Thank you for joining us today for a fireside chat with Chief Executive Officer George Maxwell from VAALCO Energy. I am Jeff Robertson, Managing Director for Natural Resources at Water Tower Research. Before we begin, I would like to remind participants that our discussion today could include forward-looking statements as of today, December 2, 2025. VAALCO's disclosures regarding such statements can be found on the Investor Relations tab of its corporate homepage. VAALCO is an international oil and gas exploration company with assets located in Gabon, Egypt, Canada, the Ivory Coast, and Equatorial Guinea. VAALCO's asset portfolio combines a mix of short-cycle development projects and long-cycle development projects and exploration prospects that expose the company to future growth opportunities and support management's goal of building value and returning cash to shareholders. With that bit of introduction out of the way, George, thank you for taking the time to join us today. Thank you, Jeff. Thanks for the introduction, and I'm looking forward to the chat. Before we get to the development or the drilling campaign that's getting underway in Gabon and some of the plans for Côte d'Ivoire for 2026, I just want to revisit some of the capital program for 2025. VAALCO's original CapEx outlook for the year, which was published back in March, called for total CapEx in the range of $270-$330 million. The midpoint of total NRI production was estimated to be about 15,600 BOE per day. The latest full-year estimates, which were updated on November 10 in conjunction with third quarter earnings, pegged the CapEx midpoint at $243 million, or 20% below the original midpoint, and pegged the NRI production midpoint at 16,500 BOE per day, or a 6% increase from the original midpoint. George, can you walk us through where the CapEx savings have come from and really what's driven the better-than-originally-expected NRI production outlook? Yes, it can. I mean, we indicated some of these responses in our last earnings call, and predominantly we've seen, with a softening commodity price, we revisited our CapEx program for 2025, and we've removed around about $20 million of discretionary CapEx that was originally planned for this year. In addition, we've seen some increases in CapEx, primarily around the Ivory Coast project around the MV10, where we've pulled forward about $10 million of CapEx into 2025 to ensure that we can keep the MV10 project on schedule, but we've also seen, against the original budget, a delay in the drilling rig for the drilling program in Gabon. That's been delayed probably between two to three and a half months due to the availability of the rig, so we've seen some of that slippage for the capital program for Gabon slip into 2026. Those are the three key elements that have allowed us to have a lower CapEx guidance for 2025. When we look at the production and the performance, particularly in Gabon, we've seen continued improvement from our forecast position and our modeling position from the Etame field. Now, part of the production increase has come from the continued flowing of four-eighths on Ebouri. We started that well up. It's been flowing very well for most of 2025. We started that well to allow us to test exactly how we were handling the H2S issues that we are all well aware of in Ebouri and whether those could be handled with the chemical scavenging that we have been planning for. I'm happy to say that well has performed well. It's getting us well above our production forecasts. When I look at how much of this increase in the NRI performance is related to reservoir performance and how much is related to the top-sides activities that we undertook in 2022 and 2023, you know, that's probably about at least 1,000 barrels a day contributing to those combined factors. And about 60% of that comes from the reduction in back pressure that we successfully completed with the reconfiguration of the field. And about 40% of that is coming from enhanced field performance. With respect to the production performance, is it reasonable to expect that you may see some positive performance-related revisions when you go through the year-end 2025 reserve evaluation process? There's two sides to that. One is definitely yes. We are anticipating, or we do expect to see significant revision movement within our reserves position. Now, obviously, we can't quantify that yet until we go through the evaluation process with Netherland Sewell. But given that we have not spun the drill bit in Gabon for two years, and what we've seen in the production performance, you know, the opportunity does give rise to significant revisions within the profile. So that's certainly what we are anticipating, but we won't be able to quantify that until we complete the exercise in early January. I think the original plan in Egypt that you laid out earlier in the year called for eight to 13 new wells. Through the end of September, VAALCO has completed, I think, 14 new wells in the year. Can you talk about what's driving some of the efficiency gains that you're seeing in Egypt that allows you to do more projects with the same or even hopefully a little bit less capital? Yeah, there's two key elements there. The first element is, obviously, we've had this drilling rig working continuously for probably close to a week now. And that position allows the efficiencies on how we're executing the wells and with the experienced team on board and the performance of the rig. So we've gained efficiencies there, and those efficiencies continue to accumulate for us in each well we drill. And secondly, you know, we've established in Egypt, from where we were when we first acquired that position back in 2022, we've continually improved the supply chain for providing the equipment inside Egypt for delivering these wells. So we've got limited to no downtime with the equipment, limited to no downtime on rig performance. And that, combined with the types of wells we've started drilling now with more of the slant wells, has contributed to us being able to drill more wells with the same level of CapEx. And you can see, although we're doing a little bit of a post-action review here, you can see how well it's held up in the Egyptian production performance. I know VAALCO won't provide any detailed capital spend or operating update for 2026 until probably March of next year when you report your year-end financial results. But from a high level, George, how does the result, or how do the results in Egypt make you think about constructing a capital program for that asset base in next year? We definitely are reviewing that right now. The first key element here is to understand the after-action review of the wells that we've drilled in 2025 and the ones we are just finishing off here in Q4, and then to review the performance of those wells and how they delivered and what have they delivered in respect of the reservoir performance that was anticipated. So before we move into a 2026 program, we have to do a review of where we can optimize the next drilling sequence in what is an aging asset. So where can we get the biggest bang for our buck in targeting both with the workover positions and the new drill opportunities? What are we doing when we look at the opportunity in SEENT? And we've tried to evaluate that now between the gas and oil split, and that's still under evaluation. I think when we look at Egypt's performance, it's been a strong performance in 2025. We're going to have to do an evaluation of the subsurface position to exactly where we want to position any 2026 drilling program. Earlier in Gabon, you mentioned that the rig was a little bit late coming off its prior contract. Is the rig on site at Etame now? And can you talk about how that drilling program will unfold as we look into 2026? Yes, it can. So the rig is on station. It arrived with us last week. We had a couple of days waiting on weather before we could pin it to the platform. But it is pinned to the platform now. And as of today, I think we're currently jacking up the rig. So we would expect to spud the first well in the next 72-96 hours. So that would be the first well on Etame. When we look at the program, and as you know, we've got five firm wells and five optional wells. So we start the program in Etame with definite two firm wells to drill there with an option of a third that we may consider during this program. And then the rig would then move to SEENT, where we plan to drill a gas well for field fuel to reduce our diesel consumption. Then if we don't exercise options, we'll then move to Ebouri with the two-eighths workover, sorry, the four-eighths workover, and then a position on five-eighths drill. So it's quite an extensive program. We can be doing up to 10 wells. However, what we're trying to cycle in here is how the first wells are performing and trying to make a judgment call as to when we call off the options to minimize the amount of rig moves we have within the field. So the current, or maybe it's a little bit revised from what you talked about in prior quarters, creates a more efficient drilling program with the rig. Is that what you're trying to explain? Yes. I mean, before, because we initially were focused on moving, I guess, to Ebouri as a first location. But because we've seen strong performance on two-eighths, strong performance on four-eighths, that has necessitated that perhaps we go for, fill up the Etame slots first. In addition to that, over the last six or seven months, we've seen a depletion of the gas well in SEENT, and we've seen an increasing consumption of diesel in order to power the field. So that kind of brought forward that gas well in SEENT in order to alleviate the OpEx concerns that we have for increasing diesel. So it's just a basic re-sequencing. But what it does make us do is consider when we exercise options, the timing of those options to then minimize the rig move, because the options that exist, they exist in SEENT, they exist in Etame, and they exist in Ebouri. So what we'd try to do is get our ducks in a row for exercising those even when we want to, to minimize moving between the three main platforms in the field. Can you put a range on, a dollar range on the amount of OpEx savings that you might be able to achieve with the new gas well that you plan by displacing diesel as fuel? It's probably somewhere between $350,000-$500,000 a month. You talked about Ebouri, or the four-eighths well performing well to the crude sweetening chemical process that you all are testing in that well. How does the performance there impact the ability to monetize the reserves, which have been stranded since that field was partially curtailed back when the H2S concentrations increased? Some of those reserves already came back when we put forward the plan in 2024, and we confirmed the viability of that plan. Some of the reserves came back under the 2P scenario. Certainly, when we look at the issue on four-eighths and the performance of that well, given the age of the ESPs and the completions, that's certainly performing well. There may be a narrowing of the opportunity to work over that well because it's performing so well. There may not be enough reserves left in that well to justify a full workover. When we then look at two-eighths, two-eighths has considerable reserves still to produce. The workover in two-eighths is really to facilitate our ability to inject the chemicals downhole and be much more efficient in the scavenging operation for the H2S. The key, in my view, is the opportunity to the sidetrack on five-eighths, which I think holds a great opportunity for enhancement of our position in Ebouri and really monetize. To answer your question, I think the bigger prize is on the five-eighths drill than the other two potential workovers. At the capital markets day in May of earlier this year, and I remind people, the slide deck is available on VAALCO's website under the investors tab. The phase III development program in Gabon, which is beginning now, was expected to test 2P reserve volumes in excess of 10 million BOEs and potential incremental initial production of about 16,000 BOE per day. Given the timing of the program and how you have it laid out now, George, should we expect those projects to be evaluated in time for later 2026 production and year-end 2026 reserve bookings? Almost definitely, I would say. I mean, as I mentioned, the workovers, such as the workover in two-eighths, doesn't really enhance any reserves. It's there to make it more efficient to produce with the scavenging opportunity and the down hole, the workover for down hole injection. But certainly, when we look at the Etame position and in particular the Ebouri position, those are where primarily the most of the reserves will come from. There is an opportunity for an optional well on SEENT, which is a little bit more complex, a little bit more difficult to drill, a little bit further outreach from the platform. But when we look at the main contributing opportunities, they reside within Etame and within Ebouri. So we're looking at potentially the drilling phase completing, depending on how many options we exercise, somewhere towards the end of Q3 in 2026. So that does give us enough time to ensure that the results of that are fully within our 2026 reserves process. As I said earlier, the 2026 financial and CapEx guidance won't be released until March of next year. But with the five committed wells and the Gabon campaign, can you put a rough CapEx range around, or an estimated range around those wells for us? Yeah, I mean, we've had obviously split some of 2025 CapEx into 2026, and that volume was somewhere around, I think I mentioned earlier, about $40 million of that in relation to the program slip. On a gross spend basis, we were always budgeting around $250 million. So net to VAALCO, about $160 million on those wells. And we've quoted that previously in our capital markets day. So you can work out probably somewhere in the region, net to us, of about $100 million-$120 million we slip into 2026 for the CapEx program from the previously disclosed information. Now, when we come to do our CapEx guidance, we'll also have a lot more granularity to that as it folds out to the totality of our investment program across all our activities. But that's a rough rule of thumb for Gabon, for the drilling side. Elsewhere, Gabon's seismic program could commence on the Niosi and Guduma exploration licenses later in 2026. You talked about the performance of the reservoirs at Etame exceeding expectations. Should we expect that some of that outperformance at Etame and the upcoming development campaign to have an impact on the seismic interpretation and prospect development on those licenses, or are they in some sort of a different petroleum system? They're all in a very similar petroleum system, but we're talking about connectivity of these systems. And I don't believe we've seen from the existing seismic within the Etame field block that level of connectivity. Now, the seismic activity, yes, is due to commence early, late 2025, early 2026 for Niosi and Guduma. What we do believe, and we've put this up on the map, and I think our partner BWE believes also, is that we have active hydrocarbon systems from Etame down south through Dussafu where BWE operates. So this seismic program is key to identifying those potentially active hydrocarbon systems and where potential connectivity can be made, not just, as I said, I don't think we've got connectivity in the hydrocarbon systems, but the connections back to production facilities is also key. That's where we see potential life extensions both in Dussafu and in Etame, where near-field opportunities to tie back to existing infrastructure is where we see the prize on these seismics. So the seismic taking place, acquisition, then interpretation is going to be all through 2026, is what I understand. If we shift gears to Côte d'Ivoire, the operator of the Baobab field expects the FPSO to return, I think, late in the first quarter of 2026. I think you said on the call recently that the hookup should be completed during the second quarter. George, just from an operating perspective, how much time does it generally take to restore the production to, or restore production in the field to the levels approaching where it was when you took it offline? We've got in the program that we've seen today from the operator. I think there's about a 70-day plan for the hookups. So that's picking up the flow lines and reconnection back to the FPSO. Also, during that time, obviously, we've got systems commissioning, et cetera, will run parallel to that. That's really, that 70-day period is where we see between the arrival of the FPSO coming into the field, which is going to be sometime during March, from a January 31 sailaway, and the recommencement of production sometime during May. Those timelines are currently still within the project plan. We're not seeing any movement on that. As we mentioned earlier, we're still seeing a sailaway date for 31st of January, which is a key date where all the work on the vessel has been completed and the contracts laid for the recommissioning. Right now, what we still haven't seen yet is the complete startup sequence for the wells. That will really then dictate what levels of production will come on when. We've got some forecast for that, but until we see the full startup sequence, it's difficult to comment on that. That's something we'll definitely be giving guidance to during Q1 when we give our 2026 guidance. Do you expect the FPSO upgrades to have an impact on operating costs and operating efficiency, kind of like what you saw when you reworked the infrastructure at the Etame field? There's a couple of points there. One, this is slightly different from what we did in the Etame field. In the Etame field, we moved a lot of the processing equipment onto the platform. And therefore, we've just got a dumb storage vessel. And we moved and modernized all the processing equipment through Etame. Here, what we're doing is, or what the operator's doing is effectively reconditioning the existing processing plant. So we're not seeing significant upgrades in the processing plant from that standpoint. But we are seeing, obviously, renewals of steel, confirmation through the recoating of the tanks. We're seeing the class issue being renewed for the vessel through its tenure to end of field life or beyond. So we would expect to see some efficiencies through reduced downtime for maintenance. We've also got added engineering capacity on for some of the to accommodate phase V drilling and to accommodate flowlines for Côte d'Ivoire. So there are efficiencies in there that will come with volume when the phase V comes in on a per barrel basis. But dollar-for-dollar reduction, I think the best way we'll see that is once it's back on stream and see where we are for maintenance downtime. That's a key that we'll be focused on. You mentioned phase V development. So the development program in Baobab is expected to begin after the FPSO is put back in service. You talked about some of the upgrades. Should you expect those to shorten the cycle time of connecting wells or new wells into production? There's not a shortening of the cycle time. I mean, the upgrades have been done to the FPSO in order to accommodate phase V when Côte d'Ivoire facilitates that connection. So it means there's not a requirement for engineering work that would have been required if we hadn't taken the vessel offline. So I don't see any shortening of the connection time or the hookup time. It's just that now we have a topside position that can accommodate those additional production lines. Again, it's capital markets day. The phase V development plan, or program, as it was laid out at that time, talked about targeting gross reserves of about 33 million BOEs with a peak gross production of about 27,000 BOE a day. How should we think about the reserve and production impact of phase V in 2026, or would that be more of a 2027 impact? Yeah. Right now, we see probably a late Q3 spud date for phase V. So that's definitely going to fall into 2027. I don't see us, and again, we haven't had detailed discussions with the operator, but I don't see us getting enough wells down to make any significant reserve impact in 2026. You mentioned the Côte d'Ivoire development project as a potential subsea tieback to the FPSO. Can you share any color on the timing of that project and what it could mean? Yeah, we still have to have those discussions with the operator. I think when we put that in our capital markets plan, we had it somewhere around late 2027 into 2028 for that. But if you just think of that potential timeline for the establishment of well locations and then equipment ordering for subsea trees, we're probably into the 2028 cycle time. By the time we've got that ready and fully planned, we've got an FTP planned and submitted to the government, and then we start to look for rig and equipment. So it's probably going to be a 2028 startup position at the earliest. George, if we move to Equatorial Guinea, you talked recently about continuing to evaluate alternatives to develop the Venus discovery in the most economic fashion on Block P. You mentioned that a subsea tieback to a facility located in shallower water on the shelf could become the preferred scenario. Can you talk about how that type of a development, number one, impacts the decision line toward an FID and ultimately timing of when that could begin producing? Yeah. So the original plan of development was a move crew on the shelf with a long reach drill from the shelf down into the reservoir. And what we tried to do in the feed study was look at how can we switch CapEx for OpEx in a field that has a relatively short life of about 60 months. It's high production, short life. And when we did the feed study, part of that was to look at can we look at leasing a move crew and planting it on the shelf, and how do the economics work. And going through all of that position, we did get to a point where the proof of concept was definitely there. We'd already established that. The proof of concept and the long reach drilling was there. But what it also highlighted was drilling, extended reach, and the angles of attack coming into the reservoir on a three-to-four-kilometer basis were giving some high risk factors. It was possible, but it was a high risk factor. So what we jumped to was how does that look if we did a vertical drill? And all of a sudden, all the risk factors on a vertical drill, given how shallow the reservoir is from the seabed, disappeared. And it gives us the opportunity to have much more accurate well placement, especially for the water injector, which gives us a greater confidence in the sweep efficiency for the reservoir. And therefore, when we did remodel the reservoir simulation model, we came back and reconfirmed the potential of this field to produce 20,000 barrels a day. So, taking that de-risk position from a vertical drilling solution into account, we then said, okay, in order to be able to do that, we need to look at the efficiency of how do we do subsea tieback to topsides. And that's really where we've extended the FEED to look at the opportunity set where another FPSO coming in and that tieback opportunity for location of trees and timing, et cetera, how does that stack up against the surface MOPU that we would have on the shelf? And that's where we've kind of extended the study too. We've looked at those opportunities. And when we look at the economics, now, of course, a vertical drill from a drill ship on a day rate basis is much higher than a jack-up on the shelf. However, the time is less than a third to drill those wells from vertical than it is to drill from the MOPU. So from a drilling perspective, it's almost a wash. And so therefore, we're looking at how efficient can we get on the topside. So that's really what's moved it from that extent to a simple MOPU and storage at the shelf. And it really was to try and de-risk the two elements, the key elements for this study that came out of the study for me was, again, how resilient the reservoir will be if we get the water injection well in the right place and the kind of benefits we can get from that in the order of the recovery factors. But secondly, it took away 90% of the risk factors and complexity on the drilling position, mainly because we can come into the reservoir from a much more efficient standpoint from the vertical versus the shelf drilling. Do you expect to be in a position with all of the evaluation to consider an FID at some point in 2026 on that project? I would certainly hope so. I mean, this project we've demonstrated already, it has considerable value to the company, both in terms of production and economics. It's just about balancing our capital spend with the commitments we have right now and making sure that if we are aware to enhance that capital spend, we're very firm on the execution plan in Equatorial Guinea to give us that return as quickly as possible. So there is a little bit of planning has to take place so we don't overstress our capital position in the near term, but also make sure that we exploit as early as possible the value opportunities that can give us great returns to the company and to our shareholders. As I said at the outset, VAALCO has a project portfolio across multiple countries in Africa that expose it to significant reserve and production growth over the coming years. Upcoming activity in both Gabon and Côte d'Ivoire could begin to crystallize some of that opportunity over the course of 2026 and 2027. George, just to wrap up on your capital framework, can you talk about how you think about managing the program, which is essentially a multi-year type program, an opportunity set against the backdrop of $60 plus or so Brent oil as we look in, at least today as we look into 2026, and how that impacts VAALCO's ability to maximize returns and continue your goals of returning cash to shareholders? Yeah. I mean, clearly, we've got to focus on wherever we invest in the dollar, how quickly does that dollar come back to the company? So greenfield developments take some time. And greenfield developments, making the commitments on greenfield developments can tie up cash for extended periods of time. In order to commit to the greenfield developments such as EG or CI-705 that we're involved in as well, then we need to make sure that the near-term production and the operating cash flows coming from those near-term productions are coming back as quickly as possible. And that's where what we're investing in Gabon right now, enhancing that production and working closely with our partners there to ensure that we not just provide enhanced production, but we provide further longevity to that field. It's worth remembering for Etame that when the company first entered that in 2002, it anticipated five million barrels to be recovered. We're currently not far off of 150 million barrels of production. So this is definitely an asset we want to invest in. It's definitely an asset we think we can continue with its longevity. We then couple that with the near-term production opportunities in CDI and where we are with the investments that we're making with our partners there. And the investment in, again, enhancing the longevity of CI-40 right through to 2038 with the refurbishment of the FPSO and the commitment to at least phase V and drilling programs to, again, enhance that recovery. Those are, for me, the cornerstones of where our investment profiles will be because those are the shortest time frame for those dollars to come back. Now, when those dollars come back, we then have the choice. What do we do with those dollars? Do we go after our greenfield opportunities and also provide a return to our shareholders? And this is where we have the balance. We have a portfolio. That portfolio is there to ensure near-term monetization, but longer-term operations through into the 2040s. So the company has a visibility way beyond the next two to three years. And it's balancing those activities because we have to continue to invest. We can't just manage depletion because that is, especially at lower oil prices, that's ever-decreasing circles. There's only one way that's going to happen in operating cash flow goes down. So we have to invest in order to enhance the production and manage our cash flows at these lower commodity prices. And I think where we are right now, we've got lots of opportunities. I would love to have an endless source of liquidity to go after them all today, both human resources and monetary, but we can't. So we have to balance that with recognizing where the near-term opportunities deliver the near-term returns to both the company and the shareholders. George, I think we'll leave it there for today. I know with the portfolio you have, we'll have plenty of opportunities to host another Fireside Chat as we get closer to the startup of production in CI and progress on the development campaign in Gabon. So I want to thank you for taking the time for joining us today. I certainly definitely look forward to it. And surely, as we know, we started the drilling program. So by March, we're going to have an awful lot to talk about between Gabon and CI-40. Good. For our participants, I want to thank you for joining us for today's Fireside Chat with George Maxwell from VAALCO Energy. Our research can be accessed from our website, www.watertowerresearch.com. The views expressed in this Fireside Chat may not necessarily reflect the views of Water Tower Research, LLC, and are provided for informational purposes only. This Fireside Chat may not be redistributed or reproduced without the written consent of Water Tower Research and should not be considered a research or a recommendation. WTR is an investor relations firm and not a licensed broker, broker-dealer, market maker, investment bank, underwriter, or investment advisor. Additional disclaimers can be found at watertowerresearch.com. George, once again, thank you for joining us today. Thank you very much, Jeff. It was a pleasure talking to you, soon. Thanks. Thanks. Bye-bye. Thanks. Bye-bye.