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Presentation

Operator: Good morning, everyone, and welcome to the VAALCO Energy’s Third Quarter 2025 Conference Call. [Operator Instructions] Please also note today’s event is being recorded. At this time, I’d like to turn the floor over to Al Petrie, Investor Relations Coordinator. Sir, please go ahead.

Al Petrie: Thank you, operator. Welcome to VAALCO Energy’s Third Quarter 2025 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. [Operator Instructions] I’d like to point out that we posted a supplemental investor deck on our website that has additional financial analysis, comparison 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 the reports we file with the SEC, including our Form 10-K. Please note that this call is being recorded. Let me turn the call over to George.

George Maxwell: Thank you, Al. Good morning, everyone, and welcome to our third quarter 2025 earnings conference call. For over two years, every quarterly earnings call, we have met or exceeded our production guidance, consistently leading to strong operational and financial results. The third quarter was no different with NRI production of 15,405 BOE per day, which was at the high end of guidance; working interest production of 19,887 BOE was above the midpoint of guidance, and NRI sales of 12,831 BOE per day, which was also at the high end of guidance. Our production and sales performance through the first 9 months of 2025 has been so strong that we have raised the midpoint of our full year production and sales guidance by about 5%, while also further reducing our capital guidance by almost 20% and maintaining our operating expenses virtually flat.

Ron will go into more detail about our guidance later in this call, but we believe that maintaining operational excellence and consistent production across our portfolio is essential to continued strong adjusted EBITDAX generation, which will assist us in funding organic growth initiatives while positioning us as a larger player in the industry. In the first 9 months of 2025, we have delivered net income of $17.2 million or [ $0.0016 ] per share and adjusted EBITDAX of $130.5 million. It is important to remember that 2025 is a transitional year, and everything remains on track with our forecast. Production came offline in Q1 at Cote d’Ivoire due to the FPSO project, and we do not expect to start the drilling campaign in Gabon until late Q4 as we await the drilling rig’s completion of its current commitments.

This means that the meaningful production uplift we are projecting for these major projects won’t begin until 2026 and into 2027. I would now like to go through and provide a quick update on our diverse portfolio of high-quality assets, beginning with Cote d’Ivoire. In line with the project timeline, the FPSO ceased hydrocarbon operations are scheduled on January 31, 2025, with the final lifting of crude oil from the vessel occurring in early February. The vessel departed from the field in late March and arrived at the shipyard in Dubai ahead of schedule in mid-May 2025. The FPSO refurbishment is well underway in the shipyard. Significant development drilling is expected to begin in 2026 after the FPSO returns to service with potential meaningful additions to production from the main Baobab field.

We now have a 10-year extension of the license on CI-40, extending it to 2038. In March 2025, we announced a farm-in agreement for the CI-705 block offshore Cote d’Ivoire where we will operate with a 70% working interest and a 100% paying interest. In Q2, we received seismic data for the block, and we are conducting a detailed integrated geological analysis to assess and mature our understanding of the block’s overall prospectivity as well as the basin’s overall potential. We believe the block is favorably located in a proven hydrocarbon system and is approximately 70 kilometers to the west of our CI-40 block. We have demonstrated our ability to acquire, develop and enhance value through accretive acquisitions, and we are excited about the prospects in Cote d’Ivoire.

Moving to Gabon; given that we haven’t drilled a well in Gabon in over two years, we are very pleased with the positive overall production results, including strong production uptime and improved decline curves on the wells in 2025. In July, we successfully completed a planned full field maintenance shutdown of the Gabon platforms to perform safety inspections and necessary maintenance. This is the first time we have had to perform a full field shutdown in Gabon since the FSO was brought online in 2022. This has helped to contribute to the strong uptime numbers in Gabon that we have had over the past several years, which can be seen in our supplemental presentation. While we secured a drilling rig in December 2024 for our 2025-2026 drilling campaign, the timing of when we start the drilling program has always been dependent on the rig’s completion of its existing commitments.

The rig is now being released and moving to Gabon. As we discussed in the Capital Markets Day, we have some very strong drilling opportunities and the additional data gathered during the upcoming drilling program will help us high grade and derisk additional well locations that have already been identified. We plan to begin the drilling program on the Etame field platform, and we are currently planning on moving to the Ebouri wells later in the program because of the current robust production profile of these wells. In particular, we remain very pleased with the extended flow test on Ebouri 4H well, which is continuing to surpass our initial expectations. We originally wanted to gather information on the H2S concentrations at this location to aid in equipment design and to evaluate our chemical crude sweetening process.

The 4H well has now flowed for all of 2025 at a gross average of around 1,000 barrels of oil per day with the H2S concentration within our modeling expectations, demonstrating our ability to chemically treat the oil. The wells production has helped Gabon exceed its production guidance in 2025 while adding some additional production costs for chemicals. Regarding our exploration blocks in Gabon, the Niosi Marin and the Guduma Marin, we are working in conjunction with our partners and the operator, BW Energy, on plans for the two blocks moving forward. A seismic survey to fulfill a work commitment on Niosi is being planned for acquisition in late 2025 or early 2026. Given the proximity of these blocks to the prolific producing fields of Etame and Dussafu, we are excited about the future possibilities for these blocks.

Turning to Egypt; in the fourth quarter of 2024, we contracted a rig and drilled two wells starting a drilling campaign that has carried into the first 9 months of 2025. We have drilled and completed multiple wells in the first 9 months of 2025 and are continuing activity into the fourth quarter. We are very pleased with the operational performance and efficiency of the drilling program, which contributes to minimizing costs. We’ve been able to drill more wells faster and cheaper than what we had in the budget and for the same amount of capital, which has also positively impacted the production. We also continue to workover and recomplete wells in Egypt. Both the drilling program and the workover program in Egypt add solid production and are economic even in lower commodity price environments.

We are continuing to evaluate the exploration results in South Ghazalat, where the wells are encountering both oil and gas net pay zones with different levels of reservoir pressure. We are incorporating well results and updating our understanding of the area with new mapping that will determine potential additional prospectivity for the area. In March 2024, we announced the finalization of documents in Equatorial Guinea related to the Venus Block P plan of development. This summer, we began our Front End Engineering Design or FEED study. The FEED is complete and confirms the technical viability of our plan of development, but also highlights some of the risk and challenges from the shelf location. We have expanded this review to explore more efficient development opportunities through a subsea development, which would also significantly simplify the drilling operations and well design, and this is currently underway.

We are very excited to proceed with our plans to develop, operate and begin producing from the discovery on Block P offshore Equatorial Guinea in the next few years. Turning to Canada; we successfully drilled and completed four wells in 2024. We also drilled a well in the Southern Acreage in late 2024 that could help us better understand the acreage and upside in that area. While we remain optimistic about the drillable inventory in Canada, we decided to postpone our Canadian drilling program in 2025 due to the current commodity price environment. We will continue to monitor the performance of our wells and plan for future drilling opportunities. Before I turn the call over to Ron, I would like to thank our hard-working team who continue to operate and execute our strategic vision and help us deliver these outstanding results.

We are well-positioned to execute the projects in our enhanced portfolio and our proven track record of success in these past few years should instill confidence for our future. With that, I’d like to turn the call over to Ron to share our financial results.

Ronald Bain: 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 9 months of 2025, driven by our strong operational performance. We have met or exceeded production guidance for the past 2-plus years, driven by strong production in Gabon and Egypt despite Cote d’Ivoire being offline since January — since late January. This performance has allowed us to positively adjust the midpoint of our full year production and sales guidance. In the supplemental deck on our website, you can see that NRI production is up 900 BOE per day and sales are up 750 BOE per day.

You will also see that our full year capital midpoint guidance is down almost $60 million to around $240 million in total. Finally, we have worked hard to keep our absolute production expense in line with our original guidance. But with the increase to sales and production, our production expense on a per BOE basis is down about $1 per BOE. Our overall results and ability to manage multiple assets and high profile capital projects across multiple countries are reflected in our updated 2025 guidance. For Q4 2025, we are forecasting production to be between 20,300 and 22,200 working interest BOE per day and between 15,600 and 70,300 NRI BOE per day. This is up compared to the third quarter due to the planned maintenance turnaround that occurred in Gabon in July and continued strong production in Egypt.

For the fourth quarter, we are forecasting our sales will also be higher compared to Q3 due to more offshore listings in Gabon. We also expect our absolute operating costs to be higher compared to Q3 due to the additional sales, but virtually flat on a per barrel of oil equivalent basis. Finally, looking at CapEx, our Q4 spend is expected to be higher than the third quarter as we begin the drilling campaign in Gabon. We are forecasting between $90 million and $110 million, and we anticipate continued spending in CDI and Egypt in Q4 more or less in line with Q3. In the third quarter, we generated $1.1 million in net income or $0.01 per share and $23.7 million in adjusted EBITDAX. Our NRI sales for the quarter were at the high end of guidance at 12,831 BOE per day.

Both sales and pricing moved against us in the third quarter, with sales down 33% due to the fewer listings in Gabon, driven by the planned turnaround and pricing was lower by about 7% quarter-on-quarter. We have seen higher volatility in the commodity price environment thus far in 2025. Our hedging program has always looked to help mitigate risk and protect our cash commitments. But with the RBL now in place, we are moving towards a more programmatic hedging program that will be more consistent over a rolling time horizon. With this in mind, we took advantage of periods of higher oil prices during the third quarter to add more hedges for the 2026 hedging program. The company now has about 500,000 barrels of remaining 2025 oil production hedged with an average floor of approximately $61 per barrel and about 800,000 barrels of oil production hedged for the first half of 2026 with an average floor of approximately $62 per barrel.

We are targeting around 40% of Half 1 2026 oil production to be hedged by year-end. Our full hedge positions are disclosed in the earnings release. Turning to costs; our production costs for the third quarter of 2025 were at the low end of guidance on an absolute basis and on a per barrel basis. Absolute expense was $29.87 million, a 26% reduction quarter-over-quarter and on a per barrel basis was $25.24. G&A costs were in line with guidance and remained relatively flat quarter-over-quarter. Our focus remains on keeping our costs low to enable us to maximize margins and increase our cash flow. Moving to taxes; we reported an income tax benefit of $3.6 million for Q3 2025, which was comprised of an $8.6 million current tax expense, offset by a deferred tax benefit [Technical Difficulty] Gabon’s allocation of profit oil between the time it was produced and the time it was taken in kind.

Turning now to the balance sheet and cash flow statement. Unrestricted cash at the end of the third quarter was $24 million. Collections from the Egyptian General Petroleum Corporation, EGPC, since the 1st of January 2025 totaled over $103.6 million, and the company expects to receive further material payments against its arrears before year-end. We anticipate that our annual receivables balance will be half of what it was in 2024 by year-end. Monthly invoices are now paid in full and regular repayments are being made against the receivables balance. As we discussed last quarter, we added a reserves-based credit facility with an initial commitment of $190 million and the ability to grow to $300 million. Shortly after the third quarter, we successfully completed our semiannual redetermination with lenders and reaffirmed the initial commitments.

As of September 30, 2025, VAALCO had $60 million outstanding borrowings, which is the same amount outstanding as we had at the end of the second quarter. In Q3, we spent $48.3 million in cash CapEx, well below our third quarter guidance of $70 million to $90 million. Additionally, we returned $6.7 million through dividends to our shareholders. We believe that our current dividend yield of around 7% is very attractive, especially considering the meaningful upside potential in production and reserve growth that we outlined in the Capital Markets Day over the next few years. In closing, we’re continuing to see strong results. We are well-positioned to execute and fund a robust organic capital program that should help to increase production and reserves for 2026 and beyond.

With that, I’ll now turn the call back over to George.

George Maxwell: Thanks, Ron. We will continue to execute a strategy focused on operating efficiency, investing prudently, maximizing our asset base and looking for accretive opportunities. As you have heard this morning, we continue to meet or exceed both our quarterly guidance and analyst estimates in the first 9 months of 2025 as we have done for the past several years. This has allowed us to increase our full year production guidance by about 5% while lowering our full year capital guidance by about 20%. By delivering on our commitments to the market, I believe we have earned the credibility with our shareholders, and we will continue to deliver on the exciting slate of projects that we have over the next few years. Our entire organization is actively working to deliver sustainable growth and strong results.

We have multiple major projects underway that are anticipated to meaningfully grow production and reserves. Through the first 9 months of 2025, we have generated $130.5 million in adjusted EBITDAX, and this is with Cote d’Ivoire offline for the FPS again. Through the first 9 months of 2025, we have generated $130.5 million in adjusted EBITDAX, and this is with the Cote d’Ivoire offline for the FPSO project and no new wells drilled in Gabon. In addition to funding our capital program, we have remained focused on returning value to our shareholders. In the first 9 months of 2025, we returned around $20 million to our shareholders through dividends. With the Q4 dividend announcement, we will deliver another [ $0.0025 ] per share annual dividend for 2025, which at our current share price is a dividend yield of about 7%.

We are confident in our ability to execute on the many projects ahead, largely because we have been highly successful over the past several 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 and has positioned us to continue to profitably grow in the future. Thank you. And with that, operator, we’re ready to take questions.

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Operator: [Operator Instructions] Our first question today comes from Stephane Foucaud from Auctus Advisors.

Stephane Guy Foucaud: So two questions. The first one is around CapEx. So reduction of CapEx in 2025. I was wondering what would be broadly the CapEx mix across the asset in 2025? And what it means the CapEx reduction in 2025 for 2026? In other words, how would 2026 CapEx compare broadly to 2025? So that’s my first question. The second question is about South Ghazalat. In your view, in a success case, how big could be South Ghazalat or what this result means in terms of — compared to the existing reserve in Egypt?

Ronald Bain: Hi Stephane, I think — it’s Ron here. I’ll take the first one on CapEx and CapEx guidance. So if you look at it between the midpoint of guidance, I think we moved about $60 million. $20 million of that is gone. That was discretionary CapEx that we took out in 2025. We’ve had about a $10 million increase in CDI CapEx, really just keeping that MV-10 on schedule. And that’s very good news as far as we’re concerned that everything is going well in relation to that project. And the rest is really a shift in Gabon from the drilling campaign due to the delay in getting the rig moving out from 2025 into 2026. What I would say, though, is on Egypt, effectively, the Egyptian CapEx is the same number as we originally guided to, but we’ll have completed 8 additional wells in that time period for the same CapEx. So again, that’s a very positive efficiency that the guys have brought to the table in 2025.

George Maxwell: And on South Ghazalat, one of the additional wells, as you know, Stephane, was out there, and I tried to touch on it in my comments earlier. So what we’ve seen there in the well that we drilled, we entered the gas prone zone with lower pressures, which indicates that there’s potentially some gas depletion there. And we also entered an oil proven zone that had no pressure. So what we’re trying to establish now is the total extent of the oil zone, what that aerial extent could be and how large that could be for potential development and then understanding the reduced pressures around the gas zone and where that depletion may be. So having got the results of the well, we’re going back to do our after-action review and establish where else within the existing structure that we understand, we’d want to drill additional wells there.

There are a couple of things outstanding in South Ghazalat. Whilst we had some commitment wells that we’ve already completed to keep the acreage. But in addition to that, we’ve also got some commercial issues around the PSC that we have to discuss before we get anywhere close to some kind of preliminary field development plan. So there’s more technical work to do, but there’s also some more commercial work to do. We’ve always been hopeful that because it’s such a prolific area out there in the Western Desert that this block will yield some interesting opportunities for us, but that’s still to be developed and it’s still to be evaluated at this time.

Operator: Our next question comes from Jeff Robertson from Water Tower Research.

Jeffrey Robertson: Ron, just to clarify on the CapEx, did I hear you right that about $20 million of the reduced guidance is permanent reduction, in other words, getting — either doing things at lower cost than budgeted or getting more done with the same amount of dollars?

Ronald Bain: That’s exactly right, Jeff. As you know, we took Canadian drilling CapEx out very early, I think, in Q2 guidance, we pulled that out. That was about half of that. The other half is just discretionary CapEx that we pulled out over the last 3 or 4 months.

Jeffrey Robertson: Are the efficiency gains that have helped in Egypt, are those sticky? In other words, does that — you would retain those types of efficiencies if you look at a CapEx program in Egypt in 2026?

Ronald Bain: Yeah. I mean what we’ve got, Jeff, as you know, we’ve reduced that spud to basically take an online cycle time quite considerably over the last three years. We continue to drill and complete and bring online those wells at a much lower level of days versus what our initial expectations were. So those efficiencies are real. They’re there. And if they continue into 2026, we’ll continue to see less [ AFE ] costs for drilling in Egypt.

Jeffrey Robertson: Okay. And on the RBL Ron, I believe the electric commitments is going to go up to $240 million in January. Is that a reflection of asset performance?

Ronald Bain: I think it’s more a reflection of the current market, Jeff. I mean liquidity is going to be key for all upstream companies as we move into 2026, with softening commodity prices. And from our point of view, we have the availability there. I’d rather lock it in when we’ve been a position of strength than when in a position of need.

Operator: Our next question comes from Christopher Wheaton from Stifel.

Christopher Wheaton: Two, maybe three questions, if I may. Firstly, on Gabon production. You’ve not — as you said, George, you’ve not drilled any wells for two years now on Gabon. And as you said, the Gabon drilling program shifted later in this year, you still delivered a pretty good production performance, and that’s on uptime, if anything, slightly lower than it was last year. I’m interested, is there the geology better? Are there particular wells performing better than you expected? I’m interested in what’s been driving that production uptime. And then second question on really about 2026 CapEx and your ability to flex that as you’ve got more of the Gabon drilling campaign falling into ’26. You’ve got Cote d’Ivoire CapEx, obviously, as a given for ’26 as well.

I’m interested just what your key priorities for setting that 2026 capital budget are going to be given you’ve got a lot of things that you’re kind of on the must do or have to do list. And therefore, realistically, are we going to see — is there much CapEx flex below, say, 2025 levels that we might see for 2026 CapEx guidance? I’ll stop there.

George Maxwell: Okay. Let me start on Gabon. I mean, obviously, in the last — ever since we’ve completed the reconfiguration, what’s resulted from that is, I think as we’ve maybe discussed before, is a significant reduction in back pressure into the reservoir, which has enhanced not just well performance, but a lot of the field performance as well. We’ve also been working on the brewery side to continue the production in 2-H and then we’ve also brought on 4H. We did that deliberately to test the levels of H2S that could be managed through the [ scavenger ] program. And we’ve continued to see 4H produced throughout 2025 with H2S levels well within our manageable range. That’s been very encouraging, and it’s also will lead when we get to the drilling program leads us to not just the 2H workover potential, but then 5H to go back and redrill 5H both — goes across a fault block to enhance the production in the buoy.

So these results are — and these test wells that we bring back on stream are really important for our understanding of how we’re going to deal with the potential H2S as it comes towards us in the future. The — you are correct in that when we look at the production profiles for the Etame field, we can see that we’re producing well above the 1P decline curve and in some cases, into the 2P position. We look at that and the questions are naturally come is the size of the tank larger — our recovery factors are going up to the 50 percentile and higher. So there’s clearly some geological remapping work that’s currently underway that’s required to understand this field better. I keep going back to some of the decisions way back in the early 2000s when this field had a life expectancy of 5 years.

And here we are 20-plus years later having produced close to 150 million barrels from the field, and it continues to give. So hopefully, the studies we’ve got in place over the next 6 months will start to clearly give a better definition around the geology and whether there is connectivity into the Gamba from the Dentale that’s supplementing those production levels. With regard to the CapEx position of 2026. Now obviously, as Ron mentioned, the delay in the rig coming to us for 2025 has delayed our program for Gabon. We continue with the position in Gabon with a 5 firm and 5 options. So there is some flexibility in the drilling program in Gabon. But as I’ve mentioned before, we’ve been studying these drill locations now for a few years, and we’ve got some pretty strong targets that we want to go after.

So that will give some meaningful production uplifts in Gabon. So whilst there may be not as much flexibility as we may want in the Gabon drilling campaign, that comes with the added benefit of significant additional production. With regard to Cote d’Ivoire, as Ron mentioned, we have spent a little bit more CapEx in ’25 to ensure that the sail away date of the end of March for the FPSO can be met, and we’ve discussed that in detail with the operator. There is a drilling program, as you’re aware, to start the second half of 2026 in Cote d’Ivoire. The exact timing of that drilling program is still a little bit subject to, obviously, rig availability, equipment, et cetera. So there may be some flexibility there. However, again, these investments come with significant adds to production.

So — and as we know in Cote d’Ivoire, every dollar we spend is recoverable with $1.25 back in the cost oil. So whilst the CapEx may look slightly less flexible in ’26 than it was in ’25, it comes with considerable benefits.

Operator: Our next question comes from Charlie Sharp from Canaccord.

Charlie Sharp: Can you hear me?

George Maxwell: Yes, we can hear you.

Charlie Sharp: Sorry about that. I was on a separate phone and here we are. So the question really is regarding timetabling of events next year. And I think you’ve just provided some useful information there on the planned sale away of the Baobab FPSO. I’m guessing from that, that you still expect to be back on stream there before the middle of the year in order to facilitate drilling sometime in the second half. That’s one small question. And then secondly, on Gabon, should we assume that you’re drilling wells about one per quarter, in which case you’ll probably be drilling into 2027? And will you be completing successful wells as you go or will you batch drill and batch complete?

George Maxwell: Okay. So I’ll start with — you’re correct in your assumption. We’re still — the sail away date is still for the end of January after the second dry dock period. The hookup is scheduled to be late March, early April and back on production by end of April, early May. So well ahead of the drilling program. And when we come into 2026, you’ll see that coming into our guidance position, and we’ll be able to give you much more detail at that time. But that’s the current schedule and everything on that project is currently on schedule. For Gabon, obviously, what we’re trying to do here in Gabon, like I said, we spent a lot of time looking at these drill locations. Some of the — as you may be aware, the imaging on the seismic here is not as clear as we would like it to be due to the interference of salt.

But that being said, we’re planning to drill pilot holes in some of these locations to establish exact levels of hydrocarbons to then allow us to pull back and redrill or complete in a different zone. So when we look at the schedule right now where we’re starting on the Etame field with two pilots, we would — if both of those come in and remind the POSGs are 80% plus, we would drill and complete as we go. So we will not do that drilling. So we potentially have three wells on Etame if we choose to elect one of the options, one well on Seent and then a workover and well on Ebouri.

Operator: Our next question comes from Bill Dezellem from Tieton Capital Management.

William Dezellem: Relative to the Cote d’Ivoire drilling program, you’d mentioned that that will begin in the second half of next year. Given that the FPSO will be back in the field and reconnected in May, what’s the swing factor or swing factors that would drive the drilling earlier in the second half versus later in the second half?

George Maxwell: Okay. So the biggest swing factor is exactly what we face in Gabon is the drilling unit arriving on time. When we look at where we are today, though, all the long lead items, the trees and the equipment, et cetera, are all ready to go. So it’s all around the drilling unit and the timing of that. So when it comes off its existing contract, as you know, we may have a scheduled date, but if it’s halfway through drilling a well for a previous client, then it has to complete that well before it comes to us. So it’s really just the rig move would be the swing factor.

William Dezellem: That’s helpful. And then relative to Equatorial Guinea, you’d mentioned that you’re looking at a subsea completion application. Was that part of the FEED study or are you now needing to do essentially a sidebar FEED study?

George Maxwell: It’s not quite a sidebar. What came out of the FEED study was what we were trying to achieve in the FEED study was how do we reduce the CapEx position that’s in the POD. And what we were looking at was can we go to drill off the shelf with what we call a [ MOPU ], a self-elevating platform for production and basically put that to a leased unit rather than a capital unit. What came from that is that there are — given the complexities of the shelf drilling, getting the exact locations for the wells are possible but complicated when you’re looking for the two producers and you’re looking at getting a water injector in there with a long lateral to give you an efficient flow of production from the structure. So that sweep efficiency is very key to the recovery factors and the production profiles that we’ve estimated from Venus.

We’ve since and during the FEED completed a new static and dynamic model, which confirms the volumes that we announced back in the Capital Markets Day. But again, that dependency on the sweep efficiency from the water injector is critical to achieving these production levels. So when we looked at that risk factor, we said, okay, it’s possible, but it contains risk. And we then looked at a vertical solution and said, do we eliminate that risk factor significantly by coming from a drillship position vertically versus coming from the shelf. And the answer to that is very clearly yes. What does that do to the cost structure? Well, it reduces the drilling times significantly, we’re evaluating that, but it comes at a higher drilling day cost. But overall, the economics are far better for the — on the drill side.

The production side, we’re now looking at — and we’ve spent some time now looking with what we’ve done in Gabon and what we’re doing in Cote d’Ivoire, do we get an FPSO at a reasonable price that can evacuate this oil and at an efficient level. And that’s really where the study is right now. There’s a lot of units available in the market right now. And because of the decline in other areas, they’re at a reasonable cost. So that’s really what we’re looking at, have we derisked the drilling position, can we then match it up with an efficient production position. And that’s really — it’s like a side bar to use your terms, but it’s also looking how we minimize the risk position on the drilling side.

Operator: Our next question comes from Jeff Robertson from Water Tower Research.

Jeffrey Robertson: George, just a quick question in Cote d’Ivoire. When the FPSO gets back to Baobab, how long would it take do you anticipate for production in the field to go back to whatever the full rate will be?

George Maxwell: Well, I mean, obviously, we’ve got the vessel gets back to the field. We’ve got the contract for the hookup and taking the flow lines back in place, and then we’ve got commissioning. I mean, I’m — at the moment in the schedule, we’re easily looking at 6 to 8 weeks for that. What we don’t — what we haven’t yet looked at, Jeff, is the start-up sequence. So we’ve got the commissioning to do, and then we need to look at the start-up sequence for the wells and see exactly which sequence of wells are coming on between the injectors, obviously, and then the producers. So that’s something we’ll certainly guide to when we come to the next call in early ’26. We’ll have much more detail on the start-up sequence at that time.

Jeffrey Robertson: Just one more in Gabon. With the maintenance work that you did in July, what will that do to prepare the facilities, if anything, for the upcoming drilling campaign?

George Maxwell: I mean, effectively, I think there, Jeff, we did quite some upgrades to Etame on both power and water handling. So everything is now done and ready for that drilling campaign coming in. But yeah, that’s essentially what was done along with the planned — the normal planned inspection.

Operator: [Operator Instructions] Our next question comes from Jamie Wilen from Wilen Management.

James Wilen: Hi fellows. I wonder if you could refresh me on the H2S wells that were shut in a few years ago. How many there were? And what were their — what was the volume per day? And what is your expectation moving forward?

George Maxwell: Yeah, Jamie, we had, I think, three wells out of Ebouri that were [ shut down ] in back in 2014. The production level around Ebouri was between 6,000 and 8,000 a day, and this is from memory, if I’ve got those numbers wrong, I’ll correct them. And as I said, we’ve got — we’ve had 2H flowing now consistently for a number of years. 4H we took on earlier this year and has continued to perform well. And it’s got to be said that we — our expectation of this well was that it was going to last for 3 months, mainly not because of reservoir issues, but because of the ESP issues. It’s an old ESP that has been in that well for probably close to 13 years. And the 5H position, we shut that down when we shut down the whole Ebouri platform.

So the 5H redrill that’s coming up in the program this time, that’s, for me, one of the most exciting wells that are in the program because it’s a redrill back into what should be a crestal position in the field, and we’re anticipating some really good results from that well. So with the work on Ebouri and the test work that we’ve done, it just further enhances our confidence levels to be able to deal with the H2S as and when it comes towards us.

James Wilen: What was the volume of that well when it was producing?

George Maxwell: I’d have to check, Jamie, but I think it was probably around about somewhere between 1,500 and 2,000 barrels a day. But my position, this is going to be — it’s — that’s the old well. The new wells are a sidetrack redrill, and it’s going to a much higher position in the reservoir structure. So I’m a little bit confident we may see numbers higher than that for that well.

Ronald Bain: And I think what I’d add to that is George is talking gross, Jamie, all the time. Those are gross numbers.

Operator: And ladies and gentlemen, at this time, we’ve reached the end of today’s question-and-answer session. I’d like to turn the conference call back over to George Maxwell for any closing remarks.

George Maxwell: Thank you very much, operator. I’d just like to close, we’ve had a strong third quarter and some good results in the third quarter despite the reduced volumes in net sales because of the government liftings that took place this quarter. The position that we’re in coming into 2026 with the execution of our projects leaves us in a strong position. There are no concerns around where we are in the main capital project around the FPSO for Cote d’Ivoire. That project remains on track, and we monitor it very closely with our partners. I’m very encouraged that we’re finally getting going on the drilling campaign, albeit there’s a 4-month delay in the rig arriving. But that’s very encouraging, and it shows our commitment both to Gabon and our commitment to CDI for our investment.

We’ve seen strong EBITDAX performance over and above guidance this quarter, which maybe was a bit masked by the revenue. But again, with the lower revenue and higher EBITDAX indicates the company’s focus on its cost control during this period of softening commodity prices. So I’m encouraged that when we come to talk again early Q1 that we will complete 2025 on a successful basis. As you’ve seen, we’ve narrowed the guidance to give further confidence to the market as we see our position narrowing to improve the profile through Q4. And with that, I look forward to talking to you again in Q1 2026. Thank you.

Operator: And ladies and gentlemen, with that, we’ll conclude today’s conference call and presentation. We do thank you for joining. You may now disconnect your lines.

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