Thank you, operator. Welcome to VAALCO Energy's second quarter 2024 conference call. After I cover the forward-looking statements, George Maxwell, our CEO, will review key highlights of the second quarter. Ron Bain, our CFO, will then provide a more in-depth financial review. George will then return for some closing comments before we take your questions. During our question and answer session, we ask you to limit your questions to one and a follow-up. You can always re-enter the queue with additional questions. I'd like to point out that we posted a supplemental investor deck on our website that has additional financial analysis, comparisons, and guidance that should be helpful. With that, let me proceed with our forward-looking statement comments. During the course of this conference call, the company will be making forward-looking statements. Investors are cautioned that forward-looking statements are not guarantees of future performance, and those actual results or developments may differ materially from those projected in the forward-looking statements. VAALCO disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise. Accordingly, you should not place undue reliance on forward-looking statements. These and other risks are described in our earnings release, the presentation posted on our website, and in reports we file with the SEC, including our Form 10-K. Please note that this conference call is being recorded. With that, let me turn the call over to George. Thank you, Al. Good morning, everyone, and welcome to our second quarter 2024 earnings conference call. We began 2024 with positive operational and financial results, including strong earnings and Adjusted EBITDAX generation. Operational excellence and delivering consistent production is key to allowing us to grow Adjusted EBITDAX. For the past two years, we have met or exceeded our quarterly production guidance. We are executing at a high level and continue to deliver results in line or above our guidance. This is due to strong drilling and workover results in Canada and Egypt, coupled with strong uptime in Gabon. Also, in the second quarter, we closed the Svenska acquisition at the end of April, which helped us to increase our earnings to over $28 million or $0.27 per share, and grow Adjusted EBITDAX to $72.5 million. We continued to return cash to our shareholders in Q2 2024 through our quarterly dividend, and we announced our third quarter dividend as well. I would now like to go through and give a quick update on our diverse portfolio of high-quality assets, beginning with our newest asset in Côte d'Ivoire. We quickly and efficiently closed the Svenska acquisition in an all-cash deal for $40.2 million on April 30, 2024. Our team traveled to Côte d'Ivoire to meet directly with the Ministry of Hydrocarbons to officially introduce VAALCO as the new partner in Block CI-40. This acquisition is highly accretive on key shareholder metrics, provides another strong asset to support future growth, and has significant upside potential. We added a solid asset with reserves that exceeded our initial estimates, and we did so at a very attractive price. Based on the results of our third-party reserve engineers, we have SEC net proved reserves as at year-end 2023 of 16.9 million barrels of oil equivalent, with 93% oil. Our previous 1P working interest CPR reserves were 13 million barrels of oil equivalent. This 30% increase in reserves further justifies the acquisition and improves the metrics associated with the purchase. We are working with the operator of Côte d'Ivoire and will provide additional information in the second half of 2024 on the Baobab FPSO project planned in 2025 and future Baobab drilling plans. Turning to Canada, we successfully drilled four wells in the first quarter of 2024, completed those wells in March and April, and brought the wells online. As a reminder, we drill longer laterals to improve the economics of the program, and all four wells are 2.75-mile laterals. Three of the four wells had very strong initial rates, with IP30 rates exceeding our type curve and one of the wells below our type curve. To show the impact of these new wells, in Q1, our Canadian production was about 60% liquids, and in Q2, our Canadian production was approximately 75% liquids. This strong oil production has rebalanced production in Canada more in favor of liquids, which contributes to the strong production performance and our overall profitability. As the wells continue to produce, they're coming in line with our type curve, and we are optimistic about the future drilling potential in Canada. As I mentioned last call, we are also targeting an exploration appraisal well in the third quarter of 2024 in our southern acreage. In our southern acreage, we have minimal horizontal subsurface information, and this exploration well, if successful, could prove up additional long lateral wells in the future with the potential to add proved undeveloped locations. In Egypt, as we disclosed last quarter, the first half of 2024 is focused on high rate of return capital workover projects to help mitigate decline. As you saw in the earnings release, we had four recompletions in the second quarter with some very strong results, adding about 800 barrels of oil per day when you combine the four IP30 rates. In addition to the successful workovers, I am very proud of a major milestone that we accomplished in the first half of 2024 in Egypt. We have gone over 2 million man-hours without a lost time incident, completing in the third quarter of this year. This is a testament to our commitment to safety, training, and dedication of all of our people in the field. As I mentioned on the last call, we have 10-15 well drilling program that we are currently evaluating in Egypt. This project remains contingent on completion of the program evaluation and confirmation of a drilling rig. We have not included this program in our 2024 CapEx guidance and won't add it until confirmed. However, if we proceed with the program, we anticipate additional CapEx of approximately $9.5 million, which will also generate additional production. We will see some additional production in 2024, however, the bulk of the additional production will impact early 2025 production. We have seen some positive announcements from the government in 2024, in particular, payment of AR receivables, which is very encouraging. Ron will go into more details regarding the Egyptian receivables. Turning to Gabon, in the second quarter, production was impacted by an Ebouri platform issue. Operationally, we had a planned maintenance turnaround in Ebouri in the third quarter, but due to the platform issue, we moved that forward into Q2. This issue was addressed when the platform was brought back online safely, and we will not have the turnaround now in the third quarter. You will notice that our Q3 production midpoint for Gabon is actually above the Q2 production of just under 7,500 barrels per day due to the movement of the turnaround at Ebouri. Given that we haven't drilled a well in Gabon in over a year, we are pleased with the positive overall production results and strong production uptime and improved decline curves on the wells. The FSO and field reconfiguration projects in 2022 have allowed us to minimize downtime, capture efficiency and reduce overall OpEx. Looking ahead to 2025, we have prepared a firm 7-well program that we plan to initiate first half 2025, subject to securing a drilling rig. The proposed program includes an infill well and exploration well in Etame, a Gamba infill well and a gas well for field fuel supply system, which will reduce our dependency on diesel and reduce OpEx, and 2 workover wells and a redrill of 3H on Ebouri. We have completed the analysis on Ebouri that we have highlighted in previous quarters. We will conduct 2 workovers on existing wells and drill 1 new well to increase production from Ebouri that will be treated with this chemical process. The study has indicated that downhole chemical injection can adequately cover the sweetening of the crude, and therefore, we anticipate that the more costly CapEx option for a full CSP will not be required. This is a positive outcome that should allow the company to access contingent resources and place these back into reserves upon completion. Subject to contracting, we plan to initiate the program in late Q1, early Q2 2025, and expect the campaign to continue throughout 2025. We will provide more detail on CapEx involvement when we present our 2025 budget and guidance. Our expected CapEx spend for 2024 on long lead items remains, as previously noted, between $30 million and $40 million. Further discussions on Blocks G and H have taken place, and we have included the signature bonuses in our 2024 CapEx forecast. On the 25th of March, 2024, we announced the finalization of documents in Equatorial Guinea related to the Venus Block P plan of development. The finalization of these agreements included a carry arrangement of the partners, Atlas and GEPetrol. This arrangement is on commercial terms of SOFR plus 7%, which at today's rates is about 12.5%. This improves our 1P economics on those previously announced, and we have included an illustration of that in our accompanying slide deck. We will now proceed with our front-end engineering design or FEED study. We anticipate the completion of the FEED will lead to an economic final investment decision or FID, which will enable the development of Venus. We are excited to proceed with our plans to develop, operate, and begin production from the discovery in Block P, offshore Equatorial Guinea over the next few years. We look forward to discussing this new area of operations in more detail once the FEED study is complete. In the first half of 2024, we have delivered or exceeded our guidance operationally and with solid financial results that have outpaced analyst expectations. We remain focused on growing production, reserves, and value for our shareholders. I would like to thank our hardworking team who continue to operate and execute our plans. Over the past two years, we have greatly diversified our portfolio, which has expanded our ability to generate operational cash flow, all while growing our cash position and remaining bank debt-free. We are well positioned to execute the projects in our enhanced portfolio and our proven track record of success these past two years should instill confidence in our future. With that, I would like to turn the call over to Ron to share our financial results. Thank you, George, and good morning, everyone. I will provide some insight into the drivers for our financial results with a focus on the key points. Let me begin by echoing George's comments about our continued success into 2024, driven by our strong operational performance. The second quarter also saw some positive impact from the Svenska acquisition, including our first lifting in Côte d'Ivoire in May. We generated $28.2 million in net income, or $0.27 per share, and around $72.5 million in adjusted EBITDAX, both significant increases over the first quarter. Let us turn to production and sales, which, along with realized pricing, drives our revenue. As George mentioned, we've met or exceeded production guidance for the past two years, with production and sales up for the second quarter, driven by incorporating the Côte d'Ivoire volumes following the closing of the acquisition. We completed the lifting in Côte d'Ivoire in May and received payment in June. Total NRI sales for the quarter increased to 19,386 barrels of oil equivalent per day, above the midpoint of our guidance, with production of 20,588 at the higher end of guidance. I'd like to reiterate that with a diversified portfolio of assets, we will have changes from quarter to quarter in the mix of sales from each of our producing areas. This change in mix impacts our realized pricing and ultimately our revenue and earnings. But if you look at the bigger picture and over the full year, you'll see the impressive growth across our expanding portfolio of producing assets. Pricing remains solid in Q2, and our hedging program has always looked to help mitigate risk and protect our commitment to shareholder return. Our current hedge positions were disclosed in the earnings release. Turning to costs. Our production costs for the second quarter of 2024 were impacted by a $50 million non-cash purchase price adjustment in Côte d'Ivoire. According to GAAP rules, inventory purchased in the acquisition was marked to market at the time of the purchase, and when the lifting occurred in May, prices had dropped, but the corresponding expense was recorded to production expense. Without this acquisition-related non-cash adjustment, VAALCO would have been below the midpoint of our Q2 production expense guidance. We believe that Côte d'Ivoire production expense on an ongoing basis will be around $3 million net per month. Our focus remains on capturing synergies and keeping our costs low to enable us to maximize margins and increase our cash flow. G&A costs were also in line with guidance, and while they rose on an absolute basis, driven by our growth, on a per barrel basis, they were virtually flat with Q1 2024. We commenced a back-office process improvement project with the implementation of a single cloud-based ERP across the whole company that will go live in Q3 2024, and should allow us to streamline processes and efficiently work across multiple offices located across the world. Non-cash DD&A costs increased quarter-over-quarter, primarily due to increased depletion costs associated with the addition of Côte d'Ivoire. Compared to the same quarter in the prior year, we saw a decrease in the absolute and per barrel DD&A costs due to lower depletable costs in Gabon, Egypt, and Canada, and partially offset by the addition of Côte d'Ivoire. Moving to taxes, and as I've previously stated, in Gabon, our foreign income taxes are settled by the government through in-kind oil liftings. Last call, we discussed that we would have a government lifting in May. In Q2, we settled $30.2 million in foreign income taxes for Gabon through the government taking their oil barrels as payment in kind. We've discussed our mark to market of the in-kind oil in the past. With the lifting in Q2, the amount of in-kind oil has been reset, so in the near term, price fluctuations will not have as significant of an impact to our tax liability until the quantity of barrels of in-kind oil begins to build back up. Tax costs in the second quarter of about $9.3 million resulted in an effective tax rate of about 25% in the quarter. This was lower than prior quarters and driven by nondeductible items such as the Svenska transaction costs, the Gabonese state lifting settling, and the bargain gain associated with the Svenska transaction. Excluding the bargain gain, the effective tax rate is 53% for the quarter. Our new projected effective tax rate over the long term, excluding discrete items, ranges 55%-60%. Turning now to the balance sheet and the cash flow statement. Unrestricted cash at the end of the second quarter was $62.9 million, which was down compared to the first quarter due to several factors. In Q2, we paid $40.2 million for the Svenska acquisition. We spent $32.5 million in cash CapEx, and returned $6.5 million through dividends to our shareholders. I'd also like to point out that we settled $30.2 million in taxes in Gabon through an in-kind oil lifting, which means the government received the cash associated with this lifting, rather than VAALCO settling it and receiving the cash proceeds as we normally would. I'd like to point out that there's some noise in the cash flow statement regarding the Svenska acquisition. We have a slide in the supplemental deck showing a waterfall to help to explain the movements. In the investing activities, you will see $40.6 million in cash received in business combination. This was cash that Svenska had on the books for prepaid or accrued liabilities, that flowed through the operating activities section that VAALCO assumed with the purchase. Last call, we discussed likely working capital movements, primarily related to Egypt. In the second quarter of 2024, we sold all Egyptian production domestically, which drove our June accounts receivable higher. Following the end of the quarter, we did receive in early July an $8 million cash payment for Egyptian accounts receivable. Additionally, EGPC has now provided written confirmation and recognized our invoice in their June payables related to the contractual backdated receivable from the merger of the PSCs of approximately $40 million. This is a major step forward and with EGPC demonstrating through March and July back payments to IOCs, and with the new oil minister prioritizing resolving the aged payable situation, we are pleased to continue to work with the Egyptian government, which has made a concentrated effort to reduce its backdated bill payables in 2024. As has been the case since the third quarter of 2018, we're carrying no bank debt and have credit facilities available to continue to build value. In Q2 2024, VAALCO paid a quarterly cash dividend of $0.0625 per common share, or $6.5 million absolute. In 2024, we have now returned almost $20 million in shareholder returns. We also announced the third dividend payment of the year, which will be paid in September. Let me now turn to guidance, where I'll give you some key highlights and updates. I want to remind you that guidance now includes the recently closed Svenska acquisition, which only affected two months for the second quarter, and the full impact will be seen in the third quarter. Also, our full guidance breakout is in the earnings release and in our supplemental slide deck on our website, with production breakout of both working interest and net revenue interest by asset area. For the total company, we are forecasting Q3 2024 production to be between 24,900 and 27,600 working interest barrels of oil equivalent per day, and between 20,300 and 22,800 NRI barrels of oil equivalent per day. This is up compared to the second quarter due to the full impact of the Svenska acquisition and due to the Gabon turnaround timing that George discussed. For the full year 2024, we are now forecasting our total company production to remain unchanged between 23,600 and 26,500 working interest barrels of oil equivalent per day, and between 18,900 and 21,400 NRI barrels of oil equivalent per day. Looking at production by asset for the full year, we are expecting natural decline in Gabon and Egypt, although the capital work program in the first half of the year in Egypt has helped mitigate some decline. In Canada, we're seeing year-over-year growth from our drilling campaign, and in Côte d'Ivoire, we're reflecting operations from May through to December in our full year numbers. For the third quarter and the full year 2024, we're assuming our sales will be more or less in line with our production. Our absolute operating costs are expected to go down compared to Q2, due to the non-cash purchase price adjustment and operating costs that drove costs higher in Q2. Normalizing for the adjustment, then adding expected quarterly running costs, this will go up for the full year due to the normal operational expenses in Côte d'Ivoire. Taking all this into consideration, we are projecting our per barrel of oil equivalent range to decrease due to the additional Côte d'Ivoire volume. We're also expecting flat to slightly lower absolute G&A, as we noted previously. Finally, looking at CapEx, our 2024 capital spend is between $115 million and $140 million as we prepare for the 2025 FPSO change out, the anticipated next drilling campaign in Gabon, and the largely completed Canadian 2024 drilling program. For the third quarter, we are expecting a range of between $32 million and $54 million for our CapEx. In closing, we are executing on our strategy and adding meaningful value. With the Svenska acquisition, we are forecasting a meaningful increase in production and sales, which should also increase our ability to generate additional adjusted EBITDAX and operational cash flow in the second half of 2024. We are very well positioned to execute and fund a robust capital program across multiple producing assets over the next several years. With that, I'll now turn the call back over to George. Thanks, Ron. We will continue to execute our strategy focused on operating efficiently, investing prudently, maximizing our asset base, and looking for accretive opportunities. As you have heard this morning, the first half of 2024 has been very profitable. We have generated $35.8 million, or $0.34 per share in net income, and almost $135 million in adjusted EBITDAX. With the closing of the Svenska acquisition at the end of April, we will see a positive impact to production, sales, OpEx per barrel of oil equivalent, operational cash flow, and adjusted EBITDAX for the second half of the year. Looking across our asset base, we are pleased with the Canadian drilling results. We are planning the drilling campaign at Etame, and we are progressing the FEED study in Equatorial Guinea and optimizing production while executing workovers in Egypt. Our entire organization is actively working to deliver sustainable growth and strong results. I believe we have gained credibility over the past 2 years, having delivered on our commitments to the market and to our shareholders, and we will continue to deliver with the exciting slate of projects that we have over the next few years. We are in an enviable financial position with no bank debt and even a stronger portfolio of producing assets with future upside potential. In addition to funding our capital program, we have remained focused on returning value to our shareholders. In Q2 2024, we returned over $6 million to our shareholders through dividends. We are on pace to deliver a further $0.25 per share annual dividend for 2024, matching what we paid out in 2023, which our current share price is a dividend yield of about 4%. As Ron discussed, our 2024 guidance has the Svenska acquisition incorporated with strong production and sales expected to continue. We are truly excited about the future, and VAALCO now has multiple producing areas and future prospects that have diversified our risk profile and our sources of income. We are confident in our ability to execute on the many projects ahead, largely because we have been highly successful over the past two years, developing and growing our assets. Our disciplined approach to maximizing value for our shareholders by delivering growth in production, reserves, and cash flow has led to outstanding results thus far, and we believe that we will carry that momentum into the remainder of 2024 and beyond. Thank you, and with that operator, we are ready to take questions. Yes, thank you. We will now begin the question and answer session. To ask a question, you may press star, then one on your telephone keypad. If you're using a speakerphone, please pick up your handset before pressing the keys. If any time your question has been addressed and you'd like to withdraw it, please press star then two. During the question and answer session, we ask that you limit yourself to questions to one and a follow-up. You can always reenter the queue for additional questions. At this time, we will pause momentarily to assemble the roster. The first question comes from Stephane Foucaud with Auctus Advisors. Hi, guys. Thanks for taking my question. I've got two. The first one is about the receivable in Egypt, and particularly with the agreement that has been signed. Does this $40-$50 million that has been agreed, is it already on the balance sheet at the end of June, or would that be something that would be added by when the end of September comes in? That was my first question. My second question is around the exploration program in Canada in H2. What sort of volume million barrel could be the risk potentially by this program? Just to have sort of an idea of the order of magnitude. Thank you. Thanks, Stephane. I'll leave Ron to answer the first question, and once he's done that, I'll come back on the second one. Hi. Thanks, George. Stephane, yeah, in relation to the Egyptian receivable, that's the backdated contractual receivable that was basically there for when we took over TransGlobe. So it was booked prior to us purchasing TransGlobe, and we've been looking for resolution for that really since day one in October 2022. It's been a long path to take, but we've managed to get to the position now where we've got the documentation, we've got an agreement through all of the departments in EGPC, and effectively, we're in the signing process in relation to each of those areas now. But the invoice has actually been cut. The values have been agreed, and they have recognized and given us written confirmation that the net receivable is now sitting there at the end of June 2024 on their payables too. So it's like anything else, it has to be on their payables register before there's any chance of you getting any payment on it at all. And I'm glad to see we've succeeded on that, on that part. Sorry, I meant is that already in the balance sheet of VAALCO as receivable or not? That's what I meant, rather than EGPC. Ron, do you hear that? Okay, we may have lost Ron, but I'll answer the second question, Stephane. So with the exploration well in the southern acreage in Canada, what we're trying to do is about a year or so ago, some of the well performance came below the type curve, and we lost some reserves there, although we did gain in the north. And what we're looking to do is reestablish those reserves with this exploration well. Roughly, I think it's between 8 to 12 million barrels we're looking to try and reestablish, and that would open a play for further drilling on the southern acreage. We're quite encouraged by looking at this well that we hope to spud in September, and that will further enhance the programs going into 2025. Great. That's wonderful. Thanks, George. Thank you. The next question comes from Chris Wheaton with Stifel. Thank you. George, good afternoon. In Ron's absence, I think that probably I'll ask you a slightly different question, which was, Equatorial Guinea, it's good to see progress there for the second half, progress towards FID. Can you update on the timing after that, though? At what point do you see moving towards actual first construction and therefore first oil? And also, if I need to update the cost of the development or likely cost of the development, given that we still seem to be in an inflationary environment for offshore services at the moment. Okay. As I think I've mentioned before, what we did initially about 18 months ago was put together the plan of development, and that was fully costed. That was fully costed with 3 wells, plus a CapEx spend for a MOPU, and it was somewhere around about a gross spend of about $280 million. The plan going through the FEED study is to try and reduce that CapEx and swap CapEx for OpEx, because it's much more tax efficient, given the short tenure of this development. So there is a little bit of adjustment that we're trying to achieve through this FEED study to reduce the CapEx down to around about $160 million level gross and increase the OpEx position through the lease of the MOPU. Now, of course, there are some inflationary pressures still on services. However, part of the output from the FEED study will be looking at particularly opportunities where we can have some of the older jackup rigs converted into MOPU and go through the lease arrangements. And as you're aware, there are quite a few of those units available here in the United States. So right now, I wouldn't be advising that we need to increase any of the cost profile. I'm kind of hoping that we get to a point where for Equatorial Guinea, we get to FID, and we get into a planned structure that may allow us to piggyback on the Gabon campaign, and allow Equatorial Guinea to come in on the back of that, which would be mid- to late 2026 for drilling. Which would then allow us to look at first oil sometime in 2027. Brilliant. That's really helpful. Thank you, George. I'll leave it there. Thank you. Thank you. The next question comes from Jeff Robertson with Water Tower Research. Thank you. George, in Côte d'Ivoire, do you have any additional detail with the operator on the timeline for the FPSO change-out from what you've provided in the past? While the FPSO is off station, will there be any significant operating costs in CI, or will all the costs incurred be in the capital cost lines? Yeah, that's a good question, Jeff. I mean, obviously, the operator is having those discussions right now. At the moment, we have no change to what we initiated, which was a Q1 shutdown in 2025 for the vessel to leave station. We do not anticipate any significant OpEx. In fact, we're looking at retaining those operating costs being capitalized during the period of 2025. Those discussions are still ongoing because we'll retain those as part of the project cost. But obviously, there are ongoing costs for retaining the presence in CDI, but that won't be significant. The main focus will be on the FPSO refurbishment and the timeline to get it, get it back on station, which will, you know, go through into 2026. So, as I said in my commentary earlier, when we come to finalize that position with the operator and finalize our position and timing of the 2025 drilling program, you know, at that point later this year, when we come to give budget and guidance for 2025, we can be a lot more specific and detailed on. And we will provide that detailed project plan slide to let everyone see when we plan when it's planned for the vessel to leave, and when it's planned for it to come back, where it's going, and the cost structures around that. And that will be linked to, obviously, the 2025 capital program for Gabon as well. So, it's gonna be probably towards the end of this year, we'll be able to give more detail there. But when we look at our ability to execute and fund that, you know, our confidence levels remain extremely high. As Ron mentioned, you know, we are debt-free, but we do have debt lines available to, and also cash on the balance sheet to more than cover us through that period. In Egypt, Ron talked about progress with aged payables with EGPC. Can you provide any color on discussions around being able to sell oil into the export market as opposed to the domestic market? Yeah, a little bit. I mean, as you can tell, you know, we're quite a small management team, so we're actually in different parts of the planet right now. The reason we do that is to make sure we can always have a senior management team member meeting with various governments. Thor, our COO, is currently meeting with the minister in Egypt as we speak, in Alexandria. So I'm waiting for the outcome of that discussion. We have initiated in detail what our investment plans are for Egypt, and I've mentioned that with the potential of a 15-well drilling program. But we're looking to see how we optimize both the commitment that the minister has made to tackle the aged receivables on EGPC. He made that statement publicly. We've seen them looking to quarterly pay down 20% of aged balances, which is encouraging, but as you're aware, you know, it's not sufficient to make sure we can charge ahead with an accelerated investment, and we're looking to see that position improve. At the moment, we don't and we have not forecast for export cargoes, and we don't see that possibility at the moment because of the position with the type of crude we have. Initially, they could not refine that crude, but that's now not the case. They are refining the Ras Gharib crude in-country. So for the rest of this year, we're looking at domestic sales. But in saying that, you know, we're still encouraged with the profiles and opportunities that we see in Egypt. We just need to see just a little bit of, as I think I said at one point, to move it from a great deal to a compelling one. Thank you. George, I was texting with Ron after he got disconnected early, and he confirmed that the receivable was on the books for VAALCO before now. So, for Stephane's question, yes, the receivable was already booked. And I think Ron's trying to get back in. I'm not sure if he's actually made it back in. Yeah. Hi. Hi, all. I'm often get back on. The curse of modern travel and communications, but back online. Okay, great. Thank you. The next question comes from Charlie Sharp with Canaccord. Yes, good morning, good afternoon, wherever you are, gentlemen. Thanks for the presentation. Very helpful. I just wanted to clarify, if I may, the wells that you're planning to drill in Gabon next year, and when you might be able to provide some guidance to us on what sort of production you might expect from those additional wells. Thank you. No problem, Charlie. We kind of give a very brief overview of the wells we're planning. At the moment, we've got seven wells firm. We've also got further five wells contingent that we will look or may include in the program. With regard to volumes and guidance, that's probably gonna come out in our November call as we start to give more guidance into 2025. But they effectively are a mixture of step-out wells and one or two an exploration well, and then the redevelopment around Ebouri, which is the key pickup. On a volumetric basis, what we're targeting is probably somewhere, well north of, 6-8 million barrels of additional reserves coming in through the initial program, excluding the position on the gas well. That's a risk position, I'm kind of hopeful that we'll see a little bit of improvement on that through Ebouri, given what we lost on reserves that went to contingent resource. So there may be a little bit of pickup on that, but we'll continue to study that. But that's more likely to be in November before we can land on the exact pro well sequencing and exactly what the IP rates we're forecasting and the final reserve positions we're targeting. That's very helpful. Thanks. And just finally, one for Ron, if he's still on. I think the operating costs for full year 2024, you, you've indicated, are higher than you had previously. I just wanted to be sure that I understood if that was really related to the Svenska acquisition, or was there something else that I was missing there? Yeah, just in my script, I think there, Charlie, I mentioned that Q1 and Q2, you see production costs have gone up. And that's really in relation to the Svenska acquisition because they had inventory, crude oil on the FPSO on the thirtieth of April, when we purchased the company. So that effectively means that the, that crude oil is marked to market. It's basically valued at market price. And then, of course, we produced, and then we sold in May. And so when we do that, and from an accounting point of view, you roll through that mark-to-market cost at the market price. So that's really bumped our costs up by about $15 million in the quarter, and it will obviously, it's non-recurring and it's non-cash. You will not see it there in each of the other quarters. I also mentioned in my opening comments that we would typically see that net cost, that production cost in Côte d'Ivoire would run about $3 million per month, $9 million net. Very helpful. Thank you. Thank you. Thank you. And the next question comes from Bill Dezellem with Tieton Capital Management. Thank you. George, would you please circle back to your comments about the H2S wells and what it is that you are going to be doing there, and the timeline that you anticipate those may be able to be turned back into production? Yeah, no problem, Bill. I mean, we've, as I mentioned, completed the study where we can now sweeten that crude through downhole chemical injection rather than a more costly mechanical process. So that is very good news. And that's based on the existing modeling structure we have. Obviously, as we come into the campaign and we start to add more wells in Ebouri into production, you know, we'll be able to revise and update that model with more subsurface data that's coming in through the production profile. Right now, these wells, from a sequencing standpoint, are. We're planning them at the back end of the campaign, and that's primarily due to being able to get the quality of completion equipment we need for several treatment downhole. So those lead times are quite extensive, up to 12 months and beyond. So they'll be at the back end of the program. Of course, given that they are reasonably prolific wells, if we can pull those forward by the equipment arriving earlier, then we will certainly do that and do that work on the Ebouri platform as early as possible. But as I say, at the moment, they're at the back end of the program to allow for LLIs to be delivered on time. Would you please remind us what the total shut-in production is on those H2S wells? Well, when they were shut in, one of them is actually still in production at the moment, the Ebouri 2H, and that's the one we've been using as the test piece for the sweetening program for downhole chemicals. But it was shut in, I think, and this goes back to 2014, so I'd have to check my numbers, but I think it was about 3,000-4,000 barrels a day that got shut in. It is just one well now that's shut in due to H2S? It's only one well that's in production right now. The other wells are shut in. And what we're planning to do is, we will do some work on the existing well to make it more efficient when it comes to the downhole chemical injection, make sure the line is fully functioning, and that will be an enhancement to that particular well's production. We will then also do a sidetrack on the 3, what was the 3H well, and move that to a more favorable location within the reservoir. And then we've got to rerun the completion on 4H, which to give it, and that's one of the reasons that we need that specialized equipment. So those are the three, the three. 1 redrill, 1 sidetrack redrill, and 2 workovers that are planned to get that Ebouri production back up to optimum levels. And then you will be drilling additional wells at Ebouri, also to enhance the production there beyond bringing those wells back online through the recompletions. Is that correct? Am I understanding that correctly? That there are potential additional Ebouri wells in the contingent program, but we need to get the first these three wells up and running first, and that will determine where we go next. Understood. Thank you. I appreciate the time, and congratulations on a solid quarter. Thanks, Bill. George, I was just gonna maybe add a little bit of color to Bill there as well. In relation to it being shut in, you know, with Bill being a long-term shareholder, those wells were shut in when VAALCO had a much smaller working interest in those reserves. Now we're bringing them back on, you know, we're bringing them back on at nearly 60% working interest. So kind of fortuitous in that way, too, that we shut in with that position, and hopefully, we'll now be able to flow it with a greater working interest coming into VAALCO. Actually, Ron, that's a great point, which I had overlooked. So with that in mind, what is the—if the wells were to flow at the flow rate that they had at the time they were shut in, but taking into account your now greater working interest, what is the total production that you would expect from those wells? Yeah, I mean, what I was saying before, Bill, in the 4,000-6,000 barrel range was what I was giving you on our position. So that I had, I'd already factored that in. So from a working interest perspective, but yeah, I mean, the key here for me is to, is getting this field back in production with multiple drainage points, and then having that history match opportunity to study that against the existing model, see where our model inaccuracies lie, because, you know, no model is perfect, and what does that give us for additional opportunities for drilling thereafter? That's where sequencing, you know, we wouldn't have enough time wherever we place the wells, but the earlier we can do the Ebouri program, for me, the better, because there may be some additional contingent opportunities there at the end of the program. Great. Thank you both for that. I appreciate it. Thank you. The next question is from Stephane Foucaud with Auctus Advisors. Yes, thank you again. 2 quick follow-on clarifications. The first one is about Egypt. You talked about the fact that you're looking for a drilling rig for the second half of the year. Is that the only condition to go back to drilling? Because I had in mind that at some point that you would need to have an export cargo, which I understand is not required anymore, but maybe there are some other things like payment from Egypt or so forth, that would be other condition to go back to drilling. So confirmation would be great. And second, for Ron, the $116 million of other current liabilities is a big jump compared to, I think, last time. Is that purely related to the Côte d'Ivoire acquisition, or is there something that's beyond the increase? Thank you. Okay, I'll jump on to the Egypt one. Yeah, you're correct, and I think, as I said previously, we're looking for some kind of pickup to make sure that the drilling program in Egypt goes from, you know, extremely economic and exciting to compelling. And anything that becomes compelling, we execute immediately. There is still the condition of the drilling rig. We need to make sure we can get the right rig supplier that works for the types of wells and for the economics that we do in Egypt. We've got that identified. We're having discussions with that right now, so but the rig is not yet secured. And so, yeah, there is a mix of- We were looking for export cargoes, as I explained in the previous answer, but the export cargoes are probably not available given that the crude can now be refined in Egypt. So we're looking to see how quickly these investment profiles are returned to the existing position we get, and hopefully we'll get some positive feedback from Thor's visit to the minister today, and see how we can not just execute this program, but enhance and accelerate our investment positions inside Egypt, because the opportunities are there, and we'd be very keen to take them up. So to answer your question, yes, we've no longer said we must have an export cargo because we understand the changes in the profile and country. But we are looking to see how, as we invest this money, how it's going to be returned. I'll leave Ron to answer the next one. Yeah, no problem, George, Stephane. The increase in accrued liabilities that are up to 116, if I picked your question up correctly, yes. Predominantly, that is in relation to, obviously, the Svenska transaction coming in. What I would give some color to that, I mean, obviously, the breakdown will be in our 10-Q when it comes out tonight. And when you look at that, there's probably about half of it is every period, so it's turning over, and about half of it is probably, you know, more of a long-term item. It's certainly not going into next year, but we certainly would not look to move in Q2. Sorry, Q3. Great. Thank you very much. Thank you. This concludes our question and answer session. I would like to turn the conference back over to George Maxwell for any closing comments. Thank you very much, operator. Thank you for everyone that attended today's conference call and listened to our activities and operations for Q2. We've had another solid quarter. Well, as you know, we're halfway through Q3. We've got a lot of activities ongoing for the rest of 2024. I think with the acquisitions and the de-risk profile we have now, when you look at the activities that we're planning on each of our producing assets and non-producing assets, we have a number of organic catalysts that will excite both the market and excite both our staff and our hardworking staff to get these things executed for us. So, we've got a lot of work to do. We've got a lot of things upcoming, but we've achieved part of our objective in creating a profile and a portfolio that gives this company, you know, decades of longevity, and that's very exciting for us. So I'd like to thank everyone for their attendance, and we look forward to talking to you again in November for Q3. Thank you. Thank you. The conference has now concluded. Thank you for attending today's presentation. You may now disconnect your lines.