Okay, just a few administrative points before we begin. We are recording today's call, and we will have a replay available on our website later on this afternoon. All attendees have been placed in listen-in-only mode for the duration of the webcast, but we will have a Q&A session at the end of our presentation. If you have any questions, you can start sending those in now using the Zoom Q&A button that you should see on your screen. If you've dialed in by phone, you can send us any questions to socialmedia@alvopetro.com. Lastly, we do go through various non-GAAP measures, and we make forward-looking statements throughout this presentation. We do encourage you to review all the cautionary statements and additional disclosures, both on our corporate presentation and on our most recent management discussion and analysis that was just released yesterday for Q2. All right, thank you, Alison. As we previously announced, we did upgrade our gas sales agreement with Bahiagás late last year. As part of that, we did increase our firm gas sales volumes by 33%. That, combined with some considerable operational successes, has resulted in a very strong start to 2025 for us. As per last quarter, our production was up 41% quarter- over -quarter in Q1, and we had a similarly strong quarter in the second quarter here, pretty consistent with Q1 and up 50% from the second quarter of last year. We did have some facility maintenance and inspections in Brazil that did impact the quarter, and that was offset by the addition of our new production in Western Canada that averaged 138 bbl of oil per day. As you can see here, our July production did continue at pretty consistent levels, averaging almost 2,300 bbl of oil equivalent per day in Brazil and 134 bbl of oil per day in Canada. Adrian will walk through this later, but our strategy here through the rest of this year is to add additional 100% working interest productive capacity in Brazil with a target of getting to 3,000 bbl of oil equivalent per day and be in a position again to increase our firm sales volumes for 2026. In Canada, you'll see we have drilled an additional couple of wells that will be brought on production here later this month, and we expect to drill a couple more as we exit this year. Just jumping into some of the key highlights from our results released yesterday, this first slide here that we'll go through is our operating netback. Again, a reminder that is a non-GAAP measure. It's a measure of our operating profitability. We express it in per barrel of oil equivalent, and that's the green bars that you see on the chart. To compute that, we start with our realized price. At the very top of the chart, we deduct off royalties in the orange bar. The gray bar, we've aggregated both our production expenses and transportation expenses, and then the net result is our operating netback. Looking at Q2 2025, we saw a marginal decrease, about $0.47 per BOE in our realized price, overall average realized price company-wide. We did actually have an increase in our realized natural gas price in Brazil, up 2% to $10.62 per MCF. With bringing on our Canadian operations, our overall company-wide realized price did decrease just marginally. On the royalties, that orange bar, our royalties were down $4.63 from last quarter. If you recall our last earnings call, we did have some historical adjustments in Q1 recognized relating to a dispute on our gross overriding royalties on natural gas. With those historical amounts in that, we did see a decrease in our overall royalties this quarter. On an effective royalty rate as a percentage of sales, it was 4.7%, which was 4.2% in Brazil, and then in Canada, 16.3%. It does include our Crown royalty charges, any gross overriding royalties applicable, and then on freehold lands, our freehold royalty rate, as well as the Saskatchewan resource surcharge. Moving on to production expenses and transportation expenses, we've aggregated that in that gray bar there, totaling $5.51 this quarter, including production expenses of $5.37, which is relatively consistent with last quarter. We do have transportation expense in Canada for clean oil trucking that worked out to $0.14 per BOE company-wide. Overall, we generated a netback of $54.72 that was up close to $4 from last quarter. That includes a Brazil operating netback of $56.08, which was up over $5 from last quarter, and then in Canada, $32.07 U.S. operating netback. Overall, really strong netbacks still in place here. If you look at our operating netback margin, which is that line at the top, that's our operating netback expressed as a percentage of our realized price. We are at 87% this quarter, and overall for the last six quarters, you know, well above 80%, and that's, you know, really best-in-class netback margins compared to companies operating in Canada and in South America. You layer in the fact that we have a very low effective rate in Brazil. We're eligible for a tax incentive of 15%. The fact that in Canada, you know, we have significant tax pools to offset our current earnings in Canada. We're not expecting tax in Canada this year. Overall, that allows us to generate really strong funds flow from operations. Going into funds flow here, just a reminder that's cash flow from operating activities before changes in working capital. This chart just highlights the change from Q1 of $9.2 million this quarter. We're at $1.1 million to $10.4 million of funds flow. Basically, all of that is due to that royalty change without those historical royalty amounts that I talked about in the operating netback discussion. Similarly, on net income, overall operating netback higher with those lower royalties. Depletion and depreciation expense also decreased compared to last quarter, and then those were offset by lower foreign exchange gains this period and then higher current and deferred tax. Overall, net income went up about $800,000 to $6.8 million this quarter. On the balance sheet side, these green bars that you see go through our working capital, including cash balances. We've shown this since we started natural gas sales back in July 2020, so over five years now. This quarter, our working capital was $6.8 million. We did see a bit of a decrease from Q1 and Q4 2024. We have had higher capital spending the last two quarters, as you've seen. That has resulted in a decrease in working capital, but still a very strong working capital position. Our cash balance is still $15 million as of June 30th. We are debt-free as well, I should point out. All right. Just on our dividend history, all the way through last year, we paid a dividend at $0.09 per share quarterly. With the new gas sales agreement and the higher sales volumes that I walked through earlier, we did increase the dividend starting in the first and second quarters of this year to $0.10 per share quarterly. Since inception, when we started the dividend in the third quarter of 2021, we've now paid $58 million or $1.60 per share back out to shareholders over that time. Just walking through our more, I would say, disciplined capital allocation model that we'd introduced quite a while ago. Our model is to reinvest about half of our cash flows in growth and return the other half to stakeholders. If you look at the chart on the left-hand side, the green lines with the black dots are all the cash inflows each quarter. Most recently, as Alison walked through, $10.4 million of funds flow from operations this quarter. All the different stacking bars show the cash outflows in each quarter. The yellow is the reinvestment, and the various shades of green show the return to stakeholders. As Alison noted, we did have higher capital expenditures, particularly in the last two quarters here, as we had simultaneous investment programs happening both in Canada and in Brazil. We would expect that as we move into the fourth quarter to reverse and slow down a little bit. If you look at the pie on the right-hand side, you could see since starting up production of natural gas in Brazil, we've had cash flow from operations or funds flow from operations of over $183 million now. 49% of that's been reinvested. 48% of it's been returned to stakeholders, and the remaining 3% represents the portion where we built that cash and working capital position that Alison walked through. We have established a strong gas infrastructure platform, and our focus is firmly set on our next growth objectives. Our near-term target is to be at 18 million standard cubic feet a day, or 3,000 barrels of oil equivalent, which will roughly fill our current gas plant capacity. Our longer-term vision is to double this. Reaching these objectives is planned to come from a combination of our assets. Our first is our core base of operations, which is Caburé. The Caburé unit has been performing very well, and we're looking to further expand this unit capacity with our development well program. This program is currently underway with three of the five wells drilled and our fourth one to be finishing drilling this month. However, our biggest growth opportunity is the Murucututu project, which is 100% working interest for Alvopetro, and this is just north of Caburé. We had a very successful completion late last year on our 183A3 well, which is on production now. We're now focused on the completion and the tie-in of the 183D4 well that was drilled earlier this year. For this asset, GLJ has assigned a combination of 2P reserves, contingent, and prospective resources to this opportunity. We are working to migrate this into production cash flow in support of the longer-term growth objective. Just some more detail on this main growth opportunity in Murucututu. Like I mentioned, this is 100% working interest to Alvopetro, and it's just north of Caburé, and it's pipeline connected to our sales infrastructure. Earlier this year, we finished drilling the 183D4 well, which followed up on the A3 success of last year. The logs are shown on the right-hand side of the slide, and we identified 61 m of net pay over three Curaçú sequences, 6.2 - 6.4. This is the same formation as being produced in Caburé. It's just across the fault, and it's a bit deeper. The well was completed after we drilled it. We completed it with sliding sleeves in the casing program over eight spots within the Curaçu formation. We have just finished completing seven of these sleeves, and we're in the process of configuring the well for initial production right now. Note that in our 183A3 well, we have production only from the top sequence, sequence 6.4, which is in the D4 well, just the top three sleeves there that you can see with the cursor on the right. For the D4 well, we've completed 6.2 and 6.3, and we're commingling all of that and putting it on production later this quarter. All right. Just moving on to the Western Canadian entry that we announced on February 5th of this year. Remind you, our initial focus area is on the Mannville Stack. This is a resource that straddles the Alberta-Saskatchewan border. We're on the Saskatchewan side of the border. It's a multi-zone area. You can see up to eight different horizons that can be targeted. Our first two wells targeted the General Petroleum and the Lloydminster formations that you see there. This is a pretty exciting play, I would say. We've got stacked multi-zone potential, and it's really something that's being reinvigorated through the application of open-hole multilateral drilling technology. There's a large amount of original oil in place in roughly 3m-5 m thick sands that we're targeting here with excellent reservoir quality. The red dashed line that you see on the map here is our AMI with our partner. The yellow is our lands here that you see. As we announced, I think on our last call, we did drill the first two earning wells to earn into this play, the 100% to earn 50% in all this. Those first two wells were drilled at Neilburg South and Lashburn. More recently, we just finished drilling the next two wells, both at Big Gully. You can see on the northern part of the map sheet there. We were able to drill both those wells with eight open-hole legs, totaling over 19 km of open-hole horizontal reservoir access. We'd expect both those wells to be on production later this month. I would say we're extremely pleased with this entry into Western Canada. Part of the reason we did this is, you know, we've got exposure to much lower geological risk, I would say, an excellent and competitive service environment. Our individual well costs are much lower. We've got the ability to very effectively apply leading-edge technology to a proven resource that can generate very strong economics, short cycle times, and rapid payouts. I think we've got a lot of opportunity in a basin that really is starved for capital. The nice thing is we've got a big inventory of locations that we can get after here. To put this all in perspective, I think it is kind of remarkable that we signed this deal on February 5th of this year, and we've already got four wells drilled, and we'd expect to have all four on production within the first seven months of starting out here. We're pretty excited about it. Just talk about the individual well performance from the first two wells that we brought on production. The two kind of more straight lines that you see here, the upper one, the blue line, is the type curve that we had established before we did the farm-in. The lower dashed line is just basically 80% of that type curve. Respectively, we would recover 121,000 bbl or 97,000 bbl of oil on an expected ultimate basis. You can see the rates of return at a $70 WTI that that type curve can generate close to 100% rates of return, payouts of basically a year, extremely strong economics. From the individual well performance, it's the more jittery lines that you see there. The Lashburn well, the green one, was the first well that came on production. The Nealberg South well was the blue one. You can see the first one performing within that expectation range, and the Nealberg well significantly exceeding expectations. What we've done here is just created an indicative multi-year development. It shows four wells being drilled this year, and then basically 12 wells per year, a total of 52 wells. Roughly half of the inventory that we're currently seeing, but it just gives you an idea of what this looks like on a multi-year basis. The green lines show the dollars, and the black lines show the production. The solid and dashed lines match those type curves that you saw on the previous slide. What is interesting, the green lines match the right-hand axis. You can see for a maximum capital exposure of between $7 million and, say, $9 million, we have the opportunity here just at those type curves to build somewhere between an 1,100 and 1l,400 barrel of oil per day production platform that, after returning all the capital, has the potential of generating free cash flow of up to $80 million. We're off to a good start, and we're very excited about this. To conclude, I think we continue to deliver some pretty strong results. Obviously, we've still got very attractive natural gas prices with industry-leading operating netbacks and margins. Our strong Q1 and Q2 results this year, off strong production growth. We've got a clean balance sheet, very good free cash flow generation capacity that helps really underpin that more balanced capital allocation model that I reviewed earlier. For value investors, we're still trading at less than our 1P NPVs and about 45% of our 2P NPVs. For yield investors, that $0.10 U.S. per share quarterly dividend translates into a yield of over 9%. For growth investors, I think we've got a very exciting organically funded capital program that has the potential to unlock an awful lot of value, especially when you consider it relative to our existing enterprise value. Now, with the ability to deploy capital in high rate of return opportunities, both in Brazil and Western Canada, I think we're positioned better than ever. As a result of that, we've significantly strengthened our capital allocation model. I think Q3, in particular, is going to be a very exciting quarter for us. We've had a lot of simultaneous activity here. If you think, we're going to bring on four wells out of the new wells out of the unit, we've just completed the completion at the 183D4 well, which looks extremely exciting. Expect to have that well on production later this month. The latest two wells that we drilled in Western Canada are also coming online, roughly around the end of this month. It's an exciting time, certainly, to be an Alvopetro shareholder. With that, I'll turn it over to the question -and -answer period. Okay. We've got a few questions in. How many drill locations are ready at Murucututu, and when do you expect to drill the next well on that property? If you look at our broader corporate presentation, what you can see is there's some actual, there's some aerial photos of the three well pads that we've got. Our 197-1 well is producing from one pad. We've got our field production facility and our 183A3 well from another pad, and then the D pad, where the 183D4 well was just drilled and completed from. Three different pads. We can probably drill at least six additional locations from those pads. We're looking at licensing another pad to access some of the more southern locations, and that's in the works right now. I think the second part of that was when will the next wells be drilled. We're looking at the contracting and procurement and all that for those wells. Practically speaking, we're probably looking at the early part of next year. We'll get the results from this current D4 well that we're bringing on production, incorporate that, and then look at restarting drilling next year. Do you have any expectation on production rates from the 183D4 well? Yeah, we don't really put out those production guidance, but if you look at our 183A3 well, it's been producing about 53 m³ per day, roughly. That's just from that upper sequence that Adrian talked about. We don't really want to speculate, but we're obviously completing more of it, and we're optimistic about it. Do you have any drilling plans for block 183, the portion of the block that is not part of Murucututu? Yeah, we actually just recently, we have another prospect that we had identified there. We've made an application to the A&P to extend the block, and we're working through all the permitting to do that. I forget when the new deadline is, but we've got several years to. 2027. Thank you. Yeah. To drill that location, it's not in the near-term plan, but the answer is yes. What are you realizing for Canadian oil sales relative to WCS pricing? I think in Q2, our average realized price in Canada worked out to just under $47, probably about a discount of around $9 - $10 Canadian from WCS in the quarter, which is, I think, roughly what we're expecting going forward. Staying on the Canadian side, there's a specific question about Nealberg and the well being well above the type curve. Can you discuss the difference in flow rates between the two wells drilled in Canada and how homogenous do you see the play? I think I got all that. Yeah, a lot of this comes down to, you know, part of the variance is, you know, I think our operator here did an amazing job staying in zone most of the time. I'd say that is one of the factors that can contribute to different operators achieving different results. The oil gravity and oil viscosity and the porosity and permeability are also big factors, I would say. There is, as you move through the play, you do, you know, there are some geological variability considerations to certainly incorporate. We are shooting some seismic around the Nealberg South area to help manage any of those potential risks. That's why you'd look, we're looking at restarting the drilling probably sometime in December so that we can incorporate all that 3D seismic and follow up on that good well result that we had here earlier this year. Sorry, I'm just going through these. Do you have a view on your outlook for exit production in Brazil this year? Yeah, that's, we typically don't provide that type of guidance. I think with the capital plans that we have over the short to medium term, our near-term objective in Brazil of getting to that 3,000 barrels of oil equivalent or 18 million cubic ft a day is firmly in our grasp and the Canadian side of it. I think we put all the pieces in place there that, depending on the capital activity and the pace of that activity, you can kind of, we put all the building blocks with those type curves. Hopefully, we can continue to exceed those, but I think if you use the type curve, the development plan that we put in there is, maybe it's conservative with respect to the pace at which we would ultimately do this, but it gives you directionally a good sense. Any plans to repeat share repurchases in Q3 of this year? We have been, to be clear. There's a modest amount of shares being purchased every day, and that's something that the board will continue to look at in the future, you know, the portion of the returns that go to stakeholders, looking at the balance of that between dividends and buy-backs. The Canadian production is rising. Do you see Canada becoming an equal size to Brazil in the next three to five years? Three to five years. Practically speaking, if you look at the well cost for the wells that we're focused on in the Murucututu area right now, wells that look similar to the 183D4 well, they're just, they are more, they're deeper. The completions are more expensive. Practically speaking, they're probably a little bit more expensive, certainly on a per-well basis. When you compare it to 50% of an open-hole multilateral well, those wells on a gross basis are costing about $1.8 million Canadian, not in U.S. dollars, and our share is 50% of them. The other interesting thing, what I tried to highlight with that indicative multi-year development plan in Canada is pretty quickly, because of those rapid payouts, pretty quickly you get to a self-funding state. The total investment exposure on that hypothetical 52-well program is in the $7 million to $9 million or even $10 million Canadian range, and that includes the initial two earning wells that we drilled. That's the other nice thing about the Canadian piece, it can become self-funding pretty quickly. Do you have any geopolitical comments regarding Brazil as it relates to oil and gas operations? Everything seems stable, with the recent news around tariffs, etc. Yeah, I think there's a lot of noise in the market, certainly around the tariffs, and it's not isolated to Brazil. I think Canada's impacted by it to even a greater extent, just given the relative amount of exports that come from Canada to the U.S. versus, I think in Brazil, only about 12% of their exports are going to the United States. I think closer to 30% is going to, for example, China. A good barometer, I think, for how the market feels about that is how the Brazilian currency is performing relative to other currencies relative to the U.S. dollar. I think there's been over a 12% appreciation in the currency this year, and even since some of the more recent tariff announcements, the currency's actually appreciated. That's probably a better scorecard than my personal opinion. Things are going quite well in Brazil. I think the track record of stability of contracts, if anything, the government's been very encouraging and implemented. The fact that we qualify for this enhanced income tax, a reduced income tax program of just 15%, that's certainly much more favorable than we have in Canada. The government's trying to stimulate activity through the reduction of royalties, especially for small and medium-sized companies. I think it's a pretty good place to be. All right. My neck. Yeah, last but not least, since on our last webcast, Corey did have a neck collar on. Somebody is asking how you are doing. Pretty good. I can move it around pretty well. Tying a tie is not that easy, hence the reason I don't have that on, but it's a combination of my neck and my shoulder. It's going well. Thank you for asking. Okay, that is it for questions. All right. Thank you, everyone, for participating. We look forward to doing this again in about three months' time. If you have questions in the interim, please give any one of us a call. Thank you again for the support. Thanks, everyone.