EGY - NYSE

Ladies and gentlemen, thank you for standing by, and welcome to the VAALCO Energy Third Quarter 2024 Conference Call. [Operator Instructions]. This conference is being recorded and a replay will be made available on the company's website following the call. I would now like to turn the conference over to Chris Delange, Investor Relations Co-ordinator. Please go ahead.

Thank you, operator, and welcome to VAALCO Energy's third quarter 2024 conference call. After I cover the forward-looking statements, George Maxwell, our CEO, will review key highlights of the third 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 section, we ask you limit your questions to one and a follow-up. You can always re-enter the queue with additional questions. I would 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, a presentation posted on our website and in the reports, we file with the SEC, including our Form 10-K. Please note that this conference call is being recorded. Let me turn the call over to George.

Thank you, Chris. Good morning, everyone, and welcome to our Q3, 2024 earnings conference call. For the past 2 years, we have met or exceeded our quarterly production guidance leading to consistently strong operational and financial results, including net income, adjusted EBITDAX and cash flow generation. Maintaining operational excellence and consistent production across our portfolio is essential to expanding adjusted EBITDAX, which will enable us to fund organic growth initiatives and position us as a larger player in the industry. We are executing at a high level and continue to deliver results in line with or above our guidance. In the Q3, we experienced quarterly results of fully incorporated the Svenska acquisition, which occurred at the end of April. For Q3, we increased our adjusted EBITDAX to $92.8 million and through the first 9 months of 2024, have delivered $227 million of adjusted EBITDAX. We sustained our commitment to returning cash to shareholders in Q3 2024 through our regular quarterly dividend and have also announced the dividend for Q4. 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 Cote d'ivoire. We swiftly and efficiently completed the Svenska acquisition in April 2024, securing a valuable asset with reserves surpassing our initial expectations, all at a highly attractive price. Based on the results of our third-party reserves engineers, we have SEC net proved reserves as of year-end 2023 of 16.9 million barrels of oil equivalent with 93% being 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. In Q3, we had 3 shared listings in Cote d'ivoire driving our total VAALCO sales 20% higher overall versus Q2. The timing of the FPSO shutdown and sale away remains scheduled for Q1 with these plans now becoming more firm as we move closer to the shutdown targeted dates. We are collaborating with our operator at Cote d'ivoire and will provide additional information on the Baobab FPSO project and future drilling plans when we issue our 2025 guidance in Q1. Turning to Canada, we successfully drilled 4 wells in the Q1 of 2024, completed these wells in March April, and brought the wells online. As a reminder, we drilled longer laterals to improve the economics of the program and all 4 wells are 2.75-mile laterals. We are very pleased with the production results from our drilling program and as you can see that in the production mix in Canada. In Q1, our Canadian production was about 60% liquids and in Q2 and Q3, our Canadian production was approximately 75% liquids with new wells coming online with a lower COR. 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 are in line with our type curve and we are optimistic about the future drilling potential in Canada. As I mentioned in the last call, we are also currently drilling and exploration appraisal well in the Southern Acreage, for which we hope to have results prior to year-end. 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, our focus in 2024 has been on high rate of return capital workover projects to help to mitigate decline. As you have seen in the earnings release, we had three recompletions in the third quarter. In addition to the successful workovers, I am proud of a major milestone that we accomplished in Egypt. We have gone over 2.9 million-man hours without the lost time incident this year. This is a testament to our commitment to safety, training and dedication of all of our people in the operation. As I mentioned in the last call, we have a 10 to 15 well program and in the fourth quarter, we have contracted the rig and will commence at least two of these wells this year. We expect to drill and complete at least a single well prior to year-end and complete the drilling of the second well. However, the second well is not expected to provide production until January 2025. We continue to engage with the Ministry and EGPC on the backdated receivables issue. We are balancing our working capital position between a limited, but necessary drilling program with the indications from EGPC of a program to address the backdated position. We also plan to fracture one of our wells in South Ghazalat and Western Desert in the fourth quarter. Results will be available in Q1 2025 and if encouraging, will have positive impact on our opportunities in this area for the future. Moving to Gabon. Given that we haven't drilled a well in Gabon for over a year, we are pleased with the positive overall production results with strong production uptime and improved defined curves on the wells. The FSO and field reconfiguration projects in 2022 have allowed us to minimize downtime, capture efficiency, and reduce overall OpEx. Currently, despite not initiating the planned drilling in 2024, our production guidance remains firm for the year, which is a testament to the quality of the Itami field and how the reservoir has positively responded to the reconfiguration. Looking ahead to 2025, as I stated last quarter, we initiated a bidding process for the 2025 drilling program. We are almost complete on the bid evaluation and contractor selection. It is intended that, we will announce results of this evaluation in the very near future. However, I can confirm that the timing of this project remains on schedule for mid-2025. Since our last communication, we have continued to review the well sequencing of the program and the testing of the Ebouri shut-in wells. When finalized, this will provide greater analysis for the equipment selection required for the Ebouri wells and the timing of the wells within the program sequence. The other planned wells, two infill wells within Itami, a gas well in SENT and an exploration well remain in the plan. This is in addition to the potential of a small workover program at Itami. We will provide more detail on CapEx and volumes when we present our 2025 budget and guidance. Our expected CapEx spend for 2024 on long lead items remains as politely noted between $30 million, $40 million. Regarding Block G and H recently, the government of Gabon signed these PSCs for exploration blocks with a request to be renamed Nielsi Marine and Goduma Regine. This follows the technical provisional award announced in October 2021 granting Balco a 37.5% non-operating working interest with BW Energy as operator, also holding a 37.5% working interest and Panoro Energy as a non-operating joint owner with a 25% working interest. Given the proximity of these blocks to the prolific producing fields of Itami and Disciplin, we are excited to begin working with our partners to begin examining the possibilities for these blocks. In Equatorial Guinea, in March 2024, we announced the finalization of the documents related to the Venus Block P plan of development. This summer, we began our front-end engineering design or FEED study. We anticipate the completion of the FEED study will lead to an economic final investment decision or FID which will enable the development of Venus. We are very excited to proceed with our plans to develop, operate and begin producing 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. Throughout 2024, we have delivered on our exceeded our guidance operationally and our solid financial results continue to outpace 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 2 years, we have significantly diversified our portfolio, enhancing our capacity to generate operational cash flow and adjusted EBITDAX, return capital to shareholders, grow our cash reserves for maintaining a bank debt free position. We are well positioned to execute the projects in our enhanced portfolio and our proven track record of success these past 2 years, we do still confidence for our future. With that, I would like to turn the call over to Ron to share our financial results.

Thank you, George. And once again, good morning. 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 through the first three quarters of 2024, driven by a strong operational performance. In the third quarter, we saw the positive impact from the Svenska acquisition, including three shade liftings in Cote d'Ivoire. We generated $11 million in net income of $0.10 per share and $92.8 million in adjusted EBITDAX. During the Q3 of 2024, we have now generated $227 million in adjusted EBITDAX, which is over $40 million more than we generated in 1st 9 months of 2023. Let's turn to production and sales, which along with realized pricing drives our revenue. As George mentioned, we have met or exceeded production guidance for the past two years with production sales up in the third quarter, driven by a full quarter of results from Cote D'ivoire. We completed three listings in Cote D'ivoire in Q3, driving our sales growth. Total NRI sales for the quarter increased to 23,198 barrels of oil equivalent per day, at the high-end of our guidance with NRI production of 21,416 barrels of oil equivalent per day, the midpoint 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 a full year, you will see impressive growth across our expanding portfolio of producing assets. Pricing remains stable in Q3 and our hedging program has always looked to help to 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 third quarter of 2024 were at the low end of guidance both on an absolute basis on a per barrel basis. Absolute expense was $42.3 million and on a per barrel basis was $19.80. I want to remind you that, the 33% decrease compared to Q2 was driven by the fact that, Q2 included a $15 million non-cash purchase price adjustment in Cote D'ivoire for the inventory that was purchased. Our focus remains in 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 they fell quarter-over-quarter. We completed our back-office process improvement project with the implementation of a single cloud-based ERP across the whole company and went live in Q3 2024. This should allow us to streamline processes and efficiently work across our multiple geographies located around the world. The project was completed on time and on budget and is a testament to the effort and dedication of the entire team. Non-cash DD&A costs increased quarter-over-quarter, primarily due to increased depletion costs associated with the addition of Cote d'Ivoire. Valuation of Cote d'Ivoire is comprised primarily on the proven, developed and producing reserves, which assumed an estimated disconnection schedule occurring in Q1 2025 in the CPR, thereby depletion expense is accelerated due to the higher listings than forecast in the reserve report. Moving to taxes, as I previously stated in Devon, our foreign equity taxes are settled by the government through in-kind oil listings. In Q2, we accrued $30.2 million in foreign income taxes for Devon through the government taking our oil barrels as payment in kind. We forecast that GOC will lift their entitled barrels early in Q1, 2025 and there will be no further Devon state list this calendar year. Third quarter tax was impacted by nondeductible items such as the spreads per transaction costs and the change in market value of tax barrels due to Devon State mark to market at quarter end. Tax costs in the second quarter of about $32.6 million resulted in an effective tax rate of about 75% in the quarter impacted by non-recurring discrete items. This is higher than prior quarters, but offset by the 25% effective rate in Q2. As you can see, over the long term, excluding discrete items, our guided effective tax range of 55% to 60% is a good forecast. Coming now to the balance sheet and cash flow statement. The unrestricted cash at the end of the third quarter grew to $89.1 million driven by strong sales. In Q3, we spent $12.4 million in cash CapEx and returned $6.5 million through dividends to our shareholders. I'd like to point out that there is some noise in the cash flow statement regarding the Swedes acquisition. We have a slide in the supplemental deck showing a waterfall to help to explain the movements. On the investing activities, you will see $40.6 million in cash received in business combination. This was cash that Svenska had on the books to piece seller accrued liabilities that flowed through the operating activities section that VAALCO achieved with the purchase. Last call, we discussed likely working capital movements, primarily related to Egypt. In the Q3 of 2024, we sold all Egyptian production domestically, which drove our September accounts receivable higher. In early July, an $8 million cash payment of Egyptian receivables was received. Further to that, we also received $5 million worth in equivalent Egyptian pounds in August September versus $10.6 million in the whole of the preceding several months. We continue to utilize offsets and collectively the payments plus the offsets amounted to approximately $29 million for the quarter. Additionally, EGPC has now provided written confirmation and recognized our invoice in the June payables related to the contractual backdated receivable from the management of the PSCs of approximately $40 million. This is a major step forward and with EGPC demonstrating through March, July back payments to IOCs and with the new Oil Minister prioritizing resolving the age table situation. We are pleased to continue to work with the Egyptian government, which has made a concerted effort to reduce its backdated build tables in 2024. As has been the case since the Q3 of 2018, we are acquiring no bank debt and our credit facilities available to continue to build value. In Q3 2024, Alco paid quarterly cash dividend of $0.0625 per common share for $6.5 million. In 2024, we have now returned over $25 million in shareholder return. We also announced the fourth dividend payment of the year, which will be paid in December. Let me now turn to guidance, where I will give you some key highlights and updates. Our full guidance breakout is in the earnings release and in our supplemental slide deck on our website with the production breakout of both working interest and revenue interest by asset area. For the total company, we are forecasting Q4 2024 production to be between 23,800 and 26,700 working interest barrels of oil equivalent per day and between 19,400 and 22,000 NRI barrels of oil equivalent per day. This is down only slightly, compared to the third quarter due to natural decline. For the full year 2024, we are tightening the range and now forecasting our total company production to be between 24,100 and 25,400 working interest barrels of oil equivalent per day and between 19,300 and 20,600 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 workover program in Egypt has helped to mitigate some decline. In Canada, we are seeing year-over-year growth from our drilling campaign and Cote D'ivoire, we are reflecting operations from May through December in our full year numbers. For the fourth quarter, we are forecasting our sales will be more or less in line with our production, but down compared to Q3 due to less offshore liftings. We expect our absolute operating costs to be only slightly higher compared to Q3. But because we are expecting fewer liftings, we are projecting our per barrel oil equivalent range to increase slightly with a range between $17.50 and $22.50 per barrel of oil equivalent. We are also expecting flat to slightly lower absolute G&A. Finally, looking at CapEx. Our 2024 capital spend is between $110 million and $130 million, as we prepare for the 2025 FPSO change out in Cote d'Ivoire. The anticipated next drilling campaign in Gabon and some drilling in Egypt and Canada that could impact 2025 Q1 production. For the fourth quarter, we are expecting a range of between $40 million and $60 million for our CapEx, which includes a fifth well drilled in the southern acreage of our Canadian asset and FPSO marine disconnection and long lead item contracts. In closing, we are executing our strategy and adding meaningful value. With Svenska to acquisition, we have delivered a meaningful increase in production and sales, which has also increased our ability to generate additional adjusted EBITDAX and operational cash flow. We are well-positioned to execute and fund the robust organic capital program across our diversified assets over the next several years. With that, I will now turn the call back over to George.

Thanks, Ron. We will continue to execute our strategy focused on operating efficiency, investing prudently, maximizing our asset base and looking for accretive opportunities. As you have heard this morning, the first 9 months of 2024 has been very profitable. We have generated $46.8 million or $0.45 per share in net income and almost $227 million in adjusted EBITDAX. With the closing of the Svenska acquisition at the end of April, we have seen a positive impact to production, sales, OpEx per BOE, operational cash flow and adjusted EBITDAX. Looking across our closer asset base, we are pleased with the Canadian drilling results. We are planning the drilling campaign at Itami, working with the operator in Cote d'ivoire on the FPSO refurbishment and development drilling program in 2025 and 2026. We are progressing the FEED study in Equatorial Guinea and optimizing production while executing a capital and expense drilling project 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 we have over the next few years. We're in an enviable financial position with no bank debt and an even stronger portfolio of producing assets with future upside potential. In addition to funding our capital programs, we have remained focused on returning value to our shareholders. In Q3, 2024, we returned over $6 million to our shareholders through dividends. We are on pace to deliver another $0.25 per share annual dividend for 2024, what we paid out in 2023 with our current share price as a yield of around 4%. We will continue to finalize our projects and timing for 2025 on the forward guidance and expectations in the Q1 of 2025. 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 2 years developing and growing our assets. Our disciplined approach to maximizing value for our shareholders by delivering growth in production, reserve, and cash flow has led to expanding results thus far. And we believe that we will carry that momentum into 2025 and beyond. Thank you. And with that, operator, we are ready to take questions.

We will now begin the question and answer session. [Operator Instructions]. And our first question here will come from Jeff Robertson with Water Tower Research. Please go ahead.

Thank you. Good morning. George in Gabon, where do you see the natural production decline going in 2025, since it's been, I guess a couple of year and a half since your last well completion?

Thank you for that, Jeff. I mean, I think as we pointed out in the call, earlier today, we've actually seen some terrific improvements in reservoir performance and a big reduction in decline for a couple of reasons. One reason is obviously with the reconfiguration, we've considerably reduced the back pressure in the field and we've seen improved reservoir performance in that position. The second, again as a result of the reconfiguration, we've seen hugely reduced downtime down to 3% for planned preventative maintenance. So, when we look into 2025, as I mentioned, due to start the campaign around about May or June 2025 and that's mainly due to rig availability. That's the earliest that the rig would be available for us. I still see a decline probably hitting between 7% and 9%. We do have some planned maintenance in Q1, which we'll do ahead of the drilling campaign, but I still think what we're seeing from the performance of the reservoir is particularly encouraging.

Will reducing the back pressure and the performance gain from that have an impact on how you book reserves there?

That's something we're looking at. Actually, I'm having a meeting on that next week. That's something we are considering to look at with the performance of the reservoir, particularly through 2023 and 2024, are we underestimating the size of the tank or are we over underestimating the recovery factor? So, that's a piece of work that we will have completed in time for the CPR report will be issued in January.

And then, if I can squeeze one more in lastly. On the drilling campaign, if you start sometime late in second quarter, I guess based on how you sequence the wells, would you anticipate having some production contribution from that program in the back half of 2025 or would it more be weighted to 2026?

No. We'll definitely start with production wells. The key debate we're having right now is, whether we can start on the Ebouri side of the campaign or whether we're starting on the Itami side of the campaign. And that's really down to the continuous testing and evaluation particularly around the Ebouri 4H for the H2S concentration and what types of materials we need in order for those completions and also the side track -- sorry, the step inflow wells in Itami. Now when it comes to the Itami inflow wells, I think we're good to go on those all day long. The kit will be ready on time. So, it's really just a question between how many rig moves we want to take into the program, between the infill wells at Itami and the opportunity to rehabilitate restart at Ebouri. But it definitely will be production wells at the front of the sequence.

And our next question will come from Chris Wheaton with Stifel. Please go ahead.

Thank you. George, Ron, good afternoon, good morning. A question, George, to you first on Cote D'ivoire. When do you think we can expect a little bit more clarity on what the timing and Viking spend is going to be around both the FPSO restart, whenever that happens, which I see from recent presentation on your website, looks like it's going to be sometime 4Q next year. And then obviously, an ongoing drilling campaign, which is going to be spending money, hopefully, generating good returns doing that. So, I wonder when you could talk about when we're likely to get that timing because that seems to be the sort of probably the biggest swing factors in terms of your likely reported performance in calendar '25?

Yes and no. I mean, I think we've confirmed already that we don't see any change in the sale away time for the FPSO. So, we've confirmed in discussions with the operator that the Q1 disconnection in Seaway is still what will happen with the FPSO. The contracting basis for that to go to dry dock and the disconnection and the contracts around that are all being placed as we speak. When we look at some of the capital spend you've seen come through this year, it relates not only to the MV10 reconfiguration, but also relates to the '25, '26 or probably '26 is my fair update drilling campaign. So, we're already spending CapEx on that right now. When we get to look at the total overall project and the project timelines, I would expect to be in a position late this year or early next year to be able to give a detailed project breakdown with timelines and costings. Obviously, we have internal costings right now. One thing I'll say with a great degree of confidence to everyone right now is we are more than adequately funded to carry out the campaigns that we've already indicated to the market, which includes Egypt and Gabon and Cote d'ivoire. So, there is no issue of being able to fund these campaigns, it's all about the timing. We haven't had confirmed timing and project schedules as yet from the operator, but as soon as we have those and we do not expect those to deviate significantly from the estimates we're currently carrying, we will certainly make an announcement around that. But it certainly will be no later than early Q1 next year.

Okay. That's great. Thank you. Two questions for Ron, if I may. Firstly, working capital. Interestingly, every quarter this year has been seen a working capital outflow, which is quite unusual. Even if you back out the $15 million of Cote D'ivoire receivables build, you still had working capital outflow this quarter. Is there time that's reversing in 4Q? Because obviously, that's been quite a drag on your free cash flow generation so far this year. Another question on depreciation. Forgive me, I didn't quite understand the answer or the commentary you gave on the higher DD&A because I would have thought Cote d'ivoire is lower unit DD&A than your average. And therefore, if you've got more Cote d'ivoire barrels, you should have lower unit DD&A, but unit DD and A was up sequentially. So, I was trying to sort of that didn't seem logical to me. Could you perhaps explain why I'm going wrong there? Thank you.

No problem. Chris, let me handle that. First of all, on the working capital, I think what you've got you're right in removing that CDI receivable, which was paid in early October. During the year, there's been a number of things. As you know, we've been out of the drilling campaign really, Canada, we had the 4 well campaign in the Q1. Since then, obviously, our AP and our CapEx accruals have reduced considerably, and they will ramp up again in 2025 when we go into the next campaigns. Outside of that, we bought our Egyptian receivables. That has trended up this year. I think year to date, we're up about 19 million since December. It's trending about 6 stroke 7 million per quarter, the differentiation between what we're selling at present pricing and what we're collecting and/or using as offsets. Obviously, with Ebouri Coast coming in too, we've got a little bit more oil in the tank with two FPSOs as well. So, our inventory is a little bit higher. And then in Q2, you had some one-off events that we talked about, we were DMO annual payment we gave on, which is cost recoverable. We'll have our DMO discount against the pricing in CDI in Q4. So, you do have these one-off events that do swing things too. So, nothing more than that, Chris. It does look strange, but you will note as well in our cash flow and we did talk about the working capital noise with the waterfalls chart that we got cash with the Svenska business and we had to settle a number of liabilities that were seller led liabilities that we settled post year end too. So, all of those factors are driving the working capital outflows in any to those quarters. Moving on to DD&A, it's quite simple, Chris, on this one. Although the operating cost per barrel is lower in Ebouri Coast and in some areas, when we valued the acquisition, when we put together the purchase price around that $40 million that we paid for it, obviously, a large proportion of the predominant proportion of that valuation goes into the proven developed producing reserves. And those proven developed producing reserves are actually only going through until it comes off station. Otherwise, when the disconnect happens, which was obviously targeted for Q1 2025. So, you've got that situation where you've got a large portion of the valuation being effectively, amortized and depreciated through until January 2025. Now I do think, as we go through Q4, you know that, we'll get truth up on the PDP as we go into 2025, because essentially, we'll have most of our PDP amortizing gone before the end of the year. But that's why the DD&A component, is so high and made exacerbated by the fact that, we have three listings in Q3 versus one listed in Q2 for CDI.

Right. That last answer is very helpful, Ron, because I was using the 2P reserves, not GDP reserves as the denominator in that unit DD&A equation. So that explains why those numbers don't match up.

And our next question will come from Charlie Sharp with Canaccord. Please go ahead.

Yes. Good morning, gentlemen. Thank you very much for taking my call. Just really wanted to return, if I may, to Gabon and the drilling program. And I think you indicated that, that may start sort of mid Q2. It has slid a little bit. I think you also indicated that, that was rig related. I just wanted to chase up whether that is because the rigs just aren't available locally, or is that pressure on rig rates? And can you give us sort of ballpark figure of what each of the wells would cost to drill? And then, the final bit of that is of the seven well drilling program, I think you've indicated that some of those are work cover wells. How many actual new wells will there be in that 7 well program?

Okay. Let me take each section. So, there's no pressure or no issue around rate base. When we put the LOIs and tenders out there, sorry, when we put the tenders out, we had somewhere around 7 bidders. And obviously, we were looking at a mixture of the bareboat rate versus mobilization versus the geographic location of the unit that was being bid. Taking all that into account, we are currently in negotiations over a certain unit that is has the lowest mobilization opportunity. And with that, it's already executing a program in West Africa. It completes with one company in February, then it's too good for two other wells to do in another part of West Africa, then it will come to us. So, it's purely one of economics as opposed to any kind of pressure on rates, et cetera, economics and expediency. And it's a rig that is it's not stacked, it's hot working and one we've used in the past. So that is really the timing is down to the schedule that the rig already has committed to as opposed to any other external factor. When we look at the program itself, I haven't went into a lot of detail on the program and we will be doing that from near to it. But when we're looking at the infill opportunities, we're looking at drilling pilots on either side of our targets. So, the number of wells could be the pilots are both successful with 2 wells. So, we could have up to 5 or 6 new wells coming into that, which will be slot dependent on Itami. We've got a redrill in Eburi, a workover in Eburi 2, it's a redrill of 4H and a redirection on Eburi, one of the other Eburi locations. So, out of the 7 firm, and I'll exclude the exploration well and the gas well, we've got at least 5 of those wells or new wells. The gas well obviously is for fuel gas and we've got an exploration prospect out there as well. The optional position would take over a number of workover opportunities if we choose to let them that we feel are necessary given the performance of the ESPs on some of the wells. So that's really what we've kept in contingent.

Okay. And the wells, can you give us a sort of ballpark figure for the program or per well?

I can. I'm probably going to be about $40 million for D&C on a new well. I'm probably going to be about $5 million less on a redrill. And for the exploration well, we're going to be down as low as about $17 million to $20 million.

Okay. That's very helpful. And then very finally, an easy one, I'm sure. In Gabon, on the new licenses, you say you've completed the documentation. That doesn't quite sound like those licenses have been awarded to you?

Those licenses have been awarded to us. All parties have signed, unfortunately, we had a real estate issue that I was discussing with the minister in Gabon Fernando Gebon, I was actually in Cape Town last week discussing it with the minister. We still have to put pen to paper, but he formally announced the licenses have been awarded to all of us in Cape Town last week. So, it's just basically we have to put a signature on a piece of paper. But that's why, we've worded it the way we've worded it. There's no question over the license whatsoever, just an administrative issue.

Sounds good. Thank you.

And our next question will come from Stephane Foucaud with Auctus Advisors. Please go ahead.

Thanks as well for taking my questions. The first one is around Canada. So, there is this very interesting one to be doing in Q4, on the exploration side. But I think you didn't talk much about what '25 might look like. Do you plan to do much in Canada in 2025? And would that be dependent on the results of the upcoming explosion well? That's my first question.

Okay. The first question is quite easy. Yes, we probably plan -- we haven't given guidance for '25 yet. We tend to drill a number of wells in Canada to ensure that we keep the GOR ratio in a position that makes sense for us between liquids and gas. We will I can guarantee to you right now, we will be drilling in Canada next year. The key issue here is, whether we're enhancing the prospectivity of the South-based on the results of this well that will come in or whether we continue to drill in the areas that we've got for the North. Now, we've got areas worked up and I think I've said before, we've got an excellent five-year plan from the team in Canada. So, we know exactly where we would like to drill to make sure that, we keep the liquid ratio as high as possible. But in saying that, if the well that we're drilling to the site, the exploration well comes in successfully and as expected, that may cause a slight change in sequencing as to where we will target the wells for next year.

Okay. So, we should expect maybe a capital program similar in Canada than for this year? Would that be something reasonable?

Yes. Very little. There or thereabouts. Yes. I mean, obviously, we're not giving guidance yet, Stephanie, because we haven't locked in those positions. But I mean, anyone can see that we can't allow the GOR position to go too high due to the gas position in Canada. So, we have to keep investing to keep those liquid ratios up.

Okay. Thank you. And my second one for you for Ron. The production of Q2 -- of Q3, sorry, was very good. And I was trying to reconcile to see where the production has been so good across the assets. But when I add up the individual production of each asset, I sort of got a slightly lower number, which I think is the production you've got in Slide 4, [indiscernible] What's the difference between the 26,350 on Page 4 and the 26,710 headline for the production, at Cote d'Ivoire?

You're cutting in and out a little bit, Stephane. I'm finding it a little bit difficult to hear you. But, if you could point me to which pages, sorry, you were highlighting?

Yes. Sorry. Can you hear me now?

Yes, I can.

Okay. So, it's Slide 3. The headline number for the production is 26,709,000 a day. And when I was looking at each asset individually, I got a slightly different figure, which is 26,348,000 on Slide 4. And I was wondering what was the difference. I think it's in Canada, which would suggest it has been a very good prediction. If you could confirm, that would be great.

Yes. Most probably. As of the individual slide averages coming back through there, I would have to look at my team who presented that for me. But, yeah, I think if anything, it's it could be 1 or 2 and those areas just on the averages themselves, because these are individual average numbers versus obviously our total production from a working interest point of view and then divided by effectively 90, I guess it was 92 days in Q3.

Our next question will come from Bill Dezellem with Tieton Capital. Please go ahead.

Thank you. I'd like to start with Cote d'ivoire. The production was up on a daily basis by 35%, and I was hoping that you could help us understand that because I assume that calculation adjusts for greater number of days in Q3 than Q2 since it's on a daily basis?

Yes, I mean the production has well, certainly against our forecast, the field has been performing very well. Recently, we've seen one of the wells take come down in Cote d'Ivoire and thereby the P16 well. So, we will see a position closer to forecast I think in Q4. And I think our guidance reflects that position. But basically, we've seen a very strong performance. So, we've got the increase because we've had the higher run rate, where two-thirds of Q2 versus a full Q3, but we've also seen the wells performing higher than our original forecast we got from the operator. That's primarily what's been happening. There's not it was only until recently towards the end of Q3, we started to see some issues around the P16 well.

Yes, I mean, I'll just jump in there, Bill. I mean, the forecast for Q4 is 4,000 to 4,400 and through October, we were right on the midpoint.

Okay. But I don't feel like that totally addresses the significant increase in the daily production in Q3 versus Q2.

I can probably shed some light on that....

Yes, George, you jump in.

Q2 only has 2 months in it because of the closing date versus Q3 has 3 months.

What I was looking at though was the daily production as opposed to the total production. Does the daily production take that change into account?

Total production divided by the number of days? Yes. It's your total number divided by the number of days in the quarter. So, it would be 30.

I mean, at the end of the day, what would have happened in Q2, Bill, is, you got more days than we had, combined for CDI because it came in on the on the 1st May even though we count from the 1st April. And then obviously in Q3, you've got 92 days, so you've got 92 days’ worth of production at the same time.

Okay. I'll take that one offline, but it certainly looks like nice activity there. Let me shift to BW Energy Fields. What is the timeline for that relationship for those two blocks before you begin drilling and have production?

These are two exploration blocks. Now the reason we went into a partnership with Panoro and BWE is because between the three of us, we are the main partners in that whole area for Itami and Disifun and the fairway play on blocks G&H run basically flow down from where we produce in Itami down into where they've been drilling and in production in Disifun. So, once we well, in Q4, we will sign and pay the signature bonus. In 2025, we haven't seen the program yet, but we anticipate the program will be seismic acquisition, particularly around Block G, which is the one nearest to us. And then, we anticipate sometime in 2026 would be a well-being committed into that block. Now production from any successful well is dependent on two things. It's dependent on its proximity to infrastructure. So how close is it to Itami versus how close is it to Disifun and obviously then tying it back. So, if we were drilling in 2026 per say assuming rig availability, we wouldn't be seeing any production from that until late '27 by the time you put equipment in place and tie it back to the infrastructure.

That's helpful. Thank you very much George. And I'm going to try to squeak one more in, if you allow it. The payments, which I think are roughly $40 million that you are still owed from Egypt, when do you expect that to happen? And does that come as one transfer into your account of $40 million or does it happen piecemeal over time? What's your expectation of how that would unfolds going forward?

We've been pushing this for some time. We've finally got it to a point where it's recognized and acknowledged by the government. We're keeping it separate from our trade receivables, when it comes to the discussions. So, we're highlighting it as we're not looking for offsets for this, we're not looking for settlement or keep us settled, as we promised to do on a monthly basis with our trade AR. So, we're looking for a separate deal on this. Now whether -- how we get to that and we've been having discussions, our new company managers have been in there having discussions to try and keep this as an extraordinary item. Our anticipation is certainly that, we will be looking for a single payment in U.S. dollars to settle this back to position. On the basis that, we've made significant progress through the agreements with the government and including full recognition of our investment and the VAALCO trade name into Egypt, we see the rig up again last month and we commenced the drilling activity both in Rascara band and South Ghazalat. We're looking in Q1 as a way to see some movement on that, but the discussions are ongoing. My preference always would be a single payment to your account, but that's certainly, where we'll be starting the discussions, therefore we have been having the discussions around. And we'll keep pursuing that. At the same time, making sure that, our trade AR doesn't suffer or be compromised in any way because of this backdated settlement.

We have time for one more question here, and we will take a follow-up from Jeff Robertson with Water Tower Research. Please go ahead with your follow-up.

Thank you. George, in Cote d'ivoire, with the development plant or development drilling campaign planned for next year and into 2026, are you all actively seeking a rig for that yet or are you still in the early stages of putting it together?

That's with the operator. I believe they are actively seeking a rig and I believe they are ready to talk to us about that in early Q1.

And this concludes our question and answer session. I'd like to turn the conference back over to George Maxwell for any closing remarks.