Good morning. Thank you for joining us today for our Q2 2026 results webcast. I'm Corey Ruttan, President and CEO, and I'm joined by Alison Howard, our Chief Financial Officer, and Adrianna Dec, our Vice President, Asset Management. Hi, everyone. Just a few administrative points before we begin. We will be recording today's webcast. We'll have a replay available on our website later on today. All attendees have been placed in listen- only mode. We will be hosting a Q&A session that we'll get to at the end of our presentation. You can start logging any questions you have now using the Zoom Q&A feature. You should see a button on your screen there. You can start sending in any questions at any time. If you dialed in by phone, you can send questions to socialmedia@alvopetro.com. Lastly, we will be going through various non-GAAP measures, oil and gas metrics, and we will be making some forward-looking statements throughout this presentation. Please do read the various cautionary statements we have at the end of our corporate presentation that's posted to our website and all of the further disclosures that are in our MD&A, also on our website. All right. Let's talk about our production. Recall we had some pretty strong results last year. We had 41% year-over-year production growth last year. Certainly the first half or first part of 2026 here is off to a pretty strong start as well. If you remember, we had record quarterly production in Q1 at over 3,100 barrels a day. Q2 at 3,067 barrels of oil equivalent per day was pretty consistent with that. We also announced yesterday our July production update, which again is over 3,100 barrels a day. First seven months of 2026, again, quite strong. Roughly another 25% over that 2025 average that we had. Okay. We'll just go through some key highlights from our Q2 results. Starting with our operating netback, which is the green bar that you see on the chart there. Operating netback is a non-GAAP measure. It's a measure of our operating profitability. We express it on a per barrel of oil equivalent basis. To compute that, you start with your realized sales price, which we see at the top of the bar chart. You deduct off royalties in orange. We've combined production expenses and transportation expenses in the gray bar. The net result is our operating netback. Looking at Q2 2026, we saw close to a $7 per BOE increase in our realized sales price. A nice uptick there with higher commodity prices throughout the quarter, including natural gas sales of $10.98 per Mcf, which was up 8% from Q1. Our royalties, the orange bar, despite higher prices, our actual effective royalty rate, and our overall royalties per BOE decreased into the period. That just highlights the strength of the fiscal regime in Brazil that we have our royalties there. The effective rate was 5.3% this quarter, and in Canada, just under 15%. On our production and transportation expenses, again, once again, low production costs, less than $6 per BOE. Very attractive cost structure there. That generated an operating netback of $59.08 per BOE up again just under $7 per BOE, driven by those higher realized prices in the quarter. When looking at our realized price of $59.08 relative, our operating netback of $59.08 relative to our realized price of $68.72, that's an operating netback margin of 86%, which is truly best in class, and I think really highlights what we're doing in Brazil and the kind of cash flow we can generate on this production. I don't think you find another company our size operating in Canada and internationally with these sorts of netbacks. When you layer in the fact that we have a tax incentive in Brazil that reduces our tax rate to just over 15%, we're not currently taxable in Canada. We aren't paying any tax on our cash flows out of Canada. That just allows us to generate really significant funds flow on these barrels that we're producing. Looking at our funds flow. That's cash flows from operating activities before changes in working capital. This chart just shows the change from our Q1 funds flow of $12.5 million to our Q2 of $14.1 million, an increase of about $1.6 million this quarter. Again, that was driven by those higher realized prices we saw, partially offset by some higher G&A and current tax in the period. If you think about our funds flow of $14.1 million relative to our revenues this quarter of $19.2 million, that funds flow margin is 74%. Again, highlight what I was talking to you on the last slide. This is really significant cash flows that we're generating, which is great. Net income, very similar story there. An increase of $1.7 million, again, driven by those higher prices. We did have some increases in some non-cash expenses, depletion and impairment were up. Our foreign exchange gains were down marginally compared to last quarter. Our deferred tax was actually lower, that increased our overall net income. Net income of $9.8 million this quarter. All right. As we previously announced, we paid a $0.12 per share dividend in the second quarter of this year. That represents a yield of just under 7% at current share prices. Since inception of the dividend in the third quarter of 2021, we've now paid $2.06 per share or $75 million in dividends back to shareholders. Pretty proud of this. This is a chart we show just to highlight our more disciplined capital allocation model, where we're balancing organic growth and returns to stakeholders. The chart on the left here, you've seen this a lot. The green lines with the black dots are our cash inflows or funds flow from operations every quarter that Alison reviewed. You can see just over $14 million in Q2 of 2026. That was up 13% from Q1 and up 36% from Q2 or the comparable quarter, in 2025. The bars on this chart, all the different shades of green show the returns to stakeholders. You recall we very quickly repaid the project financing that we had in place at the beginning of our project. We introduced the dividend and you can see each quarter how that looks. The yellow bars are the capital expenditures that we have each quarter. In total, the pie on the right, since coming on production on July 5th of 2020, I think we've now had cumulative funds flow from operations of just over $230 million, and almost exactly half of that's gone to reinvestments in capital expenditures and organic growth, and just shy of 50% has gone to the various forms of stakeholder returns. Pretty consistent with that model that we'd established quite some time ago. From just an update on our gas pricing situation. Recall, we do have two contracts that we're pricing gas under right now. Our original QDC1, which comprises about 80% of our firm volumes right now is the red line. There's a formula in the appendix, the detailed formulas in the appendix or the notes to the presentation. It moves based on Henry Hub and Brent, 20% of our gas is being priced under QDC, and that's entirely a function of Brent oil prices. You can see with the appreciation in Brent oil prices, we have seen an uptick in that. The green is the weighted average between those two formulas. We announced, not too long ago that our August 1st price reset just increased up to $11.70 per Mcf. That is up 7% from those gas prices that we have just announced today that we realized in the second quarter. The futures prices that you see here are just using those formulas and based on the August 4th futures market or futures prices for both Henry Hub and Brent. You can see what that looks like moving forward. We have established a strong platform in Brazil and think we have a solid multi-year growth plan. Now 2026 is really focused on our next phase of growth for Murucututu, following up on the earlier successes here. This year, we are increasing field processing and takeaway capacity fourfold for the field facility at Murucututu. The off-site fabrication of the main processing equipment for this expansion is underway, and we look forward to installing this equipment in the field over the coming quarter. We are also expanding the field egress by increasing pipeline capacity to 600 E3m3. We are looping the existing 4-inch pipeline with an 8-inch line. Right now, our pipeline contractor is mobilizing and they are conducting the initial works in the field. Also the line pipe for these pipelines is being delivered to the location. You can actually see the line pipe being stacked there at the location there at the bottom, the picture on the bottom right. Right now, we are currently completing the 183D-1 Caruaçu development well. This completion is in its final stages right now, and we expect to have production from this well in August, and we will have it on stream. We have a drilling rig right now sitting and working at the H2 location. That is the picture in the top right. We are in the final phase of this well, and we plan on finishing this well sometime in August. You can see at the top right there. With success, the completion is expected to happen in the fourth quarter. That location is actually currently tied into our production facility. Once we complete it, we expect to have flowback production. This well is targeting the prospective resource area of the Caruaçu Reservoir. We are also finishing the G drilling pad right now to support a four-well Caruaçu development location. That is the picture on the bottom right. That is a four-well pad. The pad will be connected via an 8-inch pipeline to our Murucututu facility. Once the drilling rig is done at our H2 location, we will move there and target the FDP wells in that Caruaçu structure. All right. Just to recap on our Western Canadian asset base. Again, we're focused on the Mannville Stack play fairway on Saskatchewan side of the border, you can see in the green dashed outline here. We've fully earned all the activity on our two farm-ins that we did last year. We have a 50% interest in 104 sections of land now. To date, we think we've delineated three core areas so far, and we've got an attractive inventory of over 100 Tier 1 drilling locations. We're working to move our next phase of drilling forward here. Just before we jump into the Q&A, just to summarize, I think, again, we've got some very high quality assets here with some strategic infrastructure, very attractive natural gas pricing with industry leading margins and extremely strong free cash flow generation capacity. That all helps support that more balanced and disciplined capital allocation model that we have. For value investors, we're currently trading at about two-thirds of our 2P NPVs. For yield investors, like I said, that $0.12 per share dividend that we paid represents a yield of close to 7%. For growth investors, I think we've got an extremely exciting capital program here this year that has the potential to unlock an awful lot of value, especially when you consider it relative to our current enterprise value. I think we've coupled some very strong growth prospects in Brazil now with an attractive inventory of opportunities in Western Canada, which is a nice balance. Just remember, we had a pretty strong year last year with 41% year-over-year growth. 2026 is shaping up to be another pretty good year for us, as you can see. I think our capital program from this year will position us extremely well to continue that growth trajectory into next year and beyond. We'll just start the Q&A section. I'll stop sharing the screen. Okay, perfect. We have a couple questions around Brazil and how many drilling locations over how many years in Brazil, how many inventory locations we have to drill in Brazil. Yeah. For our Caruaçu structure and the reserve report for that development, we have six locations, and we just finished drilling one of those. We have five remaining locations. As I noted, we're drilling the H2 location. That is a prospective resource location, so that would be part of those five. From the Gomo structure, we have two locations, and then we have a number of follow-on locations in the prospective and contingent resource category. Okay. You've noted that you're adding more wells sooner in Brazil and increasing field capacity. However, your gas sales contract is still 500,000 cubic meters a day. How can we expect this activity to translate to production and sales increases, and when? Yeah. Maybe walk through this in steps. Like Adrianna just talked about us completing the D-1 well in the short term here. Literally in the next couple of weeks, we expect to have that on production. I would look at that a little bit more as adding redundancy or insurance of well productive capacity beyond what we have today. It's going through our existing facility infrastructure, so it really helps support that current big Bahiagás firm sales capacity that we have. I think it is reasonable in the short term to assume that we stay probably closer to those H1 production levels that I walked through earlier. The next kind of key milestone is basically when we get the UPGN optimization or project completed that Adrianna talked about. We're still trying to target that to be done ideally by the end of September. That gives us more flexibility to produce a higher percentage of our production from our Murucututu field. In advance of the Murucututu projects being done, which I'll talk about next, again, it's probably reasonable to assume we stay roughly close to H1. It does give us the ability to sell some additional flexible gas to the Bahiagás, the more material increase or potential comes once those Murucututu field expansions are completed that Adrianna walked through. That's the field production facility and the pipeline project, and we're targeting to have those done sometime roughly around the end of the year. We can layer in additional flexible sales to the Bahiagás and/or add additional firm sales like we've done in the last couple of years to expand our sales capacity to match those facilities expansions. The drilling projects that we're doing are obviously Murucututu focused. We've accelerated some of that from 2027 into 2026 to take advantage of kind of that continuous drilling program with our current drilling rig. We'll be building productive capacity to match those production or the facility enhancements that we're doing this year. Okay. We have a few questions on Canada, specifically why we've seen little well growth within Canada, especially in the context of oil prices being quite strong and yet we have little drilling activity. Can you update on plans for Canada for the second half of 2026? Yeah, no, those are fair and good questions. I think earlier we had guided that we were hoping to be doing some activity here this summer. We are working with our partner to advance those programs. We do have mechanisms within our contracts and within the standard agreements in Canada that we can also drive activity forward and the pace of activity. In parallel, we're preparing that path. In reality, it probably means we're drilling sometime in the winter as opposed to we thought we could get a couple of wells down here this summer. Just delving a bit more into Canada, there was a question about if we had any CapEx spending in Canada during the quarter, and we didn't really. There was very minimal activity in Canada. There is a question about the base decline on the existing seven wells. Obviously, we've moved into a flatter part of the production curve now. We did have some production interruptions due to basically just engine shutdowns from overheating during some exceptionally hot periods here. That was a relatively small impact. There was some downtime in there, but I think we moved into the flatter part of the curve. Shifting back to Brazil and our 183-D1 well, it was noted as completed in three intervals, June press release guided up to seven. Is there any rationale for there being only three intervals? Are there remaining intervals behind pipe for later recompletion? I can answer that. Initially, we had looked into completing seven intervals. When we finalized our completion program, we targeted up to five intervals in that program, due to a couple of operational challenges as we went through the program, we were only able to complete three. Those three are each in the individual Caruaçu subsequences. We have a strong stimulation in each one of those sequences. We do believe we have communication to the majority of the net pay that we were initially targeting. Back to Murucututu overall, is there any reasoning for the volume reduction from 2.3 million cubic feet a day in July from 4.3 million on average in Q2? I wouldn't read much into that. I think it's just us balancing the production between Caburé and Murucututu and managing our facilities. Like we said, the facilities projects we're doing this year will give us a lot more flexibility and allow us to increase the proportion of gas that's coming from Murucututu. Can you walk through why the price reset for August 1st was lower than the one that was initially indicated during Q1? Good question. That's the challenge. The best information we can provide when we're doing those projections, which I walked through earlier in the presentation, is the futures market, there's been a lot of volatility in that. I forget what date it was, but if you look back at the futures market on the date or the day before we did that presentation versus today, what actually happened leading up to August 1st, that's where the difference arises. We have a few questions, more corporate questions. Any reasoning for no stock buybacks in 2026? This is something that at the board level, we're discussing all the time. I know our shareholders have a lot of mixed views on this. Yeah, no, the 50% of the pie that's going back to stakeholders, obviously, we can do buybacks or dividends. We recognize we are in a phase here where we made a decision to accelerate some of the capital from next year into this year, like I said, to take advantage of the drilling synergies and a continuous drilling program. Basically, the board made the decision to prioritize dividends and reward our existing shareholders and accelerate that capital activity. Is M&A likely for Canada between now and the end of 2027? Yeah, there's obviously a lot of opportunities in Western Canada. We don't talk about specifics on those things, there certainly are a lot of opportunities that come our way, and we continue to look at them, we can't comment too much on those things. One other question here about our cash position. The cash position continues to increase. What are your current thoughts on the size of this cash position? Are there plans to accelerate CapEx or return the excess to shareholders, or are you keeping the powder dry for acquisitions? Well, mostly it relates to that. We put some debt capital in place last year. We haven't really used it. That's part of the issue is that cash is still sitting there. Part of the reason we did it is it gives us the flexibility to do things like accelerating those couple of wells that we had planned for the first half of next year. We're now drilling one of them, and we'll be drilling the next one immediately following that. That's part of the reason we put it there. We will use some of it to do that activity. There is a question, what is the second half of 2026 CapEx expected to be? Is it in line with the initial full year guidance for CapEx? We did have some disclosure in our MD&A about this. Our CapEx in the second half of 2026 is forecasted to be just over $29 million, and that's largely because we've now accelerated those two wells that Corey just mentioned, those two Murucututu wells. It is higher than our initial guidance. That's the reasoning. That ties into the answer on the cash balance that we're sitting on right now as well. Let me just check social media. Nope. Okay, no, we have no further questions at this time. All right. Well, thank you, everyone, for joining. Feel free to call if you have any questions following this, and we look forward to updating you again in November. Thanks, everyone.