Alison Howard, our Chief Financial Officer. Hi everyone. Thanks for joining us this morning. Just a couple of administrative points before we begin: we will be recording today's webcast, and there will be a replay on our website later on this afternoon. In addition, just a reminder that everyone is placed in listen only mode for the duration of the presentation. We will have a Q&A session at the end, and you can log any questions that you have through the Q&A button on Zoom. If you've dialed in by phone, you can send your questions to social media at alvopetro.com, and we will get to all of those questions at the end of the presentation. Lastly, just a reminder that we do go through some non-GAAP measures throughout the presentation, and we do make some forward-looking statements. Please read through our cautionary statements and other advisories that are included on the presentation that's on our website. Great. Thank you, Alison. So just to start again with our average daily production, I think we presented this quite a few times. A reminder, we came on production in July of 2020. We've added this black dash line to this slide for this purpose, just to show you the firm volumes that we had committed with Bahiagás. So you can see when we first came on production, we were almost exactly equal to that amount, and that was equal to our share of the Caburé Unit production plateau at the time. That production plateau increased, and we also were able to increase our production from the unit well above those pre-commercialization expectations. And Bahiagás was able to sell all that gas on a flexible basis under our contract. Starting in the Q2 of 2023, our partner started nominating for more gas, and we've been back bouncing around closer to that Bahiagás firm level since then. Our production, we had previously announced this, was—it had increased quite a bit in the Q4 and then decreased back down in the Q1 of 2024. We did, with yesterday's announcement, announce April production of 1,808 barrels of oil equivalent per day. So that was up about 6% from our Q1 average. The other thing that has happened, there's been, I think, about four months through this period of time where we have had Bahiagás limiting our production because of some demand disruptions. You can see that reflected in a couple of cases where we're just slightly below the Bahiagás firm levels. Just talk about a couple of things. Our strategy here is to add more 100% working interest production to our portfolio so that no matter what's happening with production from the unit, we can be up closer to our 3,000-barrel of oil equivalent per day goal. The other thing that's happened, and I'll talk about it, is we just finished our first redetermination of the unit. So once that becomes effective, our share of unit production of the plateau goes up to about 2,300 barrels of oil equivalent per day. So with that redetermination result and with an expanding production base from our other projects, then that will position us well to also increase the firm volumes under our contract so we can increase this black dash line up and increase the guaranteed minimum amount of our cash flow levels. So just a little bit on the Caburé Unit redetermination process. Our unit operating agreement did contain their somewhat typical redetermination provisions, which can happen from time to time. The first of these was completed in April of this year. The result is that our working interest in the unit increases to 56.2% from 49.1%. Sorry, there's a typo there. It increases from 49.1%. What that does is, as I mentioned on the previous slide, it increases our production entitlement from the unit to almost 14 million cubic feet a day. We did have GLJ prepare pro forma reserves reflecting the redetermined working interest as though it had happened when we completed our reserves at December 31st, 2023. What that shows is that our 2P volumes increase by 11% up to 9.6 million barrels of oil equivalent, and our 2P NPVs go up by a similar amount, 11%, up to $342 million. Our unit operating agreement does stipulate that expert decisions are to be binding and that the redetermination is to be effective on June 1st, and it does provide the right for Alvopetro to operate as a result of that decision. We have noted in our previous disclosures that our partner is disputing this result. Because of that, Alvopetro moved to file an emergency arbitration injunction process to seek to make the decision effective as prescribed in our unit agreements. I think regardless of that decision in the emergency procedure, it is likely that the dispute will ultimately be heard by a full arbitration panel or tribunal. Our attempt with this emergency process is to make it effective in the interim period here. Just talk about our gas sales agreement with Bahiagás. Just a recap, our gas sales agreement gets reset semi-annually on February 1st and August 1st of each year. It's based on three different international benchmark prices, which are the gray dash lines that you see here. So this lower one is U.S. Henry Hub prices. This upper one is U.K. NBP prices. And then this dash line that you see through here is Brent oil equivalent prices. So left of this vertical red dash line is all the historical prices. And then in the future, this is the forward strip pricing as of May 6th that you see here. So the black line is the output of the formula within our contract. We also have a floor and a ceiling in red and green, respectively. Both those do escalate based on U.S. inflation. You can see we're pretty close to the ceiling based on these forecast prices, drops just slightly below it on the reset on February of 2025 based on these prices. The black dash line that you can just barely see here is the price that was used in our reserve report. We're almost exactly still at that price expectation. So just moving on to results from this Q1 of 2024, we'll talk about our operating netback here on this slide. Reminder that that's a non-GAAP measure. That measures our operating profitability. We express it in per barrel of oil equivalent, and that's computed as our realized sales price, which is at the very top of the bar chart. And then we subtract off our royalties, which are in orange, and our production expenses, which are in gray. And then the green bar is our overall operating profit or operating netback here. So this quarter, our realized sales price in per BOE was $75.94. That was a slight decrease from last quarter. Our royalties were relatively consistent from last quarter. As a percentage of the sales price, it worked up to about 2.7%. Our royalties on natural gas are based on an ANP reference price, which is more closely similar to Henry Hub, a proxy for the value of the raw unprocessed gas. So overall, that effective rate is lower than the stated royalty rate on our fields in Brazil. And then production expenses, those were higher at $7.76 this quarter. Most of our production expenses are fixed in nature. So when we have that 21% reduction in sales volumes from Q4, our overall cost per BOE did go up. In addition, overall, our operating costs in Q1 were about $49,000 higher than Q4. That was mainly due to some workovers that we completed in the Q1. So that gave us a netback this quarter of $66.16. And while that's down about $3.53 from last quarter, when you look at that relative to our realized price of just under $76, that's a profit margin or netback margin of 87%, which is very high in this industry. When you look at other peers operating in Latin America and North America, this is best in class. When we layer onto that, this is expressed before income tax. But our income tax rate in Brazil is just over 15% due to this benefit that we get on virtually all of our profits in Brazil. Overall, this helps us to generate very strong funds flow, which we'll go to here. Again, funds flow from operations is basically cash flow from operating activities before changes in working capital. When we compare to Q4, which is the bar on the left-hand side there at $12.4 million, we did see a decrease of about $3.9 million this quarter. Most of that was due to that 21% reduction in sales volumes. Also, the realized price reduction that I talked about on the previous slide, those production expenses, as I mentioned, were a little bit higher. G&A in Q4 was a bit lower because we had reductions for final 2023 bonus amounts. So consequently, G&A this quarter is a little bit higher. Overall, very strong funds flow still at $8.5 million. Moving on to net income. So despite that reduction in our funds flow, we did see a $3.9 million increase in our net income from the $652,000 last quarter to $4.6 million this quarter. Most of that was due to changes in impairment. We did have just under $11 million of impairment losses booked in Q4. That is partially offset by foreign exchange losses this period versus gains last quarter and then higher deferred tax. Last quarter was impacted by deferred tax asset recoveries on those impairment losses. Overall, the quarter of $4.6 million net income. On the balance sheet side, these green bars here show our progression of working capital through the various quarters since coming on production. As of March 31st, we have over $15 million of working capital, which is current assets less current liabilities. That includes cash of just under $17.5 million. A reminder that we've fully repaid our credit facility back in September of 2022 and have been debt-free since then. We are well positioned with a very strong balance sheet going forward for our plans. All right. Thank you, Alison. So we did previously announce our Q1 dividend. We did reduce that based on the production decrease that we talked about and the anticipated reduction in cash flow or funds flow from operations, consistent with our longstanding policy to return roughly half of our cash flows to stakeholders and reinvest the other half in organic growth. In total, since we started the dividend in the Q3 of 2021, we've paid out over $40 million or the equivalent of $1.13 per share of cumulative dividends to shareholders. Based on our current share price, that $0.09 dividend translates into a yield just over 10% right now. So this disciplined capital allocation model that we talk about, again, the idea is to reinvest half of our cash flows in organic growth and return the other half to stakeholders. This chart here, all the black dots and the green line that you see here is the Funds Flow from Operations that we've had quarter-over-quarter. Alison walked you through the $8.5 million that we generated this quarter. And then each of the bars just shows where we've invested that money. So a reminder at the very beginning, we pre-invested in the Caburé Unit to get that on production. So we had very little capital requirements in yellow, and almost all of the cash flow went to an accelerated repayment of our outstanding debt. We did buy back some shares in the Q3 of 2021, and then we also started the dividend in the Q3 of 2021. So the dark green wedge that you see there. And then more recently, you have seen us investing in capital expenditures, which are in yellow. In total, if you look at that since we came on production from the Caburé Unit to the end of the Q1 here, you can see this has been quite balanced. We've had 48% of our cash flows, which have totaled now $139 million. About half of that has gone back to stakeholders in the various forms of either the capital lease on our gas plant, debt and interest payments, and the vast majority of that's in the form of dividends. And about 43% has been reinvested. The rest of it, the blank portion of the pie here, 9% of that's gone to build the cash and working capital position that Alison walked you through a couple of slides ago. So just to talk about our organic growth plan going forward, again, our near-term objective is to be at 18 million cubic feet a day or 3,000 barrels of oil equivalent per day. From our core business, we did expand the gas plant back in the middle part of 2022. The Caburé Unit has been performing quite well. We expanded the productive capacity of that along with our partner. And then the biggest part of this is because of the redetermination result, our share of the unit production is expected to increase here once that becomes effective. With respect to our Murucututu asset, which sits so sorry, the Caburé Unit sits right here. The gas flows down this pipeline to our gas processing facility that sits to the west. Our main growth acreage sits immediately north of the Caburé Unit. It's all 100% working interest. We call it Murucututu. We've got three existing wells. They're all pipeline connected back to the unit here. We're just in the process of doing optimization projects on each of those three wells. We just completed a chemical treatment program on our 197-1 well, and that well is in the process of being brought on production now. The recompletion that we've got planned in the 183-1 well is expected to start here in the next couple of weeks. Following that activity, we'll do the final completion in our 183-A3 well, targeting a number of the Caruaçu zones that we encountered in that well. The idea is to take that recipe that we have and then apply that to a much broader development plan. It's a multi-year, multi-zone development plan covering this entire asset. We have had this asset assessed by a GLJ, our independent reserve evaluator, and they've assigned a combination of 2P reserves and risked best estimate and contingent and prospective resource to this of 4.6, 5.4, and 9.6 million barrels of oil equivalent, respectively. So there's a lot of growth potential for us here. We can execute this on an organic basis, and we're looking forward to migrating this resource into production and cash flows over the coming years. So just to conclude, to re-summarize this, I think I've said this before, but I do firmly believe Alvopetro continues to offer a very attractive investment proposition no matter what your focus is. I think our results speak for themselves, but we're generating industry-leading operating margins off the back of very attractive gas prices. We've got a clean balance sheet with extremely strong free cash flow generation capacity that helps really underpin this balanced reinvestment and stakeholder return model that we've got. For value investors, we're trading at about one-third of our 2P NAVs. For yield investors, the dividend represents about a 10% dividend yield with dividends paid quarterly in U.S. dollars. And for growth investors, we certainly have a very exciting and organically funded capital program that has a lot of potential, especially when you compare it to our current enterprise value. So with that, I'm going to stop sharing the presentation, and we'll turn it over to a question and answer. Okay. The first question that we have is, are you inclined to exercise your right to operate Caburé? Are there clear advantages to that? Yes. With a working interest over 50%, our preference would be to operate the field. There is a development plan that we've agreed to with our partner. We'd like to see that executed on an expedited basis. There's 5 wells planned there. Yeah, that's our intention. Can you give an update on how you see the Brazilian gas market demand and more specifically the region you are working in? Has there been a significant impact from strong renewable power generation, and how much of this is structural versus transitory? Yeah. So a couple of parts there. So we'll talk about Bahiagás. One of the things that they are due to they have, I think, up to 10 suppliers of natural gas now. So they've been one of the leaders probably in diversifying their portfolio of gas as the gas market opened up in Brazil. And then they've got hundreds or thousands of customers that consume the gas. I think there has been probably close to 8% or 9% impact on demand that's happened to their demand base. It's otherwise pretty stable. They are impacted from time to time due to plant turnarounds or temporary disruptions within their customer base. The other thing, what they did is they basically committed to all their supply on a firm basis for both 2023 and 2024 quite far in advance. So especially for this year, it reduces their ability to kind of manage any of those demand decreases that I talked about. But for 2025, they're going through a process now to contract all that firm supply. So they'll be able to make those adjustments. And we have the ability the ideal thing for us would be to increase our firm volumes under our contract. And they're still quite keen to be prioritizing Alvopetro Gas, partly because we're directly connected into their distribution network. So it helps improve our net realized price, but it also helps reduce the absolute cost of the gas to the end consumer. The second part of your question is renewables. Yes, Brazil has been quite aggressive on adding renewable electrical generation. I would say that demand wedge is kind of treated separately so that the natural gas component or competition for that would be in thermal power plants. And I would say Brazil generates a lot of their electricity through either hydroelectric or renewables. So there certainly has been an impact on the thermal power side with respect to how often those plants are dispatched because of that renewable energy. Can you give an update on expected CapEx for 2024 and how this has changed from guidance in the 2023 annual filings? So, I can do that. We don't really give guidance on the overall CapEx, but we do go through the specific projects we have in detail within the MD&A that we file. So there has been no material changes since the Q4 filing on March 19th. So our main projects on the Murucututu field, we have the projects on the two wells, 183.1, the recompletions on 183.1 and 183.A3, as well as a plan on 197.1 to optimize production there. So those total for the year, about $4.2 million. We did have some spending in Q1, so about $3.7 million remaining for the rest of the year. At Caburé, we have this five-well development planned at the unit that Corey referred to. That'll go 2024 into 2025. At our new working interest, that's estimated at $7.1 million with $4.2 million in 2024. We have the facilities upgrade plan. That's 100% Alvopetro. That totals $3.2 million. There was $1.4 million in Q1, so approximately $1.8-$1.9 million remaining on that. And then on our exploration blocks, we do have a stimulation planned on one well there, and that's about $500,000. So those are the main things. With respect to the unit and the redetermination there, once that's finalized and effective, there is some historical catch-up on the CapEx at the new working interest. So that would be added on top of that. That's estimated at $1.2 million right now. Next question. Given the continued strong free cash flow, large cash position decline in share price, and the cut to the dividend, what are your thoughts on buybacks? Yep. We've talked about this a lot. I think this is something that the board, especially at these valuations, will be looking at as we make decisions on the stakeholder return portion of the pie. And particularly, I think, as we increase the cash flow back up, I think it's a good opportunity to reevaluate that. So ultimately, it's up to the board, and it's something we'll be looking at in the context of dividends and/or buybacks. Okay. I just checked the social media email, and there's no questions there. I think that is the conclusion of the questions that we have through the Zoom portal as well. All right. Thank you, Alison. Thank you for everyone joining today. If you didn't have a chance to ask your question, as always, feel free to reach out to myself or Alison, and we're looking forward to updating you on the next call. Thank you very much. Thank you.