All right. Good morning. Thank you for joining us today for our Q1 2023 results webcast. I'm Corey Ruttan, President and CEO, and I'm joined by Alison Howard, our CFO, and Adrian Audet, our Vice President, Asset Management. Good morning, everyone. Thank you for joining us this morning. Just a couple of administrative items. We are recording this webcast. We will have a replay available on our website later today. In addition, we will be hosting a Q&A session at the end of the presentation, so if you have any questions, you can use the Q&A portal on Zoom to insert your questions, and we'll get to those at the end of the presentation. If you're dialing in, you can send your questions to socialmedia@alvopetro.com. Lastly, we are not going to go through any of our cautionary statements, those are available on our presentation on our webcast or on our website. Just please feel free to read those at your leisure with regards to non-GAAP measures, forward-looking statements, et cetera. Thank you, Alison. So just talk about production. Since we came on production from our project in July of 2020, I think we've posted some pretty strong results. I think the initial expectations that we set for the project were pretty close to what we delivered in that first quarter of production. You see, we were able to ramp that up quite nicely. The first quarter of 2023 at 2,767 barrels of oil equivalent per day was another record quarter for us. It was up 2% from the previous quarter and up 11% from Q1 of last year. Last week, we did announce that in April, we did have lower sales volumes, and that was partly due to our offtaker, Bahiagás, requesting less gas in the month of April. And it was also partially due to our partner at our core project actually nominating for more gas during the month of April. Bahiagás is back to requesting both firm and flexible volumes, back to the same level they've been requesting previously. Our partner continues to nominate at higher levels. We did guide that we would expect May to be somewhat similar to April when we announced that. You know, in previous calls, we had guided that we could experience some volatility just related to the timing of our production from the Caburé unit. Our strategy has always been to add an additional natural gas production platform, and we're looking at doing that with our 2023 capital program that we'll talk about later in the slide, mainly with our Murucututu project. This slide we show on all of our earnings calls just related to how our gas sales agreement works. We've updated this based on recent futures pricing, based on the benchmark prices that are within our contract. Just a reminder, our gas price gets reset twice a year, once on February 1st and again on August 1st, and it's based on these three international benchmark prices that you see here in the gray dashed line. We've got U.K. NBP gas prices, Brent oil equivalent prices, and then U.S. Henry Hub natural gas prices that you see here. To the left of this red dashed line the vertical line that you see here, those are all the historical prices that go into our formula. Moving forward, to the right of that line, those are the futures prices as of May 9th that we've reflected here. The output of that is just a projection of what, based on our formula within our contract, what will our gas price look like moving forward based on that. That's the black line. As a reminder, we do have a floor, which is the red solid line, and a ceiling, which is the green solid line, embedded within our contract. What you see here is that the forecast is to be at the ceiling within the contract out through to 2027, basically. That's almost equivalent to what we've included in our reserve NPVs when we published those a couple months ago. I think the important thing to note, you know, we've talked about this a lot, but it really highlights the fact that we've got a lot less volatility in our realized gas pricing or our realized commodity pricing than all of our peers. You can see a lot of noise and a lot of volatility, especially in the last six months. We're quite fortunate, I think to have much more of a heady kind of feeling contract that underpins our revenues. Just moving now onto our Q1 results. starting with our operating netback, which is this chart here. The green bar shows our operating netback, which is our profitability. We express it in barrels of oil equivalent. starting with our realized gas price, Corey just touched on our February 1st realized price. Corey just touched on our gas price reset on February 1st. Our average realized price for our natural gas increased in the quarter to over $12 per Mcf. That was a function of that February 1st price reset. We have some additional sales tax credits, which reduces our sales tax on our gas effective January 1st. Overall, we saw an increase in our gas sales price, and therefore, despite the declining Brent pricing on our condensate sales, we saw close to a $5 increase in our realized price per barrel of oil equivalent. From that, we deduct off royalties, which is the orange bar, and then operating expenses, which is the gray bar. Operating expenses were relatively consistent to last quarter. Our royalties on natural gas are a function of Henry Hub, our royalties actually decreased quite a bit in the quarter. We had a record operating netback in the period of just under $67. When we look at that as a percentage of the realized price, our net back margin, which is that line at the top, was another record in the quarter at 91%, which is pretty remarkable, up 3% from last quarter. When we compare that to other peers that have released so far. You know, we show this chart all the time, and it compares to other oil and gas companies operating in Brazil and other Latin American countries, as well as in Canada. Again, Alvopetro is well above on the profitability perspective here. We're at 91%, which is over 40% higher than other peers, and it just shows the strong profitability of our operations. When you combine that with our low tax rate, we generate very significant fund flow from operations, which we'll go through next here. Again, another record for Alvopetro, just under $15 million of fund flow in the period, which was up $1.8 million from last quarter, again, mainly due to that higher operating netback that we just went through, and then also lower G&A, partially offset by higher current tax in the period. $15 million, which is very remarkable for us. Similarly, net income also up quite a bit, over $12 million for the quarter in net income. That higher fund flow contributed to that. Also last quarter, we did have that impairment expense. This quarter we didn't have an impairment charge, that was an improvement. Then, partially offset by some higher taxes, both current and deferred tax, with our higher income overall. From a balance sheet perspective, I think you are all aware that we paid off our credit facility last September, so we no longer have that debt outstanding. We've been very successfully building our working capital balance, which is the green bar here. We're up to just under $21 million as of March 31st. We're well-positioned here to execute on our, on our capital program for the upcoming for the rest of the year here. All right. Thank you, Alison. This chart just shows our dividend history since we introduced the dividend in the third quarter of 2021. You can see we've now increased it three times. Most recently in the first quarter of this year, we increased it up to $0.14 per share. That now represents a yield of just under 10% at current share prices. Of note, since inception of the dividend, we've already returned $22 million to shareholders, or the equivalent of $0.62 per share, back to shareholders. Pretty proud of that. This just highlights our capital allocation model that we developed quite a few years ago. It shows, I think, a much more balanced approach, where we're trying to balance stakeholder returns with organic growth in our business. Our plan was always to reinvest roughly half of our cash flows in organic growth and return the other half to stakeholders. The chart on the left-hand side, the lines just show each quarter's fund flow from operations. Alison just walked you through Q1 being close to $15 million and a new record for us. All the different bars show how our cash was utilized during that period. You can see earlier on when we first came on production, most of the focus was on repaying our outstanding credit facility that Alison highlighted. We did that in a very accelerated manner. That's the gray cross hatching that you see here. Very little money spent on kinda reinvestment in our business in the early days. We introduced the dividend in the third quarter of 2021, which is the solid green. More recently, you can see we've been investing in our business, and I think you're gonna start to see the results of that as we progress through this year. If we look at it in total, since July of 2020 through to the end of the first quarter, you can see again, the allocation. Just over a third to capital expenditures, a little under half to returns to the various stakeholders that you see here, and then a big wedge related to growing that cash and working capital position that Alison highlighted. You can see the gap between the cash flow and the cash outlays in the current quarter that contributed to that big increase, bringing our working capital and cash position up to close to $21 million. One of the things of note here is that the cumulative funds flow from operations, since we came on production here is $97 million. In the month of April, we would have surpassed $100 million of funds flow. Moving on to our organic growth plan. You know, our targets here or our vision's been pretty consistent. We've had a near-term goal of 18 million cubic feet a day, which is coincident with the capacity of our gas processing facility and a longer-term vision to basically double that. We did complete the expansion of our UPGN or our gas plant in the middle part of last year up to that 18 million cubic feet a day plus level. We've also been working with our partner on expanding unit capacity at Caburé. I think we've got some plans to drill some development wells starting later this year. Most of the growth is planned to come from our Murucututu asset. It sits immediately to the north of Caburé. Adrian's gonna walk you through that. We've got all the pieces in place now to execute a multi-well, multi-year development program here that's focused on converting reserves and resource to production and cash flows. I think we're gonna have some exciting news from that as the months progress through this year. In addition, we've started our work at Bom Lugar, where we've got up to two wells planned this year. One of them is included in our 2P undeveloped reserves. It also has deeper exploration potential in two formations there. Adrian will show we spud that well in April, right at the end of April. Lastly, on the exploration side of things, we did encounter some significant hydrocarbon columns in both of the exploration prospects that we drilled last year, and we are still in the process of evaluating opportunities to enhance permeability from those zones. You know, to repair what we think could be near wellbore damage caused by either the drilling fluids or the completion fluids that we use. Work will progress through this year and based on those results, we can define a forward plan for those blocks. Thanks. Thanks, Corey. As you recall, we're drilling a step-out well at Bom Lugar. That's offsetting an existing production well. The main target here is our oil reserves in the Caruaçu and the Gomo formations, we'll be extending it down to a deeper exploration target in the Água Grande. As we've noted, you know, we've initiated drilling here. We started at the end of April. We're currently at 1,150 meters. We just finished the cementing job last night, we're looking forward to drilling out and finishing this well in the next few weeks here. This is just a map to show you guys how we've been evolving our Deep Basin gas play and how it fits in with the rest of our infrastructure. Initially, when we started, we drilled the 197-1 and the 183-1 well in the north. Then we discovered Caburé, and we focused on that to build the infrastructure, signed our long-term gas sales agreement, built our UPGN, and initiated production and cash flow from the Caburé asset. Now we're in a position where we can realize the value of the tight gas that we discovered a long time ago. In 2022, we completed a 9 km pipeline to the 183-1 location. This is where we built the production facility to manage production from the Murucututu asset. We built another pipeline to 197-1. This is a shot of the production facility at 183-1. This is where we're going to manage all the production from these tight gas wells as we drill and complete and put them online pretty soon. Right now, we're stimulating the 197-1 wellbore. This is just a shot of what the location looks like today. Currently, we're in the process of just pressure testing the surface equipment you see here, and then we'll initiate the diagnostic fracture test and then conduct the main stage on stage four today. We've already completed the first three stages, so this is the last or the top stage there on the logs on the left. Once that's done, we'll initiate the flowback period of the well and then just put it on production to our production facility you saw on the previous slide, and then our UPGN starts selling gas. We're looking forward to the multi-year development plan for this well. We've got a lot of prospects and opportunity here. In 2023, we're gonna start the production from 197-1 and then initiate drilling at the 183-D1 location there, 183-A2. We've got up to two wells in 2023 to drill and complete, put those immediately on production. The overall objective is to migrate this resource into production and reserves with this pad-based drilling idea and de-risk the production potential of up to 20 million standard cubic feet a day. All right. Thank you, Adrian. Just to wrap up, again, I continue to believe that Alvopetro offers an extremely attractive investment proposition no matter what your investing focus is. You know, I think as demonstrated from our Q1 results, another record for us, we're delivering some pretty solid results. We've got an attractive gas sales agreement, a clean balance sheet, and we're really well-positioned to execute this organically funded capital program. For value investors, we're trading at roughly 1P NPV, about half of our 2P NPV. Our dividend yield is almost 10%, again, paying quarterly dividends in USD. For growth investors, again, a very exciting organically funded capital program. If you look at the potential value that we can create from that capital program, especially when you consider Value, I think it's extremely exciting. With that, Alison, if we could start the question and answer period. Just a reminder, if you wanna submit a question, just click on the Q&A button within the ribbon in Zoom to log your question. Yes, we have quite a few questions in, a lot of them are around the reduction in the production in April. I'll combine some of those together. The first ones are around our partner at Caburé. Can you give more details regarding your partner nominating for higher levels? Does your partner have priority over Alvopetro regarding nominations, or is it just the case that both producers are nominating higher levels, but demand is not there? Yes. To just to recap, our partner, when they produce gas, they sell it through a thermal power project. When our gas gets produced and sold, we ship it down the transfer pipeline that Adrian highlighted, process it through our gas plant, and sell it to Bahiagás. The way our contract works is that both parties are entitled to their share of production. Any production that's not being nominated for by the other party, it can be made available to the other party. No, I wouldn't say there's priority, but what's happened in the past is that there wasn't any nominations or dispatch from the thermal power projects that our partner has, such that we had availability of all that production. It really is quite a unique thing. And although the, you know, our production decreased, it's, you know, we've talked about this before, but the way our agreement works is, you know, we instead of sharing every molecule based on our working interest every day, you know, we have basically piggy banks that contain our 2P reserves. When we produce down our pipeline, we're taking reserves out of our piggy bank, and then the same thing happens for our partner when they're producing. It just really changes the rate at which we're producing our 2P reserves, and as a result, doesn't really have a significant... There's some small PV impact, but it's not really a significant impact on our net present values. Do you have a best guess for your share of Caburé production for the remainder of the year? Well, again, that's gonna be a function of what happens with our partner. Our strategy all along has been to make sure that we build a second production platform for natural gas that complements Caburé so that, you know, although there could be volatility within our Caburé production, at the end of the day, you know, our plan is to try to produce consistently at our plant capacity, whether it's coming from Murucututu or Caburé or various combinations. That from an external shareholder perspective, it looks, you know, as consistent as we had before. How low can our sales volumes go if our partner decides to take up all of its entitlement? What percentage of sales... Oh, sorry, that's part one. Yeah, I think that's pretty consistent with the earlier question. You know, roughly, you know, the field capacity's been, you know, in and around the 600, 650,000 cubic meter a day level. We're entitled to basically half that, so. Can you comment at all on the% of sales reduction that was due to less demand by Bahiagás? You know, it was kind of overlapping. I would characterize the Bahiagás portion as, you know, I think it really absent, it was probably seven to 10 days within that period that we were impacted just because of Bahiagás. Then we had kind of the coincident things happening at the same time. The main issue or the main message on Bahiagás is they're basically back to, you know, asking for as much gas as they can take from us. I think it was a unique thing that happened in the month of April, they just have to manage their book of business and all their firm commitments. If there's any slight changes in demand, they were just trying to be very fair to all the, all the various producers and make sure they were taking all their firm volumes, which had an impact just on our flexible component of our deliveries. Was there any specific reason or specific cause that the lower demand from Bahiagás is attributable to that you are aware of? Yeah. Bahiagás indicated a short-term reduction in demand, but I think it was also just a function of how they had committed for the month for firm capacity. They have the ability to adjust that. We also have the ability to adjust as we put more production on, the ability to adjust our firm volume. If we wanted to increase our firm component, you know, that's something we could look at doing in the future. If, again, it looks like we're back to the same as we've always been with Bahiagás. Are there any efforts to add a new offtake partner? If so, would this be in Bahia without Bahiagás or in a new city or a new state? Yeah, we, you know, we have a benefit that our infrastructure's tied directly into Bahiagás. It does create a net realized price advantage for Alvopetro. You know, we're very happy with our relationship. But you know, there is movement afoot where there's more and more Contracts being signed directly with end users. You know, our preference would be to, you know, continue our relationship with Bahiagás, but, you know, there have been, you know, a lot of requests from other producers for access directly to our gas. It, it's certainly a possibility. Perfect. I think that answers those questions on that particular issue. We did have a question on why the royalty rates declined so sharply from about 3% of sales in Q1 compared to 7% previously. I'll answer that. You know, the bulk of our sales volumes are from natural gas and natural gas royalties in Brazil are based on a reference price, which is linked to Henry Hub, and it's more the value of the raw, like, unprocessed gas. We saw a decline in Henry Hub and an increase in our gas price under our contract. Therefore, as a percentage of sales, our royalties came down. You know, going forward, it's more a function of what you expect Henry Hub to be compared to what our natural gas price is going to be and that percentage. Yeah, as of right now, you know, the royalty rate in Q1 is likely to persist in the short term anyway with current Henry Hub prices. We did have a question on Bom Lugar and where Bom Lugar is located. I don't think we went through that in detail today, but there is in our corporate presentation. Bom Lugar is north of our gas assets. In our corporate presentation on, I think, slide six, there is, it's more evident on the map. I don't know if you wanna comment on that at all, Corey? No. That's right. It's within the same basin just to the north of this. Or north of the map sheet that you saw for Caburé and Murucututu. Okay, the next question is on 197-1. What level of production would you expect once the well is on stream? Yeah, I can comment on that. Our 2P estimate for the 187-1 is roughly 180 boe per day. That's something that as we finish our final stage of completion and put this thing on flowback, we'll refine and update. Year one average. Yeah, sorry, the year one average. Right. Okay. Any details on the share buyback will start and the quantum? Well, that's something our board will continue to evaluate in the context of the overall stakeholder return portion of the pie, let's say, which is a balance between dividends and share buybacks. You know, we've indicated before, you know, we don't wanna get into discussing what our, you know, trading strategies or what the orders with our broker are. We'll continue to evaluate that. So it's hard to give guidance on that. And just to confirm, there's been no buybacks to date on that. A little bit more on the drilling. Are you having discussions with the drilling mud supplier and the drilling companies about the issues you've seen on recent wells, including 183-B1 and 182-C? Did you have any similar problems on wells preceding these three wells? Are you going to delay further development until you can overcome this problem? I think that's for Adrian. Thank you. We're certainly working through these problems. No, we're not, we're not delaying the drilling of our next projects. Of course, we're re-reviewing everything with our service providers, our mud providers. The products and the technology that we're using is... it should be first class for the basin and globally for prevention of fluid invasion and damage to the reservoir. It's just when the results aren't as the expectations, we've got to investigate this. That's not something we've concluded. But that's something we're working in parallel, but we're not gonna delay the other Murucututu development wells. They are in different formations. The Biguaçu Sand and the Candeias is different than the formations we saw problems with in 183- B and 182-C1. Yeah, hopefully we evolve the understanding of what happened in those two wells. It's not something we've seen in our other development wells in Caburé or in the initial discovery wells for Murucututu. Will you do a new reserve report after you drill the two additional development wells at Murucututu this year? Yeah. I think by the time we drill those and we get a little bit of production history, we're probably fairly close to or coincident with our normal reserve reporting timing. We can evaluate it depending on that timing. Okay. sorry, we do have a couple more questions back to Bahiagás. What is their actual firm volume commitment to Bahiagás? Yeah. Right now, we have 300,000 cubic meters a day, which is between 11 and 12 million cubic feet a day of firm, and the rest of it's flexible. Would other prospective off-takers accept a similar gas pricing formula as your current contract with Bahiagás? Do you have thoughts on that? You know, most of the contracts are% of rent base, but from what we're seeing in the market, I think it's relatively consistent. This next one is probably for Adrian as well. Do you have an estimated cost differential between a fracture stimulated vertically and a horizontal multi-stage fracked well in this region? Well, one thing to point out there on that is if we look at the logs and the 4 stages that we're completing at our current well, to develop that with the horizontal multi-stage isn't really applicable. The way that the Gomo sands are overlaid on each other and then separated by shales, we really need to go in there with the vertical multi-stage fracs. As we drill and log them, we've got to place those fracs specifically so it doesn't lend itself to a horizontal multi-stage development program at this point. You know, as we drill more wells, we might learn a bit more. At this point, it's not really on the books as a true comparator. Okay. The last, we have a couple more questions that are around the balance sheet and the strength of the balance sheet and the large amount of cash we have right now. You know, if this continues through the year, even if there is a share buyback, is there any M&A potential or M&A opportunities? Would you look to ramp up CapEx? Would it make sense to purchase the plant from Enerflex? Any acquisitions, that sort of thing. Yeah. Well, it's always impossible to comment on business development things. If there's an inorganic way that we can create shareholder value, we would certainly evaluate that. Our primary focus is on organic growth from the assets that we reviewed today. You know, we'll continue to evaluate that going forward. Okay. I think that is it for questions. All right. Well, thank you. If there's any follow-up questions from anyone, feel free to reach out to us directly. We look forward to updating you in three months' time. Thanks, everyone.