Q3 results webcast. I'm Corey Ruttan, President and CEO. I'm joined by Alison Howard, our CFO, and Adrian Audet, our VP, Asset Management. Turn it over. Good morning, everyone. Thanks for joining. Just before we begin, a couple of administrative points. We will be recording today's webcast, and there will be a replay on our website, shortly after the call today. In addition, all participants are in listen-only mode, but we will have a Q&A session, at the end of the presentation, and you can start entering your questions now through the Zoom Q&A, button there, and we will get to those at the end of the presentation. If you are dialing in, you can send any questions to socialmedia@alvopetro.com. Lastly, we will be going through some Non-GAAP measures, and some forward-looking statements will be made in this presentation today. So just please, when you get a chance, read through our cautionary statements and other disclosure. Those are at the end of our corporate presentation, which is on our website. With that, I'll turn it over to Corey. All right, thank you, Alison. So our production in the third quarter was just shy of 1,700 barrels of oil equivalent per day. That was previously announced. It was impacted by the temporary demand decrease that we saw in the state of Bahia in the month of September. You can see in October that's reversed. We posted production of 1,839 barrels of oil equivalent per day in October, and that's continued to be strong in November. Our strategy, we'll focus on this later, is to really focus on adding 100% working interest natural gas production from our near-term capital projects so that we can maximize the throughput through our gas plant and ultimately, as we move towards our near term goal of 3,000 barrels of oil equivalent per day. Just an update on our gas sales agreement, based on some more recent futures pricing in the market. Just a reminder to everyone, our natural gas sales contract gets, the price gets reset twice a year, so every February 1st and August 1st. The price is calculated based on three international benchmark prices. So left of this red dotted line is the historical pricing and to the right is the future projected period. The three different benchmark prices are in the gray dashed lines that you see here, being U.S. Henry Hub natural gas prices, Brent oil equivalent prices, and U.K. NBP prices. Those get blended together, and it calculates our natural gas price, which is the dark black line, which is also subject to a floor and a ceiling within our contract. So that's the red and the green lines, respectively. You can see they're slowly ticking up here because they're indexed to U.S. inflation. So, what you see here is based on the futures pricing as of November 7th. For those three commodities, we would expect to stay at the ceiling within our contract for the foreseeable future here. So moving on to results from Q3, and specifically, our operating netback, which, just a reminder, is our net operating income expressed on a per barrel of oil equivalent basis. So to calculate that, we start with our realized price, which you can see at the very top of the chart there. So we were just under $79 US per BOE in Q3, and that's, you know, including our realized gas price of just over $13 per Mcf. And then, with condensate sales at a premium to Brent, we were able to see a just over or just under $1.50 increase from Q2 to $79. We subtract off our royalties, which are orange, and our operating expenses, which are gray, in the gray bar there, to determine our operating netback, which was just over $70 per BOE, which is a record for Alvopetro. So, on the royalty side, we do pay royalties, generally between 8.5, around 8.5% plus some or overriding royalties. But, for natural gas, our royalties are based on a value which is more tied to Henry Hub, like the raw, unprocessed natural gas. So with Henry Hub pricing coming down this year, our royalty rate as a percentage of sales has come down, so in the quarter it was $2, which was about 2.6% of that realized sales price. Our operating expenses, you know, we did have lower production this quarter. A large portion of our operating expenses are fixed in nature, so our operating expense per BOE did go up. But still, we were able to generate record netbacks of over $70. And when you compare that to our realized price of $79, we're looking at a profit margin there, a netback margin of 89%, which is really best-in-class, and we like to show this slide here next. So for any of Latin American producers and North American natural gas-weighted producers that have released Q3, we compare our netback. Similar to past quarters, when we've shown this, you know, we're at 89% netback margin, compared to an average of 61%, so around 45% higher than these peers. You know, this is all before income tax, and just recall that we benefit from low income tax rate on our natural gas profits in Brazil, due to the SUDENE tax incentive that we're eligible for until 2030, and that's 15%. So, you know, some of these other operators will be in the 30%-40% range. So on an after-tax basis, it just shows the value of this production. And if we move on to our funds flow from operations, which is after tax, you know, we did see a bit of a decrease, $1.4 million, from last quarter, you know, due to that reduction in sales volumes, but still, at $9.6 million, that's very strong funds flow in the quarter. Similarly, net income also impacted due to that reduction in our funds flow, and then also there was a swing in our foreign exchange. We did have a loss in Q3 compared to a gain in Q2 of foreign exchange. Recall that most of that is on our intercompany loans, and it's all non-cash, but it's an accounting thing that we have to present on our income statement. So, you know, with the reduction in our operating netback and that change in FX, that overall loss in the period, offset by some reduction in taxes, we did see a decrease in net income of $4 million this quarter. Going to the balance sheet side, just recall that we did pay all of our debt off just over a year ago now. So we are debt free, so no debt on our balance sheet, and strong working capital. You know, that we did see a bit of a decrease from over $6 million from June thirtieth. That was... You know, we did have some capital expenditures in the period and then lower funds flow, but still very strong financial position and still well-positioned to execute on our long-term plan. All right. Thank you, Alison. Just to recap on our dividend track record here, we did introduce that back in the third quarter of 2021. You can see it was increased three separate times, and for the last three quarters, we've been paying $0.14 per quarter. Translates into a yield at current share prices of about 9%, and you can see we've already returned $0.90 to shareholders since we came on production from our key project. So just talk about our disciplined capital allocation model. If you recall, we established this quite a long time ago, even before we came on production, where we're roughly looking at, at targeting to reinvest about half of our cash flows in organic growth through capital expenditures, and take the other half and return that to stakeholders in, in its various forms. So this graph kind of shows what that looks like. The green line with the black dots here represents all the cash inflows, so the cash flow from operations that Alison walked through, earlier. Again, in the third quarter, that was $9.6 million. Each of the stacking bar charts represents the cash flows or cash outflows from each quarter. So you can see at the beginning, just a reminder, as Alison noted, we took a lot of those cash flows at the beginning and really focused those on repaying our project financing loan that we got in place and paying that off in a rapid fashion. That's the green cross hatching here. The dark, solid green at the top of these bars is the dividend that I reviewed. Again, it was introduced in the third quarter of 2021. And then, you can see more recently in yellow that we've now started to focus on the capital investment side of our business, and we'll talk a little bit about what that looks like and what that looks like going forward. In total, since we came on production, in the third quarter of 2020, you can see how this has been split. So in total, we've now had funds flow from operations of $118 million. 44% of it's went to capital expenditures. Almost, exactly, just shy of 50%, 49%'s gone to the various form of stakeholder returns, and the remaining 7%, this wedge here, is the part that's built up cash and working capital for our future, financial flexibility. So our organic growth plan, again, we've got a near-term goal here of getting to 18 million cubic feet equivalent a day, or 3,000 barrels of oil equivalent per day, with a longer-term vision of basically doubling that. The growth plan to come from really, a couple of key areas. We've got our existing platform of producing assets with our Caburé unit, which you can see in the center of the map sheet here. We did expand the gas plant last year up to 18 million cubic feet a day, plus, depending on the gas specification that we're putting through there. We are looking to further expand the unit production capacity here as we drill some additional wells next year with our partner. The second part of this is really this key asset that we have immediately to the north of that, which is our Murucututu project. We've already pipeline connected that in and put all the production facilities in place so that we can now crystallize the value associated with this asset. and, you know, one of the things we've always talked about this as a, as a Gomo formation opportunity, and, and we've got some reserves and, and contingent and prospective resource assigned to that. And it's important to remind people that that just relates to the Gomo formation. And, and something more recently that we're quite excited about is the result that we had with our 183-A3 well, which Adrian's gonna walk you through. But it's important to recognize that that was drilled as a Gomo development well, but it also had this Caruaçu exploration potential. So when you look at the result, you know, about 12 meters of the net pay that we see in that well relates to the Gomo, but 116 meters of the potential net pay relates to this Caruaçu. So we're really excited about that. It's on the same well pad as our production facility, so with success, we can get that tied in right away. This has the potential, again, with success, to be a really important part of our plan going forward, and could be quite important for us and our shareholders. Yeah. So as Corey mentioned, we finished drilling our 183-A3 well last month. So this is a 100% working interest well into the Murucututu field, and we were quite excited to see the 116 meters of net pay in the Caruaçu. So in the log here on the screen, we see the number of net pay sections within the Caruaçu section. So at this point, we're mobilizing the equipment, and we'll go through and complete each of these zones and co-mingle them onto production with the intent of having this thing on production by the end of the year. And like Corey said, we've pre-invested in the infrastructure here, so this should be tied in. It's 10 meters away from the pipeline, and we'll start to crystallize the value here with this well. This gives us a regional overview of the Caruaçu and where it lies within the context of the other producing wells in the basin. So our well we're talking about here at Murucututu is right in the middle of the geological cross-section, the seismic section there. And this well, and this structure is down dip of the Caburé Field, which is our main producing asset, down dip and across the fault here. The other field to the north is Maracanã, which is one of the larger gas-producing fields in the basin, and then to the South is another large historical field called Taquipe. So we're really looking forward to, you know, tying this well in, putting it on production, and continuing the reservoir exploitation here, the Caruaçu structure. All right. Thank you, Adrian. So just in summary, I think, you know, Alvopetro certainly continues to offer a pretty attractive investment proposition, no matter what your focus is. We're delivering some pretty strong results. Obviously, very attractive gas pricing, industry-leading operating margins. We've got a clean balance sheet with strong free cash flow generation capacity, and that all helps support this supports this disciplined capital allocation model that we've got to balance reinvestment, organic growth, and stakeholder returns. For value investors, we're trading at about two-thirds of our 2P NPVs. Again, none of this Caruaçu potential that Adrian reviewed is reflected in any of our reserves or resource reports. For yield investors, a 9% dividend yield paid quarterly in U.S. dollars. And then for growth investors, you know, we've got a pretty exciting, organically funded capital program with a lot of potential, especially when you consider it relative to our existing market cap and enterprise value. So with that, I think we'll start the question and answer period. Sure. The first question relates to sales volume. Sales volumes were much lower in Q3, but seem to have come up in October. Can we expect the rest of Q4 and early 2024 to continue at similar rates to October? Yeah. So, really, this is a function of the demand in the basin and how our offtaker is managing their portfolio of gas. You know, right now, Bahiagás has been asking for as much gas as we can basically give them. So I think, you know, if we had our 183-A3 well on production today, we'd be able to be selling all that. So our expectation is that this was a temporary thing. It's not to say it couldn't happen again, but our expectation is that, you know, we'll be able to sell all that. How often is the Bahiagás contract renewed or adjusted for demand? Are there any options available to sell or export to additional buyers in the event Bahia doesn't increase our volumes? Yeah, no, so that's a good question. Typically, Bahiagás is looking at commitments on an annual basis in their portfolio from a firm perspective. You know, the firm component of our supply, you know, does... If we were ever to have an issue with a well or a facility, it can attract supply failure penalties. So, the way we've been managing that is having a component of firm and a component of flexible or interruptible gas that gives us more flexibility. You know, typically, Bahiagás has been taking all that. We've had this one exception in the month of September, effectively. So, you know, that's something we'll look at. We have the ability to increase. So from a strategic perspective, what we're doing is we want to add as much 100% working interest production as we can, so that no matter what's happening with the production from the unit at Caburé, we have the ability, you know, step one, to be at this 3,000 BOEs a day, or 18 million cubic feet a day rate. So once we get enough, all that capacity in place, then we can be in a position to increase our firm nominations within our contract, up to, up to that level. So that would increase kind of the insurance or base level at which we would get paid, because also in our contract is a mechanism where there's take-or-pay payments that happen with Bahiagás. So in the event that they took less than the threshold within our contract, we get paid for that regardless. So, again, strategically, that's the plan: build enough capacity, increase our firm volumes, and then in addition to that, build some extra flexibility around, you know, exploring alternative markets. So we are, you know, a few hundred meters away from the main TAG connection in the basin. There's some other offtake ideas that are out there that could, you know, realize some attractive netbacks as well. So we're pursuing all that, but in fairness, you know, we've got this strategic connection directly into the Bahiagás distribution network right at our plant site, and that creates a big advantage for the end consumers and for Alvopetro and for, for Bahiagás. So I think it's in everyone's interest to maximize the amount of locally produced gas that goes through that city gate, as opposed to, you know, the alternative is importing it from LNG, importing it from Bolivia, you know, bringing it from the offshore pre-salt. And there's a bunch of transportation and other costs that get embedded effectively in the gas price when that happens. So, you know, we think we're well-positioned. The next question: What is the expected CapEx for Q4 of this year, and where will it be spent? Yeah, we don't really provide CapEx dollar guidance. But our activity levels, you know, after our Balangar result, we decided. The rig had a commitment with another provider, so the rig's moving, in the process of moving to do that commitment. So really, our lingering capital commitments are mostly associated with completing the 183-A3 well. And then you'll see, you know, a drop in capital expenditures here while we digest those results and get ready to restart the drilling portion, which is the most capital-intensive portion of our capital program. You know, practically speaking, that probably doesn't happen until, you know, at earliest, later in the first quarter. The next question is around the results from 183-A3 and the positive surprises that were seen in the Caruaçu. Do you wanna comment on that further, and what are the plans to appraise this? Yeah. So, you know, if you look at the porosity of this, you know. So first of all, you know, the wells at Caburé are highly productive. It is a bit shallower, so we would expect better permeability at the shallower depths. But this is quite a prolific formation. The logs look quite good. We've got, you know, some of those intervals that Adrian pointed to that we're going to complete, you know, have porosities up to 15%. So, you know, we're optimistic. We're not gonna put out a bunch of... We're on the cusp of testing this, so we're not gonna put out guidance on what we think it might be. I think we're just gonna ask people to be patient, and we're gonna get that news quite quickly. But the appraisal plan is, yeah, complete these zones, put it on production. You know, we can map the resource over on seismic, over you know, a pretty nice area here. It has the potential to be quite material for us, but you know, it's one step at a time. We need to test it, produce it. We'll evaluate those results, and then you know, we're in the middle of permitting a new drilling pad location that would allow us to access all the up-dip locations. So what Adrian didn't talk about, but it was on that slice of 3D seismic, you can see between the fault and where we drilled the well into the Caruaçu, there's room to go up-dip another 120 meters. So even just from that well to the up-dip crest of the structure by the fault, there's almost 300 acres of land in there and 120 meters up dip. So that in itself could be material, and then the various sands probably have different aerial extents, but that's something that would be delineated with additional drilling. The other nice thing is a big chunk of the wells that we had planned to target the Gomo development, you know, a good portion of those drill right through the Caruaçu as well, so it's nice to be able to have multi-zone targets. The next question, just shifting gears a bit: Can you take us through the accounting of the Bahiagás take-or-pay shortfall going forward? So yeah, I didn't comment on this earlier. We did have, when I was discussing the accounting results, we did have, Bahi agás take-or-pay kick in in the month of September because they were below the firm volumes. That's basically just a prepayment of gas, so what happens is it does not get reflected as sales until the volumes actually get delivered. So we get effectively the cash from Bahiagás, and that's offset with, we call it other liabilities, but it's essentially unearned revenue, and then as the gas gets delivered, the revenue gets recognized at that point, and then they get a reduction in their invoice, for the portion that's applied against that prepayment. So it's relatively straightforward. It's, you know, with production at these rates, we do expect that that, that September amount will get recovered, rather quickly. And yeah, I think I answered that, but if you had any further questions on that, just maybe shoot me a note offline, and we can go through it. The next question is around Bom Lu gar. Are there still plans for a follow-up development well BL-7 at Bom Lugar? You know, quite frankly, we weren't happy with the results from that, so right now there's no plans, but we are gonna continue to evaluate the production from that well. We're gonna look at alternatives, potentially, to stimulate it, but the capital plans are on hold right now. Back to Murucututu, are there still plans to get to 5 million cubic feet a day in 2024? Are the plans still on track for that, and what is the timing for further Gomo development wells? Yeah, so a lot of that is a good chunk of that is actually a function of the test results that we get from this upcoming test, and that will help define, you know, a little bit better on a per-well basis what we might expect from drilling new wells. We then would expect to use that to map out our capital program for next year. So that will, you know, impact the timing. But again, dependent on those well results. You know, I'm not sure where the 5 million million a day target came from, but you know, we think this can be along with the Gomo, a big part of our growth story going forward. And then the next couple of questions are around the share buyback. Has it started? And given considering the capital program to date, corporate discount to PV-10 and increasing share count, are we anticipating a reallocation of some 2024 capital spending towards share repurchase? Yes. So the short answer is no, we haven't used it. I think you saw from the pie, since inception, we've been pretty good about almost allocating the entire 50%, as originally envisioned, to the stakeholder return bucket. You know, going forward, you know, we wanna get this well test result, 'cause that can help define what our capital portion of the equation looks like. It helps define what our cash flow projections going forward look like, and then we can balance that 50% of the pot, as deemed prudent between dividends and share buybacks. Okay, and with that, there are no further questions. All right, well, as usual, feel free to call us at any time, and we're happy to talk to you and answer any additional questions you might have, and thank you for joining us today. We look forward to updating you after our Q4 results. Thank you. Thank you.