that disciplined capital allocation model that I talked about .

Speaker #1: And then , you know , from an investment thesis perspective , we really do feel like this is a value yield . And growth story that continues .

Corey Ruttan: We do have very strong free cash flow generation capacity, and that really helps underpin that disciplined capital allocation model that I talked about. 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 2P, our updated 2P NPVs. For yield investors, that $0.12 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 has the ability to unlock an awful lot of value for shareholders, especially when you consider the potential relative to our current enterprise value.

Speaker #1: We're trading at just over 55% of our £0.02 , our updated £0.02 npvs for investors , that 12 cent per share quarterly dividend that we just declared translates into a yield of about 8% for growth investors .

So, just to conclude, um, like I said, uh, 2025 really was a transformational year for elbow Pro. We continue to deliver some pretty strong results. Obviously, we benefit from from high realized gas prices, uh, industry-leading operating, net backs and operating net back margins. Um, 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, uh, of over 41% have 2p Reserve growth even after the the close to a million, barrels of production that we had last year of 43%. And considering we, we replace that production over 5 times, from a reserved perspective. Uh, I think it really was an exceptional year for us. Um, we do have very strong free cash flow, generation capacity, and that really helps underpin that disciplined Capital allocation model that I talked about.

Speaker #1: I think we've got an extremely exciting capital program that has the ability to unlock an awful lot of value for shareholders , especially when you consider the potential .

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 2P—our updated 2P NPV S.

Speaker #1: Relative to our current enterprise value . And I think we've significantly strengthened our our capital allocation and stakeholder return model by , you know , combining growth opportunities in Brazil that I think based on the hundred 83 D for success are better than ever And combine that with the deep inventory of open multilateral locations that we've got in Canada .

Corey Ruttan: I think we've significantly strengthened our capital allocation and stakeholder return model by, you know, combining growth opportunities in Brazil that, you know, I think based on the 183-D4 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 Q4, record monthly production in January. 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. You consider we were up 41% year-over-year last year, that would be, in my mind, two successive years of pretty exceptional results. Pretty happy with where we are.

Speaker #1: As I noted , we exited 2025 with record quarterly production in 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 a close to another 25% uptick relative to last year .

Speaker #1: So you consider we were up 41% year over year last year . That would be , in my mind , two successive years of of , of pretty exceptional results .

Speaker #1: So pretty happy with where we are . And with that , I'll turn it over to the question and answer period .

For yield investors at 12 cent per share, quarterly dividend, uh, that we just declared, uh, translates into a yield of about 8% for growth investors. I think we've got an extremely exciting Capital program that that, uh, 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. And I think we've significantly, strengthened our, our Capital, allocation stakeholder, return model by um, you know, combining growth opportunities in Brazil that, you know, I think based on the 1833 D4 success, our better than ever. Uh, and combine that with the Deep inventory of of, uh, uh, open home multilateral, uh, locations that we've got in Canada. Um, as I noted, we exited 2025 with a record quarterly production, in Q4 record monthly production in in January. Um and like I said if we can continue those January and February

Speaker #2: 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 do we lease those .

Corey Ruttan: With that, I'll turn it over to the question and answer period.

Speaker #2: Do we own our drilling rigs or do we lease them

Corey Ruttan: With that, I'll turn it over to the question and answer period.

Alison Howard: 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 do we lease those? Do we own our drilling rigs, or do we lease them?

February production levels, you know, 2026 will look like a 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 2 successive years of of 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.

Speaker #1: So I'll start with maybe work backwards . The the drilling equipment we would rather stay out of that business and have service providers provide those services .

Sure, we've got a few questions in, um,

Speaker #1: 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 one .

Corey Ruttan: Let me 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, you know, 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.

Can you comment on what the twenty million dollar loan? Proceeds were used for? Did we purchase new processing facilities or to release those? Do we own our drilling rigs? Or do we lease them?

uh,

Speaker #1: 83 D1 well , and it's mobilizing to location as we speak . From a credit facility standpoint . You know , we did what we did want to do is by the end of last year , we wanted to put in place this facility .

Speaker #1: 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 .

Speaker #1: 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 in capital activity through this year and potentially with higher commodity prices here , our activity levels in Canada are really a function , you know , those returns are highly sensitive to to oil prices .

183 D1 well and it's mobilizing to location as we speak from a credit facility standpoint. Um, you know we we did. Um,

Corey Ruttan: 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. You're gonna see. You know, to date, we actually haven't used a lot of that, but with the increase in capital activity through this year and potentially with, you know, higher commodity prices here, our activity levels in Canada are really a function. You know, those returns are highly sensitive to oil prices. We also wanna have the flexibility of being able to ramp up that program as needed as well.

What we did want to do is uh 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.

Speaker #1: So we also want to have the flexibility of being able to ramp up that program as needed as well

Speaker #2: So we have a number of questions around the Merc two , two expansion . So I'll try to get through all of those around the same time here .

Speaker #2: Can you provide further details regarding the timing of the Merc two two infrastructure expansion and whether those steps , those occurrence steps are all at once

Alison Howard: We have a number of questions around the Merc22 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 Merc22 infrastructure expansion and did those occur in steps or all at once?

Uh, you know, a 7% loan, uh, 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, um, uh, through this year and, and you're going to see, you know, today, we actually haven't used a lot of that, but with the, um, increase in capital activity through this year and potentially with, you know, higher commodity prices here, our activity levels in Canada are really a function, you know, the those returns are highly sensitive to, to oil prices. So we also want to have the flexibility of of being able to ramp up that program as as needed as well.

Okay, we have

Speaker #3: Yeah , there's certainly steps associated with that . You know , we're basically bottlenecked at a lot of different spots at the same time right now , just due to the initial buildout of two two .

Speaker #3: So 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 pen needs to be expanded .

Adrian Audet: Yeah. There are certainly steps associated with that. You know, 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 gonna take the full amount of 2026. They're subject to pipeline permitting at the looping of the pipeline. We do expect it to take all of 2026.

A number of questions around number of 22, um, expansion. Um, so I'll try to get through all of those around the same time here. Um, can you provide further details regarding the timing of the Merc, 22 infrastructure expansion and whether those steps those occurrences are all at once.

Speaker #3: I did note that the upgrade is expected to be done at the end of Q3 , but those other projects are going to take the full amount of 2026 .

Yeah, there there's certainly steps, uh, associated with that. You know, we're basically bottlenecked at a lot of different spots at the same time, right now, just due to the initial build out of them or 22.

Speaker #3: And there subject to pipeline permitting at the the looping of the pipeline . So we do expect it to take all of 2026 .

Speaker #2: Okay . There is a question . Maybe just to reiterate on whether the timing of the expansion of the Merc two two to the 600,000 ties in .

Speaker #2: Exactly with the estimated timing of the Q3 upgrade , cabaret and and know you expect to have the upgrade cabaret expansion still be working on Merc two to up to .

So the pipeline needs to be expanded, which is a project in itself. The, the field facility needs to be expanded paths need to be tied in and the UPG needs to be expanded. I did note that the UPG end is expected to be done at the end of Q3, but those other projects are going to take the full amount of 2026. And there are a subject to pipeline permitting at the, the looping of the pipeline. So we we do it's expected to take all of twice twice.

Alison Howard: Okay. There is a question maybe just to reiterate, on whether the timing of the expansion of the Merc22 to the 600,000 ties in exactly with the estimated timing of the Q3 UPGN Caburé and do you expect to have the UPGN Caburé expansion still be working on Merc22-

Speaker #3: The those other projects . And then there's drilling projects that will be will follow on the facilities projects . Yeah .

Speaker #1: And maybe just elaborate . So the gas plant expansion will give us more flexibility to handle increasing components of Merck two two gas , which , you know , for the most part , we've been producing at the hundred and 50,000m³ a day range .

Adrian Audet: Yeah

Alison Howard: up to the end of the year.

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

Speaker #1: We can kind of push that a little bit higher . That plant expansion would give us the flexibility of doing that while the market two expansion happens .

Corey Ruttan: Yeah. Maybe just elaborate. The gas plant expansion will give us more flexibility to handle increasing components of Merc22 gas, which, you know, 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 Merc22 expansion happens. The big kind of fourfold increase in Merc22 takeaway capacity is timed closer to the end of the year.

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 UPG and Cabaret. And, I know you expect to have the UPG and Cal expansion, but still be working on Merc 22. Yeah, those other projects, and then there are drilling projects that will follow on the facilities projects.

Speaker #1: But the big kind of four fold increase in Merck two , to takeaway capacity is timed closer to the to the end of the year .

Speaker #2: Okay . There are some questions around still on the Merck two two expansion . What are the biggest execution risks ? Whether technical infrastructure or regulatory , that could slow that ramp up

Speaker #3: Well , I noted that , you know , we are awaiting a permit for our pipeline expansion . This is something we've done before .

Yeah, and maybe just elaborate. So the gas plant expansion will give us more flexibility to handle increasing components of Merc 22 gas. Um, which you know for the most part we've been producing at 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 Merced to expansion happens, but the big kind of 4-fold increase in Mercer 22 takeaway capacity is is time closer to the to the end of the year?

Alison Howard: Okay. There are some questions around. Still on the Merc22 expansion. What are the biggest execution risks, whether technical infrastructure, or regulatory that could slow that ramp up?

Speaker #3: So but it is always a risk . And timing . A large , large portion of this is surface facilities , which are , you know , there's always a timing risk on that .

Okay, there are some questions around still in the Merc 22 expansion. Um, what are the biggest execution risks Tech whether technical infrastructure or regulatory that could slow that ramp up.

Adrian Audet: Well, I noted that, you know, we are awaiting a permit for our pipeline expansion. This is something we've done before, so but it's 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 as we expand Murucututu, we'll be drilling, like Corey mentioned, or we're contracting a drilling rig. And timing of these things is always a risk within the operating areas of Brazil. So that would probably be the biggest ones I'd highlight.

Speaker #3: And then as we expand Merck Q2 will be drilling , like Corey mentioned , or contracting a drilling rig . And timing of these things is always a risk with it within the operating areas of Brazil .

Speaker #3: So the probably the biggest ones I'd highlight

Well, I I noted that, you know, we are a a waiting, a permit for our pipeline expansion. Um, this is something we've done before. So, but it is always a a risk and timing, um, a large large portion of this is surface facilities which are uh,

Speaker #1: Yeah , 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 .

Speaker #1: They did one minor expansion for us before . They've always delivered on time . So I have high confidence level in that . The benefit , I think Adrian noted to it , we're actually following existing pipeline , right of ways .

You know, there's always uh timing risk on that and then as we've expanded Market to 2 will be drilling like Corey mentioned or we're Contracting a drilling rig and and timing of these things is always a risk with it.

In the operating areas of Brazil. So,

Corey Ruttan: Yeah. 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. I have high confidence level in that. The benefit, I think Adrian noted too, we're actually following existing pipeline right of ways. That does help simplify the process. There's always risk as obviously, but that certainly kinda helps.

That would probably the biggest ones I'd highlight.

Speaker #1: That does help simplify the process . There's always risk , obviously . Obviously , but that that certainly kind of helps

Speaker #2: So still on the Merc two two front on the drilling plan , can you comment how many total wells will be drilled on the field this year

Speaker #1: Yeah . Well right now we've got a plan for for one location . We are making contingency plans that if we're happy with the rig performance and depending on the pace of those , the facility's capital projects , we do have flexibility .

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

Yeah, I think the nice thing is, we're dealing with an existing highly qualified contractor, um, enerflex, who's a leader in in, in kind of this gas plant technology. They did 1 minor expansion for us before. They've always delivered on time. So we have high confidence level and that um, the benefit I think Adrian noted to it, we're actually following existing pipeline right away. So that does help simplify the process. There's always risk as awfully obviously. But that that certainly, um, kind of helps

Speaker #1: 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 one pad target .

Corey Ruttan: 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 those 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. The drilling up dip off of the G-Pad, you know, that G-Pad is in the permitting process. We would expect that fairly soon. Then we've got a two- to three-month civil project to get that drilling pad ready.

So still on the mark, 222 front, um, on the drilling plan, can you comment? How many total wells will be drilled on the field this year?

Speaker #1: Some of the prospective area that we've got assigned in our resource reports . The drilling updip off of the g pad . You know , that G pad is in the permitting process .

Speaker #1: We would expect that fairly soon . And then we've got a call it 2 to 3 month civil project to get that drilling pad ready .

Speaker #1: And then at that point , we 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 , you know , with , you know , relatively consistently with the facility's projects as well

Speaker #2: So on the expansion to 600,000m³ a day with Mirka two two , do you expect to utilize all of that capacity

Corey Ruttan: At that point, we'd also have the flexibility to be drilling off of those pads. We just, you know, we wanna make sure that we're timing that, you know, with you know, relatively consistently with the facilities projects as well.

Speaker #1: Well , yeah , no , that's what we're ramping up towards . You know , we we increased our firm sales volumes last year to 400,000m³ a day .

Um and depending on the pace of those C, the uh facilities capital projects, we do have uh, 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 1971 pad, um, um, Target, some of the perspective area that we've got assigned in our resource reports, the drilling up dip off of the gPad, um, you know that jpad is, you know, in the permitting process we would expect that fairly soon and then we've got a call a 2, to 3 month, civil project to get that uh drilling pad ready. And then at that point, we 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, we we you know relatively consistently with the facilities projects as well.

Alison Howard: On the expansion to 600,000 cubic meters a day with Merc22, do you expect to utilize all of that capacity?

Speaker #1: We're producing up to close to 500,000m³ a day . Today . And then with that capacity increase . So if you look at that , you know , that's a 41% year over year production growth in 2025 .

So on the expansion to 600,000, um, cubic meters a day with America, 22. Do you expect to utilize all of that capacity?

Corey Ruttan: Well, yeah, no, 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. With that capacity increase, if you look at that, you know, that's a 41% year-over-year production growth in 2025. You know, roughly 25% increase again in 2026. If we can be up to the 600 capacity for 2027, that'd be another 20%, you know, approximately increase in that year. Yeah, no, that's absolutely our target.

uh,

Speaker #1: B , you know , 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% .

Speaker #1: You know , approximately increase in that year . And , yeah , no , that's absolutely our target .

Speaker #2: Okay . Can you comment on the price you receive for your non-firm or Interruptible or flexible volumes in Brazil

Speaker #1: 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 .

Well, yeah, no. But that's what we're ramping up towards. Um, you know, we we increased our firm sales volumes last year to 400,000 cubic meters a day. Uh, we're producing up to close to 500,000 cubic meters a day today, um, and then with that capacity, increase. So if you look at that, you know, that's a 41% year-over-year production growth in 2025, be you know, 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%, you know, approximately increase uh in in in that year and that year. No, that's absolutely our Target.

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

Speaker #1: I think , you know , roughly right now , even at these higher production levels , about 20% of our gas sales are happening on a on a spot basis .

Corey Ruttan: We haven't been commenting on that. You know, we're respecting the confidentiality of our contracts, but you know, we are working on our kinda 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.

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

Speaker #1: I think you'll see that show up in our Q1 results . The vast majority of it is under our under our base contract .

Speaker #2: Can you provide an estimate of what your next Brazilian gas price reset will take you based on current futures curves ?

Speaker #3: Yeah .

Speaker #1: So maybe just a little bit of a reminder how our , our contract now works quarterly . So on February 1st , we had a price reset that we've already announced that was using the Q4 commodity prices for , for Henry Hub 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 .

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

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, uh, uh, on our kind of gas sales, portfolio. I think, you know, roughly right now. Um, even at these higher production levels about 20% of our gas sales are happening on a, on a spot basis. I think you'll see that show up in our q1 results. The vast majority of its under our, under our base contract,

Corey Ruttan: Yeah. Maybe just a little bit of a reminder how our contract now works quarterly. On 1 February, 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 1 May will be the first time that the Q1 benchmarks get used. With Q1, you know, we're over 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, we would expect, you know. Our price today is $10.75 per Mcf.

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

Speaker #1: So I think we already . So with Q1 , you know , we're over two , three quarters of the way through the quarter .

Speaker #1: If you assumed that the rest of the the month of March matches the futures curve that you see in the market today , we would expect .

Yeah, so maybe just a little bit of a reminder, how our our contract now works quarterly. So, um, on February 1st, we had a price reset that we've already announced that was using the Q4, um, commodity prices for, for Henry Hub and Brent under our main contract, um, the next price, reset that happens on May 1st will be the first time that the q1 benchmarks get used. So um, I think we already uh,

Speaker #1: 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 .

uh,

so with q1, you know, we're

Over 2. Well 3/4 the way through the quarter if you assumed

Speaker #1: With those spot prices and a reminder about 80% of our volumes are currently being sold under that contract

Speaker #2: Maybe we can jump to our CapEx budget for 2026 . There's some questions . If we can provide further details on on what our CapEx budget is overall for 2026 .

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

Speaker #2: So we did release 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 facility's expansion and that first additional while work to , I believe that was 21 million was the number that we released .

Um, that, uh, the rest of the, the month of March match is the, the Futures curve that you see in the market today. We would expect a, you know, 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.

Alison Howard: Maybe we can jump to our CapEx budget for 2026. There are some questions if we can provide further details on what our CapEx budget is overall for 2026. We did release 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, 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 wells, the most recent two wells in January. Those costs were around CAD 2 million, I believe, two million Canadian. Then maybe, Corey, you can comment on future plans in Canada as well.

Um,

You can jump to our capex budget.

26. Uh, there's some questions if we can provide further details on on what our capex budget is overall for 2026.

Speaker #2: Yes . And then in Canada , there are some additional follow up questions in Canada . So we did drill the first or the last two .

Speaker #2: Well , 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 .

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 Murucututu 22. Um, I believe that was $21 million was the number that we released.

Speaker #2: We haven't included anything else in in our budget that we released at the end of February . At this time . But Corey can comment further on that .

Speaker #1: Yeah , no , like I mentioned , a lot of that is commodity price driven . We're also working with our other 50% working interest partners .

Yes, and then in Canada, um, there are some additional follow-up questions in Canada. So we did drill the first—or the last two, well, the most recent two wells—in January. Um, so those costs were around $2 million, I believe, $2 million Canadian. Um,

Speaker #1: So we'll be , you know , looking at , you know , I'm pretty confident we'll be implementing an additional drilling here as the year progresses .

Alison Howard: 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.

Speaker #1: And on a net basis , each of those wells cost us about . Canadian $1 million .

Corey Ruttan: Yeah. No, like I mentioned, a lot of that is commodity price driven. We're also working with our other 50% working interest partners. We'll be, you know, looking at it. I, you know, 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 cost us about CAD 1 million.

In our, um, budget that we released at the end of February. At this time, of course, you can comment further on that.

Speaker #2: And how are you financing your capital budget in 2026 ?

Speaker #1: 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

Alison Howard: How are you financing your capital budget in 2026?

Yeah, no. Like I mentioned, a lot of that is commodity price driven. We're also working with our other 50% working interest partner. So, uh, we'll be, uh, you know, looking at—you know, 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 costs us about Canadian dollars.

Speaker #2: Can you ramp up production beyond planned to take higher prices that we're seeing right now ? Or do you plan to accelerate anything given the high price environment ?

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

And how are you finding using your capital budget in 2026?

Speaker #1: Yeah , so the good news in Brazil is we had way better than expected success on this one . 83 D4 well , on our America two two project in the Karasu formation .

Alison Howard: 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. 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.

Speaker #1: And as a result of that , we're we're responding by by significantly expanding the field takeaway capacity as Adrian walked through . So , you know , the reality is we need to work through those projects .

Corey Ruttan: 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. You know, 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 the more relevant would be in the Western Canadian assets.

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

Speaker #1: 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 .

Speaker #1: Another , another increase in moving into next year , probably . So more , more relevant would be in the Western Canadian assets .

Speaker #1: 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 .

Yeah. So the good news in Brazil is we had way better than expected uh, success. On this 183d for uh, well on our America, 222 project in the Keras, Sue formation. Um, then as a result of that we're um, responding by by the significantly expanding the fuel takeaway capacity as Adrian walked through. So, you know, the reality is we need to work through those projects time, additional drilling to build productive capacity. All of that together to to um, you know, solidify, the increases we're already seeing,

Speaker #1: And built out a pretty solid tier one inventory of locations . So I think we've got lots of flexibility to increase activity there .

Speaker #1: And like I said , we'll be working through that with our partner here in the coming weeks and months .

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

Speaker #2: Can you comment on the payback period for the Wells in Canada in the current oil price environment

Speaker #1: 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 .

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

And set ourselves up for next year. Another 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 3 core areas within our land base and and built out a pretty solid. Tier 1 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 partners here and in the coming weeks and months,

Speaker #1: 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 would be my guess , depending on which type curve we're talking about

Corey Ruttan: 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. 18 months would be my guess, depending on which type curve we're talking about.

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

Uh,

Speaker #2: What price does Elvo get for oil in Canada Well , high Henry . So our pricing in Canada is at w c s pricing .

Speaker #2: There's a small discount to that , but pricing , which is Canadian dollar pricing

Alison Howard: What price does Elbow get for oil in Canada?

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

Alison Howard: What price does Elbow get for oil in Canada?

Um, what price?

Corey Ruttan: I believe so.

I'll go get for oil in Canada.

Alison Howard: Oh, hi, Henry.

Speaker #1: Yeah , WC is a Canadian heavyweight benchmark price that's quoted . It's generally been between a 12 to $14 US discount to WTI

Corey Ruttan: Please go ahead.

[Company Representative] (Alvopetro Energy): Our pricing in Canada is at WCS pricing. There's a small discount to that, but WCS pricing, which is Canadian dollar pricing.

Hi. Um, so our pricing in Canada is at W.

Speaker #2: Okay . So you've outlined a 50 over 50 capital allocation between growth and shareholder returns with the plan . Merck two two expansion and strong well results .

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

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

Yeah, WCS is a Canadian heavy oil benchmark price that's quoted.

Speaker #2: Under what conditions would you shift the balance either accelerating growth or increasing the dividend further ?

It's generally been between a 12 to 14 dollar US discount to WTI.

Alison Howard: Okay. You've outlined a 50/50 capital allocation between growth and shareholder returns. With the planned Merak-2 expansion and strong well results. Under what conditions would you shift the balance, either accelerating growth or increasing the dividend further?

Speaker #1: 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 .

Corey Ruttan: Yeah. 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 is certainly the way that I look at it.

Don't mind the 5050, Capital allocation between growth and shareholder returns with the plan Merck, 22 expansion and strong wall results. Under what conditions would you shift the balance either accelerating growth or increasing the dividend further?

Speaker #1: You know , given that financial flexibility that we have is certainly the way that I look at it .

Speaker #2: So a couple of things on Canada , just a couple questions . Anytime we express our share of reserves or production , that's Alvopetro Energy Ltd. .

Speaker #2: That's net to Alvopetro Energy Ltd. . There was a question about that . There's also a question on the transportation costs in Canada .

Alison Howard: 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, or are there any limitations that you see? That's all trucking, clean oil trucking. It's the transportation cost. It's all truck, nothing via pipeline at this time. All right. Couple questions around some legal matters. Do you have any visibility of the timing of the Caburé arbitration?

Yeah so ultimately the dividend decisions are made with with our board of directors as well but um you know with the growth opportunities in front of us um and the credit facility that we put in place we do have the flexibility to go above the 50% number for Capital expenditures. Um you know given that Financial flexibility that we have. This certainly the way that I look at it.

Speaker #2: Are those pipeline or other forms of transport , or are there any limitations that you see ? So that's all trucking clean oil , trucking is transportation costs .

Speaker #2: So it's all tracked . Nothing via pipeline at this time Sorry . Couple questions around . Some legal matters . Do you have any visibility of the timing of the cabaret arbitration

So a couple things on Canada, just a couple um questions. Um, anytime we express our, um, share of reserves or production, that's elbow, Petro share. So that's neat to all of our petrol. 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, are there any limit?

Ations that you see.

So that's all trucking clean, oil Trucking, so the transportation costs so so it's all truck, nothing via pipeline at this time.

Speaker #1: Well , I think if you go strictly by the timeline , we would expect an outcome sometime in the middle part of this year .

um,

sorry.

Speaker #1: But , you know , these processes sometimes take longer than initially projected . So I hesitant to fix a an exact time

Corey Ruttan: Well, I think if you go strictly by the timeline, we would expect an outcome sometime in the middle part of this year. You know, these processes sometimes take longer than initially projected, so I'm hesitant to kind of fix an exact time.

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

uh,

Speaker #2: 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 ?

Speaker #1: Yeah , 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 .

Alison Howard: 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?

Projected. So I hesitant to kind of fix a, a, an exact time.

Um, on Cabaret. There's also a question about this second redetermination, um,

Any thoughts on when that should be?

Speaker #1: And so the timing of that is 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 thermoelectric power plant .

Corey Ruttan: Yeah. 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. 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 thermoelectric power plant. Long story short, we would expect that to be sometime in the kinda 2- to 3-year range from today.

Um, and how will that work given the first redetermination is still being contested?

yeah, um, yeah, there's a provision for that in our unit operating agreements based on, uh,

Speaker #1: Long story short , we would expect that to be sometime in the kind of 2 to 3 year range from from , from today

Speaker #2: And then there is also a question about we have those assets that we entered into an agreement to sell subject to A&P approval .

Speaker #2: Is there any status update on that ? I think everything's been submitted and we're just waiting for the AMP approval at this time .

The, uh, recovery of gas relative to the total amount of gas to be recovered from the field. And so the timing of that is 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 would expect that to be sometime in the kind of 2- to 3-year range from today.

Alison Howard: 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?

um,

and then,

Speaker #2: 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

There is also a question about. We have those assets that we entered into an agreement to sell subject to A&P approval? Is there any status update on that? I think everything's been submitted and it's, we're just purely waiting for the amp approval of this time.

Speaker #1: 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 , you relatively lower capital costs ?

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 2 regions long term?

Corey Ruttan: 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 you know, relatively lower capital cost, pretty high or quick payouts, and they can be executed, like, I think every one of these 8-leg multilaterals that we've been drilling, has been completed within a 2-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, you know, we're not having to make investment decisions at the expense of the other business unit.

Speaker #1: Pretty high or quick payouts . And they can be executed . Like I think every , every one of these eight leg multi lots that we've been drilling has been completed within a two week period of time .

Speaker #1: 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 , the , the credit facility , we put in place , you know , we're not necessarily we're not having to make investment decisions at the expense of the other business unit .

Speaker #1: You know , we can co-invest in both both those opportunities right now

Speaker #2: And there's another question here on capital expenditures . When do we expect those to peak in 2026 . Do we see the most activity .

Corey Ruttan: We, you know, we can co-invest in both those opportunities right now.

Speaker #1: Yeah . The lumpy activity is associated with the drilling project on our 183 D1 . Well , so like I said , the rigs mobilizing .

Alison Howard: 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, well again, it's commodity price driven obviously at current spot prices. It, competes extremely well. Um, the other nice thing about it is the individual Wells. As I mentioned are are uh you know, relatively lower Capital costs, pretty high uh or quick payouts. Um, and they can be executed like I think every every 1 of these, 8 leg multi that we've been growing, uh, has been completed within a 2 week period of time. So there's a lot of flexibility on the Canadian side to ramp up or ramp down activity. Um, I think the nice thing is with our strong free cash flow, generation capacity and the the the credit facility we put in place. You know we're not neces. We we're not having to make investment decisions at the expense of the other business unit. We you know, we can co-invest in both the both those opportunities right now.

Alison Howard: There's another question here on capital expenditures. When do we expect those to peak in 2026? When do we see the most activity?

Speaker #1: Now you won't start to see concrete costs really until we get into Q2 here . But you know , yeah , we'll have more capital costs in Q2 related to that project .

Um and there's another question here on Capital expenditures, when do we expect those to Peak in 2026?

Corey Ruttan: Yeah. 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, you know, concrete costs really until we get into Q2 here. You know, yeah, we'll have more capital costs in Q2 related to that project. The facilities projects, you know, are probably wrap up more as we move through the year.

Speaker #1: And then the facility's projects , you know , are probably ramp up , you know , more as we move through the year

Speaker #2: Just looking to see if we have anything else . I think that's it for now . Yeah . No further questions .

Do we see the most activity? Yeah, the Lumbia activity is associated with the drilling project on our 183 D1. Uh, well, so uh, 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, uh, you know, yeah, we'll have more capital costs in Q2 related to that project, um, and then the facilities projects.

You know.

Speaker #1: All right . Well , I want to thank you all for attending . And thank you for all your support . If you got additional questions , feel free to give us a call and thank thank you

Or probably ramp up a, you know, more as we move through the year.

Alison Howard: Great. Just looking to see if we have anything else. I think that's it for now. Yeah, no further questions.

Okay, just looking to see if we have anything else.

I think that's it for now.

Corey Ruttan: All right. Well, I wanna 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.

Yeah, no further questions.

Alison Howard: Thanks, everyone. Goodbye.

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 um thanks thank you. Thanks everyone.

Goodbye.

Q4 2025 Alvopetro Energy Ltd Earnings Call

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