I might need to start again. Sorry. Good morning, and thank you for joining us for our Q4 Earnings Results Webcast. I'm Corey Ruttan, President and CEO, and I'm joined by Alison Howard, our Chief Financial Officer, and Adrian Audet, our Vice President, Asset Management. Good morning, everyone. Just a couple of administrative points. We are recording this webcast today, and a replay will be available later on today after this call on our website. All attendees are in listen-in only mode for the duration of the webcast. If you have a question, we will be doing a Q&A session at the end of the call. You can log your questions right away here using the Q&A portal through Zoom. Sorry. Excuse me. If you are calling in, please send your questions to socialmedia@alvopetro.com. Lastly, just encourage everyone to review the cautionary statements on our website. There's a corporate presentation that just goes through a lot of details on non-GAAP measures, et cetera. We won't go through those in detail here, but review them at your leisure when you get a chance. Thank you, Alison. Really, if you look at our results from 2022, it really was a banner year for Alvopetro. You know, since starting production in July 2020, we've really been delivering some strong production results. 2022 was a new record year for us at 2,557 barrels of oil equivalent per day of production. That was up 8%, over the prior year. If you look at our Q4 results, we produced 2,724 barrels of oil equivalent per day, which was up 3%, over the third quarter and up 12%, from Q4 last year. You can see again in January and February we had successively strong months there. February was another record month for us at 2,866 barrels of oil equivalent per day. I think that should set the stage for what should be another strong quarter for us in the first quarter of this year. This is a chart we like to show on our these quarterly calls. It just kind of walks through how our Gas Sales Agreement works. Just as a reminder, our price gets reset semi-annually on February 1st and August 1st of each year. The three different lines that you see here are three benchmark prices that are used in our pricing formula. The lower one is U.S. Henry Hub. This middle one is Brent oil equivalent prices, and the upper one is UK NBP gas prices. Left of this red dashed line is the historical pricing, and on the right side is the forecast that were used in our reserve report, which are based on our independent reserve evaluator, GLJ's price forecast as of the end of the year. In addition, we have a floor and a ceiling. They're the red and the green lines that you see here. Those do get escalated based on U.S. inflation. The assumptions that were used in our reserves were 3%, inflation for this year and 2%, thereafter. Arguably maybe a bit on the conservative side. The net effect is you blend these over a period of time and you spit out our gas sales price, which is the dark black line that you see here. Moving forward, you can see it's really limited by the ceiling in our contract. What we've also done is add this black dash line, and what that represents is if we were to redo these price forecasts based on the forward strip pricing that was in effect at the end of the day on yesterday or the day before, that's the impact that you would see on our realized price. A very small impact relative to what our peers would have experienced. You know, I think if you contrast it with a U.S. natural gas producer since Christmas, a U.S. producer, they've seen their price go down by over two-thirds. This really highlights the kinda hedgy nature of our Gas Sales Agreement and the much lower volatility that we see. In the last month, we've updated our reserves and our contingent prospective resource reports associated with our Murucututu asset and our other assets, using GLJ as our reserve evaluators. I'll just go through some of the highlights of that report. From a valuation perspective, our before tax and after tax valuation increased by 17% and 15% respectively. Our 2P production ratio was 132%, you know, meaning that in 2022 we produced just over 900,000 BOE, and we replaced more than this on a 2P basis, mainly associated with additional undeveloped locations at our Murucututu asset here. The current reserve life index for our assets are 9.7 years, Alvopetro continues to focus on de-risking and un-unlocking the potential of the Murucututu contingent and prospective resource reports. You know, the valuations of these are highlighted and reported, so we look forward to those assets. Yeah. I think the other point to make is we've just updated the chart on the bottom here. You can see based on our current share price, the black dash line is our current enterprise value. What you see there is that we're trading at just below our 1P NPV is basically roughly half of our 2P value. You know, we'll talk about this at the conclusion. You know, from a value perspective, this represents the value proposition of investing in Alvopetro today. When you look at, you know, the potential additional value that we can realize from both our, you know, our 2P reserves, our possible reserves, as well as the contingent and prospective resource that Adrian talked about there. I think there's still a lot of opportunity. Just following on Corey's discussion on the strength of our gas sales rate under our Gas Sales Agreement, this chart here is our operating netback, which is shown in the height of those green bars, which is our profitability per barrel of oil equivalent. Starting at the top with our realized price per BOE, Q4, we saw a very slight decrease from Q3. That was just due to the reduction in Brent and the impacts on condensate pricing. Our gas sales price under our Gas Sales Agreement was exactly the same as Q3 at $11.18 per Mcf. Despite that reduction, you know, we did see a $0.25 per BOE increase in our operating netback from Q3. We're over $60 in the quarter, that just shows kind of the strength of this fiscal regime in Brazil and how profitable this production is. Which is shown again in that line on the top. Looking at our operating netback as a percentage of our realized sales price in Q4, that's 88%, which is pretty remarkable, we would say. Overall in 2022, it's 87%, and our overall netback in 2022 on a year-to-date basis is over $59. Just we would say that's best in class, and we like to show kind of how that stacks up to other companies operating in Latin America and in North America, or in Canada, sorry. Yeah, our operating netback is 88%, or our net back margin is 88%, in Q4 compared to an average, we show 8 other producers that have published their Q4 results here. The average there is 65%, you know, over 35% higher. You know, this is our net operating income, so before tax. If we looked at it after tax, you know, with the strength of our, you know, we have a very low tax rate in Brazil with our tax incentives that we are eligible for. You know, again, this just highlights how great it is to be operating in Brazil from a fiscal regime. Moving on. This is our funds flow. Just that builds off of that chart and how profitable our production is. Our funds flow for 2022 was a record year for Alvopetro at just under $50 million, which is, you know, pretty impressive. Overall, our net back, which increased $27 million from the prior year, and everything else was relatively flat. We ended the year at $50 million funds flow. If you compare that to, you know, we had revenues of just under $64 million to have funds flow, you know, after G&A, after tax of $50 million is pretty impressive. That's 79%, of our revenues. That was pretty remarkable. Q4 funds flow was pretty much consistent with Q3. We did see a slight increase in our sales volumes, and that was mostly offset by some increased G&A and current tax just with finalization of year-end. Similar to funds flow net income, you know, which also incorporates various non-cash items. With that increase in funds flow from operations, again, we had record net income at Alvopetro in 2022. You know, the main impacts there were the net operating income was, you know, significantly higher than 2021 with the higher sales volumes and realized prices. We did have some foreign exchange gains. You know, we talked about that in prior period, the gains were higher than in 2021, mostly accounting foreign exchange gains and losses on intercompany amounts, so all non-cash related. The big impact going the other way was we did recognize an impairment in Q4 of $6.3 million. Again, $31.7 million of net income on that revenue basis is pretty impressive. For the quarter, we did see a bit of a decrease from Q3. Again, the main driver for that was that impairment charge that we recognized on one particular well in our E&E assets. So, yeah, with those strong funds flow, we ended the year with working capital of $14.7 million. Recall that our credit facility is fully repaid as of Q3, and now we have cash and working capital of $14.7 million. We've seen a steady increase in that, you know, since coming on production and now we're debt free, which is great. All right. Thank you. Happy to announce that we've now increased our dividend for a third time since introduction of this and since, frankly, the first increase that we did in Q1 of last year. The yield now represents over 11%. Since inception of the dividend, you can see we've already returned or will have already returned $0.62 US to shareholders. That totals $22 million. In addition, we have announced an intention to tweak our normal course issuer bid that we announced earlier to an automatic share purchase plan that allows us to purchase shares also in routine blackout periods through instructions to our broker. Next, just wanna talk about our balanced capital allocation model where we're, you know... This is something that we introduced years ago, long before, frankly, even our Caburé project came on production. The model was to roughly reinvest half of our cash flows in the business and in organic growth and return the other half to stakeholders. This is kind of how this all looks. The chart on the left-hand side here, the lines and the dots just plot our funds flow from operations over time. You can see we had, you know, two successive, you know, our best quarters here to finish out 2022. They both had, sorry. Our average for 2022 as well as our average for Q4 both represent over 100% increases over the prior year comparative periods, as Alison highlighted. The bars that you see below this, it just show where we put the capital basically. If you look at the first year of coming on production, the huge majority of the cash outflows went to repaying our credit facility on an accelerated basis. That's the green cross hash bars that you see here. In the third quarter of 2021, we introduced the dividend, which is in the dark green. We also did a share restructuring in that quarter, which is the lighter solid green color, and we repurchased a bunch of our shares. Just, you know, in 2022 is the first time where we really started to see the reinvestment in our business in the yellow bars that you see down here. That's how it's looked quarter-over-quarter. In total since coming on production, in July through to the end of the year, you can see how this looks. Almost exactly half has gone to stakeholders, a little over a third to capital expenditures, 15%, has gone to building that cash and working capital position that Alison showed you earlier, up to almost $15 million as of the end of the year. That certainly gives us a lot of flexibility as we move forward. Just focusing in on our organic growth plan, you know, we've had a near-term goal of achieving 18 million cubic feet equivalent per day. We're actually closing in on that now, we've got a longer-term vision to basically double that. The growth's planned to come from a number of areas. You can see, you know, first our core operating area with Caburé and our distributed assets. We did complete the gas plant expansion in the middle part of last year, up to 18 million cubic feet a day. This year, along with our partner, we're looking at drilling a couple of additional development wells and expanding the, the unit facilities. Probably the most significant part is our Murucututu asset. Adrian showed the addition of a couple of additional locations into our reserves. GLJ has assigned a combination of 2P reserves, contingent and prospective resource. You know, we're now in a position that we can start a multi-year development plan and really look to migrate that into production cash flow and, and reserves. I'll get Adrian in a moment to walk you through in a little bit more detail what that plan looks like. On our Bom Lugar mature oil field, we do have up to 2 development locations on this field targeting the Caruaçu formation as well as some potential in some deeper formations here. Lastly, on the exploration side, we did drill 2 exploration prospects last year. The good news is the traps worked. We encountered big hydrocarbon columns. The challenge is, you know, when we tested them, the permeability certainly seems lower than what we would have expected based on the porosity of logs. We're gonna do a bunch of engineering work this year to evaluate all alternatives to enhance that. Probably low from a capital spending perspective, but high from a sweat equity perspective to really try to unlock those discoveries. I'm just gonna walk you through the genesis of Murucututu and Caburé, and how we got to where we are today. You know, the Google Earth map here shows the two initial wells, 183-1 and 197-1, that we entered into this. We drilled to initially discover the gas project here, and we followed that up with the discovery of our Caruaçu conventional production at Caburé, at which period of time we developed the infrastructure. We signed our long-term Gas Sales Agreement that Corey went over earlier, and this really positioned ourselves to capture any additional natural gas potential. By the end of 2021, you know, we had stable production from Caburé here to our UPGN at the Bahiagás City Gate, and we were ready to move our exploitation focus to the tighter gas potential in 183 and 197-1 here. In 2022, we continued to focus on that exploitation of this tight gas project. We built that additional pipeline to the north from the unit, from Caburé to 183-1. We built an additional flow line to 197-1, and we built a facility at 183-1 to take our production. Have three-phase separation so we can manage any liquids production, state production, and leverage the existing infrastructure and position ourselves for the first phase of field development here at Murucututu. Today we're currently, you know, we've got ongoing work at 197 to do, our first multi-stage stimulation here at that wellbore we drilled a long time ago. We're really excited about this project. You know, this is a huge milestone for Alvopetro to be able to do this multi-stage stimulation tied in, you know, the flow lines right at the location right now. We're ready to finish this completion, and then our target is to have this thing online, by the end of April. In the future, you know, we've got... As we noted before, we've got this contingent resource, this contingent, or prospective resource and reserves associated with Murucututu. In 2023, we're gonna drill up to two development wells, 183 A2 and this 183 D1 area, with the potential to continue to drill in 2024, and de-risk the production potential of 20 million standard cubic feet a day of this asset alone. All right. Thank you. In summary, I continue to think Alvopetro offers an extremely attractive investment proposition, no matter what your investing focus is. I think hopefully you're convinced we've been delivering results certainly ahead of the expectations that we set before this project came on. Again, a new record production in February this year. We had record cash flow in 2022 and very strong quarters in both Q3 and Q4 to close out the year. I think that puts us on track for another strong quarter in Q1 this year. Obviously, we've got some attractive gas prices. As Alison noted, we've got best-in-class operating margins. We've got a clean balance sheet and extremely strong funds flow from operations generation capacity to help underpin that balanced stakeholder return and organic reinvestment model that we have. For value investors, just to recap, we're currently trading at under our 1P NPV, about half of our 2P NPVs, and just over 3 times annualized funds flow from operations. For yield investors, we offer over 11%, dividend yield right now with quarterly dividends paid in USD. For growth investors, as I highlighted earlier, I think we certainly have a lot of leverage relative to our current enterprise value with our organically funded capital program that we're in the middle of right now. With that, I think we'll turn it over to the question and answer period. Okay, perfect. We have a couple of questions on the impairment charge that was booked in Q4. I'll start with that. I touched on that briefly. We drilled three exploration wells in the year. The first one was 182 C one. We drilled and tested that well. We ultimately wrote off the cost for that well only. We made the decision to do that. We made the decision to abandon that well. It was drilled very close to the main bounding fault, and we missed the secondary target. Ultimately we proceeded with drilling a second prospect, a second well into that prospect, the 182 C two well. We've just written off the cost of that one, the C one well in the period. Going forward, Corey touched on this. We do have some, you know, engineering work that we're doing on 183B and 182 C2 going forward. We will have some additional work there. Probably not very extensive in terms of dollars, but as Corey mentioned, in terms of, you know, work from the team on sweat equity. Hopefully that answers that question. The next question was, the 197-1 well that is, you said you've started stimulation. When do we expect that to be on production? Yeah. Like I noted before, the objective is to have this thing online, producing to our UPGN by the end of April. Equipment's on location, and we're imminent to start the actual stimulation, so. Perfect. Staying on Murucututu, you're drilling these development wells. How is that different than the existing wells? You mentioned the concept of fit for purpose well. What does that entail exactly? Yeah. When we drilled those initial exploration wells, you know, they were cased with seven-inch casing, and we went through a testing program and tested a number of our pole zones for hydrocarbon potential. In the fit for purpose idea, we wouldn't do any of that because that makes it very difficult to do these stimulations. We would also case them in five and a half inch casing so that we can stimulate down casing and that provides a lot more flexibility to these completions that we're planning. The other addition that makes it a fit for purpose is we're incorporating a sliding sleeve technology to make the multi-stage vertical stimulations a lot more effective and realizable, so. Perfect. If the year-end 2022 estimates of contingent and prospective resources are accurate, how much of these would potentially shift to 2P reserves if the 2023 capital expenditure plans for Murucututu and Bom Lugar were proven successful? Yeah. I think it's hard to predict exactly how GLJ will go about that. I think you can see what happened this year is just based on our imminent development plans for the asset. We were able to convert two of the locations into from contingent into into reserves. I think especially as we drill the well to the north of the 1831 pad, with success there, I think it would in all likelihood open the door to migrating another big chunk or maybe all of the contingent into prospective. You know, I think at least some of the prospective area would migrate into contingent, and it would be kind of an evolution over a couple years or a few years of time as we develop the asset to the north. When do you see the next material increase from the exploration wells or from the development locations? I think To focus on the Bom Lugar property first, the drilling is expected to commence sometime in April here. You know, we would have that well drilled within, you know, 40 to within the next two months following that. There are some small facility modifications that we do on location, but we'd be able to bring that well on production reasonably quickly thereafter. Sometime in, hopefully Q3, that production would be added. From a gas perspective, as Adrian noted, the 197-1 well would come on here by the end of April. The, you know, the result, the wells, the other two wells that we would drill, that production would be added later this year. Keeping in mind that, you know, from a gas perspective, that all gets kind of managed together with Caburé and through the UPGN. You know, in the near term, we've probably got, you know, we've got 18 million a day of capacity at the plant. It's possible that that could be higher, but, you know, as we get information from the Murucututu project, then we can make decisions on, you know, do we wanna make other modifications to the plant to accommodate even higher production levels. You know, that's something we're probably talking about later this year. Speaking of production, we do have a couple of questions on that. What incremental daily production do you expect from 197-1? Yeah, I can handle that. Well, the estimated production from that specific well for the first year is 180 BOE per day. As Corey noted, we're facility limited at this point to 18 million standard cubic feet a day at the UPGN. Depending on how the results turn out, we'll be discussing making facility modifications to adjust the plateau. Okay. Do you have an exit target for production in 2023? Well, no more than what we've kind of put in our, in our plan. You know, I think, you know, we've got this near-term objective of 18 million cubic feet equivalent per day. I think we're closing in on that. Yeah, some of, you know, the facility side of things, you know, to get to our 35 million cubic feet a day goal, you can see us how the Murucututu asset will layer in based on that, chart that Adrian showed earlier. That, that gives you a sense. In parallel, we would be doing the facility modifications to accommodate higher production levels. No, we don't have a public exit target, but that's kinda how we would expect to see production grow over time here. Just shifting gears a little bit. There are reports about Brazil putting in an export tax on crude products. Are they putting in any roadblocks on the onshore industry that could impact Alvopetro? yeah, no, that was announced. It's a 4-month measure. I think there's a regulation or a legal. They're allowed to do that, if it lasts for basically more than that period of time, it needs to be voted on and converted into law. It remains to be seen whether that will be permanent or not. It doesn't impact us, obviously, because we're not exporting oil. No, we haven't seen any impediments. If anything, it's been, you know, you can see, based on the slides that Alison showed, we've got a pretty compelling fiscal regime here. Quite frankly, we just recently qualified for a tax incentive on our gas that helped increase our gas price further than what probably the market was expecting when it reset on February first. We do have a couple of questions on the automatic share purchase plan that we announced yesterday. I think I'll just try to combine these a little bit. Do we expect that there will be modest or substantial NCIB purchases based on the current share price and market conditions? You know, there's questions around the fact that, you know, Alvopetro is fairly thinly traded, and the impact that this could have and how we will monitor that. Yeah. A couple of things. I think within the regulations, there's, you know, guidelines on not having undue influence in the market, so we'll make sure that we're trying to use best practices to abide by that. You know, one thing that we probably won't be doing is, you know, selectively talking to people about what our trading parameters are or all those things, because I think that's just, you know, not appropriate. From a budget perspective to touch maybe based on the first question, you know, we're gonna manage this in the context of our stakeholder return model, where 50%, of the cash flows roughly are going to stakeholders. You know, really what the board will be doing is looking at the budget for NCIBs versus dividends or dividend increases, and we'll balance those things going forward. It's tough to predict exactly. I, you know, I'd like to preserve some flexibility around that as well, and it really is, it depends on what the market does as well. We do have a question on permitting and whether the new regime has made the permitting process easier in Brazil, or if you have any commentary on that? Yeah. You know, the permitting processes are run by for the most part for us by the local environmental regulator in the state of Bahia, which is INEMA. You know, other than that they're busy, they've continued to be quite supportive and obviously they're keen to see more activity and more attractively priced gas being produced into the state of Bahia. Overall, between that regulator and the ANP, you know, we've had very positive experiences and we haven't seen a change there. Okay. We do have a couple of questions that have come through on our social media email that I'll just go through now. The first question, once we are past the August first gas price reset, with lower gas prices, NBP and Henry Hub, which are expected to be seen through multiple prices, will we not see a lower GSA price under our Gas Sales Agreement, and how are we preparing for that? We thankfully anticipated that that might be a question, so that's why on that graph that I showed right near the beginning of the presentation, we added a thick black dashed line to basically answer that question. That represents, if you assume the forward strip prices as of today are more reflective, then that would be the expectation. You still wouldn't see any sort of gas price reduction until basically the end of 2024. It's quite just barely under our ceiling. I think that's one of the things that makes Alvopetro so attractive. If there are lower expected revenues and investing in CapEx and dividends may be challenging, why would you increase your dividend now? Yeah. Well, I think a lot of people could ask why we didn't increase it more given the production levels that we have in Q1 and the gas price we have in Q1. You can look at it two different ways. You know, we're trying to be conservative with that. I think the new level that we've got is very sustainable, even if we had lower gas prices or lower production levels, quite frankly. Yeah, no, we think it's a pretty level. Like I said, we're much more, partly because of the kinda lumpy nature of our Gas Sales Agreement, but also partly because our operating margins are so much higher than any of our peers. You know, our sensitivity on, commodity price decreases are way less than what you would see with a, say, a Canadian heavy oil producer or a Canadian or, or US natural gas producer. Okay. Another question here was around total CapEx for 2022. How much was exploration versus maintenance capital for stable flat production? I can start that, and if Corey wants to comment, he can. We actually had total capital CapEx of just under $25 million in the year. About $18.5 million of that was for exploration projects as well as long lead purchases. Then we had spending at our Murucututu project of about $4 million, which was development in nature and not capital. We did have about $2 million in spending on Caburé that was for drilling an additional well and some facility expansion. For the most part, it's kind of development and expansion capital, not really something that we have to do to maintain the current production. Hopefully, that makes sense. I think Alvopetro is a little bit different than the normal company that you think about maintenance capital. Obviously, we still need to be focused on replacing reserves and that. Because of our Caburé project being fully developed in advance, like there's all the production facilities are there. There's eight wells. It's quite well delineated. Just 'cause the nature of a gas project like that, you kind of pre-invest all the capital. You build a facility to a production plateau that frankly, there's excess production capacity above that, and then you just produce to the plateau, basically. It's different than maybe another company where they're drilling wells and then having immediate production declines and constantly having to kind of be mindful of replacing that. Perfect. The other question was just on our PDP, proved developed producing asset value, NPV10. That is included in our AIF, which was just released yesterday. It can be found on our website or on SEDAR. The NPV10 of the proved developed producing assets is $147 million. If you have any other questions specifically on that, feel free to reach out to me. Just gonna double-check quickly here to see if we have any other questions. I do not think we do. I think that is it. Unless there's any final comments Corey or Adrian wanted to make. No. I just wanna thank everyone again for attending today. I also wanna thank you for your support and look forward to updating you on this call into the next call in May. If you've got any questions in the interim, as always, feel free to call us and we look forward to your calls. Thank you.