Hello, everyone. My name is Sergei, and I will be your current conference operator today. At this time, I would like to welcome everyone to MEREN 's Second Quarter 2025 Results Presentation. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, please press star, the number one on your telephone keypad. If you would like to withdraw your question, please press star two. Please note that at any time, participants on the webcast can submit their questions using the questions button at the webcast interface. Please note that this event is being recorded. The recording will be available for playback on the company's website. I will now pass the meeting over to Mr. Shahin Amini, MEREN 's Head of Investor Relations.
Please go ahead, Mr. Amini.
Morning, and thank you for joining us for MEREN's Second Quarter 2025 Results Presentation. I'm joined today by Roger Tucker, our President and Chief Executive Officer, Aldo Perracini, our Chief Financial Officer, and Oliver Quinn, our Chief Commercial Officer. We will begin with prepared remarks and then open the floor for questions. Before we start, I would like to remind everyone that this presentation contains forward-looking statements. These are based on current assumptions and expectations and involve risks and uncertainties that may cause actual results to differ materially. You can find a full discussion of these risks in our regulatory filings available on SEDAR+ and on our website. With that, I will now hand you over to Roger. Roger, please go ahead.
Thank you, Shahin. Before going into the quarterly performance, I want to take a step back and reflect on the first half of the year and the progress we've made as a business. We've operated in a dynamic environment over the last six months, from fluctuations in oil prices to ongoing macroeconomic uncertainty. Despite this, our focus has remained clear, executing against our strategy and delivering long-term value for shareholders. This brings me to our capital allocation priorities, something we've been very deliberate about over the last two quarters. Since the Prime amalgamation, we've made strong strides in aligning the business behind these priorities. Starting with shareholder returns, we are firmly on track to deliver our $100 million annual dividend distribution. So far, we've returned $50 million, and I'm pleased to confirm a third quarterly dividend of $25 million, taking total distributions to $75 million by the end of Q3.
This is a clear signal of our ongoing commitment to shareholder value and shareholder capital returns. We also remain fully committed to maintaining a strong balance sheet with appropriate liquidity headroom. Following the Prime amalgamation, we have taken a proactive approach to deleveraging, repaying some $270 million of the RBL through disciplined cash management, with the aim of minimizing interest expenses. If necessary, we have the option of drawing down under our evolving RBL facility. With an end of Q2 cash position of $266 million and the headroom under our RBL facility, we have substantial liquidity and the optionality to act quickly and decisively to changing business environments towards our goals of value creation and shareholder returns. Overall, we are delivering on what we said we would do, maintaining financial discipline, focusing and delivering on our shareholder returns, and ensuring the business remains robust and well-positioned for the future.
Looking to the future, it is important to highlight our funded organic growth opportunity set. This slide outlines the catalysts that we see as potential near-term growth drivers for our business. Starting with the Venus development project in Namibia, I am encouraged by the recent positive updates and public statements by the operator, TotalEnergies. We are looking towards the final investment decision, possibly during the first half of 2026, with first oil by the end of 2029. This is a world-class project that will provide us with a long-life production profile, and importantly, it is funded through to first commercial production. We have captured the resource base and bridged the exploration-to-production gap without stretching our balance sheet.
Another important Venus catalyst for MEREN is that as we get closer to the final investment decision, there will be scope for us to report contingent resources and ultimately reserves as part of our annual NI 51-101 reporting process. Moving to Preowei, we are working closely with the operator and other partners to deliver a more economically robust project. The cost and subsurface optimization work for the project continues, and there are encouraging signs that the project can potentially capture more volumes with enhanced economics. Our Nigerian asset base also provides us with attractive near-field exploration opportunities, such as the Akpo Far East prospect. This is expected to be drilled during the next Egina Akpo drilling campaign to start during 2026. In case of exploration success, Akpo Far East will provide us with an attractive short-cycle project investment that can utilize the existing Akpo infrastructure.
I must reiterate our leading position in the Orange Basin offshore, Namibia and South Africa, where as well as our interest in the Venus development, we also have exposure to follow-on high-impact exploration opportunities. These are funded and provide us with potentially transformational catalysts without stretching our balance sheet. In South Africa, we hold an 18% interest in 3B/4B. We're carried for two exploration wells, and we are working with the operator to develop a drilling program. Oliver will shortly speak about our position in Equatorial Guinea, where we continue our farm-down efforts for Blocks EG-18 and EG-31, with the aim of replicating our commercial dealmaking success in Namibia and South Africa. Taken together, this set of opportunities gives us clear visibility on future reserves and production growth. I will now hand you over to Aldo to take you through the second quarter highlights.
Thanks, Roger. During the second quarter, we produced close to 31,000 bbl of oil equivalent per day on a working interest basis and 35,700 bbl of oil equivalent per day on an entitlement basis. Q2 volumes were slightly softer than the quarter-on-quarter trend due to the temporary adjustments at Akpo and Egina. These were driven by gas export restrictions and scheduled maintenance early in the quarter, which formed part of our broader strategy to ensure the long-term reliability of these assets. Overall, first half 2025 production performance is in line with our expectations and supports the midpoint of our original production guidance. At Akbami, production was also modestly adjusted to support flare management and maintenance activities.
Offsetting some of this, our two new Egina wells came on string during the quarter, performing in line with expectations and helping mitigate natural fuel decline and production adjustments, complemented by strong well performance at Akpo. Looking ahead, we will continue to optimize the infill development wells over the remainder of 2025 and the joint venture of progressing a well intervention program aimed at enhancing reservoir production levels. Also, ensuring asset integrity and maximizing production reliability remain central to our operating strategy, underpinning stable cash flow generation and long-term value delivery. Moving on to slide seven. This quarter, MEREN completed one oil lifting of approximately 1 million bbl at a realized price of $64.2 per barrel. Year to date, we have completed six liftings, totaling around 6 million bbl at an average realized price of $77 per barrel, which compares favorably against the Dated Brent at $71.8 per barrel.
Looking ahead, we have six cargo scheduled for the remainder of the year. Three of these have their Dated Brent fixed at an average price of $64.5 per barrel, while the remaining three are currently unhedged with no pricing mechanism in place. This approach, combined with the sale secured in the first half of the year, provides a prudent balance between risk management and market exposure, allowing us to mitigate oil price volatility risk and still capture potential upside. This gives us a solid and stable framework for cash flow performance into the second half of the year, despite ongoing volatility in the oil market. Moving on to the next slide for the financials. To start, please note that our Q2 financials are presented on a fully consolidated basis. The hybrid reporting used last quarter, following the amalgamation, no longer applies.
For Q2 2025, we delivered EBITDA of approximately $107 million, bringing total EBITDA year to date to around $248 million. Cash flow from operations before working capital came in at $78 million for the quarter, with reported CapEx of $30 million. For the first half, that equates to approximately $178 million in operating cash flow and $59 million in CapEx. Free cash flow before debt service and shareholder distributions was approximately $-19 million for the quarter. For the first half overall, free cash flow before debt service and shareholder returns stands at approximately $103 million. With that, let's turn to cash management. We closed the quarter with a cash balance of $267 million, compared to the opening balance of $428 million at the end of Q1. As mentioned previously, this is primarily driven by RBL repayments made during the quarter, dividend distributions, as well as movement in working capital.
Given our strong liquidity position following the Prime amalgamation in Q1, we seize the opportunity to use our cash position to deleverage the business and proactively pay down our RBL balance by $80 million during the second quarter. This brought our total debt balance at the end of the first half to $540 million and significantly reduced interest expenses. We have paid this down even further after the end of the second quarter. We also paid out our first two dividends of the year. In line with our new payout policy, we distributed $50 million year to date in dividends. As a reminder, under the new policy, we have committed to distributing a base dividend of $100 million per year, subject to customary consent and board approval. As Roger had mentioned earlier, we are pleased to have announced our third quarterly dividend, which will be paid next month.
We also had a large working capital movement of approximately $84 million, which comprised largely of movements in our underlift and receivables position. Overall, our approach towards cash management this quarter has been focused and disciplined, deleveraging the business and bolstering our financial strength. Coupled with a strong liquidity position, we remain grounded and well-positioned to deliver long-term value to our shareholders. Now turning to liquidity management. As we highlighted last quarter, following the amalgamation of Prime, MEREN assumed Prime's RBL facility with an outstanding balance of $750 million at the deal completion. We remain confident in MEREN's outlook, and maintaining disciplined cash management continues to be a key strategic focus. Deleveraging is a priority for us, and we have taken a proactive approach to reduce debt and interest costs.
At the end of Q2, our RBL balance stood at $540 million, reflecting a $210 million paydown since the deal completion. Post-Q2, we reduced this further by $60 million, bringing the balance down to $418 million and delivering a meaningful reduction in interest costs. We also canceled MEREN's $65 million standby corporate facility. This facility had remained undrawn, and by canceling it, we will save approximately $2 million in annual committal fees. At the end of the quarter, we had a net debt of $273 million, with a net debt-to-EBITDA ratio of 0.6x , well below our 1x ceiling, demonstrating our strong credit profile. Going forward, we will remain disciplined, considering how best we strengthen MEREN's financial profile and ultimately continue to deliver to our shareholders. Next slide, please. We have revised our 2025 management guidance based on the actual results from the first half.
The changes are summarized in the table on this slide. Working interest and entitlement production ranges have narrowed, with midpoints for both ranges increasing marginally. EBITDA and cash flow from operations guidance ranges are revised lower, based on a lower full-year average Dated Brent oil price estimated at $68.5 per barrel. This compares to the assumption of $75 per barrel used for the original management guidance. The revised full-year oil price estimate of $68.5 per barrel accounts for an average Dated Brent price of $71.8 per barrel for the first half of 2025 and an average Dated Brent price of $65 per barrel for the second half of 2025. We also expect a lower capital expenditure profile, primarily due to the phasing of drilling operations offshore in Nigeria, with the restart of drilling operations in 2026.
I will now hand over to Oliver to discuss the outlook for the rest of our portfolio.
Thank you, Aldo. Let's now move to slide 12 and an update on Namibia. In the last quarter, the joint venture has continued to work on two fronts. On the first front, work continues to progress the Venus development project towards final investment decision, which is expected in the first half of 2026, with potential first oil in 2029. The project engineering is mature, and the operator has guided to a development scheme with up to 40 subsea wells, tied back to an FPSO with a plateau production of 160,000 bbl of oil per day. Once online, the expected production life of Venus is greater than 20 years, and as such, it will deliver a long-term, sustainable cash flow to the company. The second front in Namibia is follow-on exploration drilling to fully unlock the potential resource within the licenses.
Results from the last drilling campaign are being studied and integrated with recent seismic data to high-grade targets for the commencement of drilling that is expected in 2026. The current drilling break will allow time to incorporate the recent well results and allow the next well targets to be further optimized. We currently expect the campaign to commence with a well on the Olympe prospect, and it is worth noting that this will test a slightly different geological concept with a four-way structural closure, and as such, presents a different prospect to the stratigraphic traps in Venus and Maroula. Of course, and as a reminder, we have the benefit of retaining exposure to these high-impact wells at no upfront cost and no pressure on our balance sheet, as all costs, exploration, and development will be carried through to first commercial production from the two blocks.
Moving to slide 13 and staying in the Orange Basin, we'll now move to South Africa and Block 3B/4B. Last September, we were granted an environmental authorization for the drilling of up to five exploration wells, and the remaining regulatory process is continuing to move forward at pace. With that, the joint venture is planning for the first exploration well in 2026, and currently, the leading prospect for the first well is Nyla, located in the northwest of the licensed area, and this is a prospect with sufficient resource in the success case to underpin a standalone future development. In terms of capital spend, the transaction we concluded with TotalEnergies and Qatar Energy last year will cover MEREN's costs for one to two exploration wells.
In summary, across the Orange Basin, we retain a leading independent E&P position with near-term exposure to multiple projects across both development and exploration, and of course, without the requirement for any near-term capital funding. Now turning to Equatorial Guinea on slide 14, MEREN holds two licenses offering differing opportunities. Inboard, Block EG-31 offers a compelling low-risk appraisal opportunity that could unlock a low CapEx short-cycle brownfield LNG project. The block lies in shallow water close to the existing onshore EG LNG facility and contains several gas-prone prospects in areas where historic wells have proven the presence of gas. The second position, Block EG-18, is a deep water exploration opportunity with material-scale oil potential.
Recent seismic reprocessing and technical evaluation have unlocked a large Cretaceous-aged basin floor fan system with several material prospects identified that sit within the same play that is being actively pursued by several majors across the border in São Tomé. Whilst we see significant value in both positions, our commercial approach and capital allocation remain disciplined, and as such, we are running data rooms for both blocks to introduce partners to both risk share and support capital funding. The farm-down process has attracted strong interest, and we are actively engaged in discussions with potential partners on both blocks, with the aim of reaching a conclusion on the farm-out process by the end of this year. With the right partnerships in place, drilling activity could take place in late 2026 or 2027. I will now pass you back to Roger for his concluding comment.
Thank you, Oliver. It has been a strong and resilient first half of the year for the company. We ended Q2 with about $267 million in cash and a net debt-to-EBITDA ratio of 0.6x , which underscores the strength of our balance sheet and our disciplined approach to managing leverage. We will continue to build on this, guided by our capital allocation framework to further strengthen MEREN's financial profile. With our new payout policy now firmly in place, I'm pleased that we have already distributed half of our $100 million base dividend commitment, with a further $25 million to be paid next month. This reflects both our confidence in the quality of our cash flows and our commitment to delivering meaningful shareholder returns.
MEREN today has all the key elements of a balanced business, the ability to consistently return capital, a robust financial profile, high-quality producing assets, and a fully funded growth pipeline. These are the foundations that position us to grow the business in a disciplined way while continuing to create long-term value for our shareholders. Thank you very much for your attention, and with that, let's move to the Q&A.
Thank you, Dr. Tucker. We will now begin the question and answer session. If you would like to ask a question, please press star followed by the number one on your telephone keypad. If you change your mind and wish to withdraw your question, you may press star two. We'll pause for a moment to allow questions to queue. Our first question is from Jeff Robertson from Water Tower Research . Please go ahead.
Thank you. Good morning. Roger, given MEREN's position with development activity and an exploration portfolio that's pretty robust, can you talk about the type of acquisition that would best fit the portfolio in terms of future capital and timing commitments?
Roger, for you?
Hey, Shahin, it's Oliver here.
Sorry
I think we couldn't quite hear the question at this end. Could it be repeated?
Yes. With respect to the notion of being a consolidator in Africa, given MEREN's current development and exploration portfolio, can you talk a little bit about what type of acquisition best fits the portfolio with respect to capital outlays or capital obligations, rather, and timing considerations?
Yeah, this is Roger. The type of thing that we would consider, it has to be within the same sort of scope of the assets that we've got. We're looking at significant fields, if you like, in the production phase and not requiring significant development CapEx. If they've got tieback opportunities and small additional CapEx, we would be interested. At the moment, we are not at the sufficient size to take on major development opportunities. The types of assets that are out there are pretty difficult to find. It's not a great big long list, but we will maintain our capital allocation priorities as we look forward. Does that answer your question?
Yes, it does. A question on Akpo Far East. You mentioned it's a short-cycle exploration project that's supported by current infrastructure. Is that a project that if it gets drilled in 2026 as a part of your campaign, it could be on in 2027?
We could only make that sort of call after we see what we've acquired or found, obviously. In all likelihood, it would be a little longer than that. Depending on the flow rates, we would look to make it as a short cycle as absolutely possible. We need to wait and see what the results of the well are before committing to it, obviously.
Thank you.
Our next question is from Teodor Sveen-Nilsen from Fuglemyra Invest . Please go ahead.
Good afternoon, and thanks for taking my question. Three questions from me. First, on cash flow, you said that or you highlighted that you had a strong cash flow year to date, which is definitely true. I just wonder, at which or when in time do you expect to be net debt-free, assuming flat oil prices? That's the first question. The second question is on dividend. This year you're going for $100 million. For 2026, I'm aware that you probably don't have a position to provide any guidance yet, but how should you think around the 2026 dividend? Should that be a fixed amount, a percentage of EPS, or a percentage of cash flow, or any other measure? Third question is on the Preowei development. Could you just remind me of timing for first oil and also the current resource expansion? Thanks.
Thank you, Teodor. I think we'll go to Aldo to answer those questions. First on the cash flows, when do you expect to be net debt-free, assuming flat oil price, Aldo?
Yes, so our current facility will mature at June 2029. That's the current RBL. Of course, between now until June of 2029, we'll always be with some gross debt and repaying down the line. I think the important part is that from the beginning of the year until now, we have reduced the RBL by $270 million. That's the pace of the cash flow that we generate that we are using to pay down debt while keeping the company liquid. In terms of being fully debt-free, it will take time. Actually, our idea is at some point in the near future to refinance the existing facility and keep firepower and liquidity to pursue our M&A and our growth strategy. That's on the cash flow.
In terms of dividends expectation for next year, we have committed to the $100 million base dividend, which is respective of what we get in terms of cash flow for next year. To make any dividend distributions is always subject to the board approval, which will be evaluated at each single time. Considering 2026, the base dividend and looking at oil prices and everything that we see at the moment, we are pretty confident with the continuance of the base dividend policy.
The third question, and for that, we could go over to Roger and Oliver, which is the Preowei development expectations on final investment decision and first oil date.
Yeah, thanks, Shahin. I think, as mentioned on the call, there's ongoing work by the operator, which is very active this year in terms of the front-end engineering and optimization, particularly around the resource size and whether there's potential for a relative increase in resource size there. In short, we expect that work to conclude through this year, and that would present the project for a potential final investment decision next year. You roll forward from there. I think we project a two to three-year development cycle. It's about a 40-km tieback from Preowei to the Egina FPSO. Let's say I'll put oil somewhere in 2029, first oil on that basis.
Could you also just remind us of the net resource potential to MEREN?
Yeah, so the last numbers in our public disclosure, Preowei, from a gross project level, was over 116 million bbl, and then we carry our 16% of that through about 20 million bbl, 25 million bbl of 2P MEREN.
Okay, thank you. That's all for me.
Thank you. As a reminder, to ask a question, please signal by pressing star one. You may also submit your questions via the webcast. Our next question is from David Round from Stifel . Please go ahead.
Sorry, thanks, Roger. Firstly, can you please just talk through the thinking around taking an early break from the drilling campaign in Nigeria? I can appreciate, obviously, giving yourself more time to look at seismic, look at well performance, but are there any specific things you're looking at there? I suppose the lead time between making that decision and what would have been the next well feels fairly tight. The second one again on Nigeria, I mean, you mentioned the wells at Egina and the workover at Akpo. Are you able to give us a sense of the kind of production lift that that could give you in H2, please?
Roger, again. The reason for the effectively the accelerated release of the rig, obviously, it was the operator's decision, and it was the operator's decision that they wanted to further study the 4D seismic to better optimize future locations.
We are in agreement with that. If you've got a 4D seismic, it is important to make sure that it is interpreted correctly to optimize your drilling locations. Sorry, what was the second part of the question again?
I suppose maybe just a follow-up to that is just really, you know, you're pushing this by, let's say, three months or something like that. Does that give you enough time to analyze the 4D?
Yeah. I think, David, it's Oliver here. You know, the rig we're saying would come back probably in 2026. I think it does give us enough time on the operator to go through the 4D seismic there. I will say in the early kind of view of that Akpo in particular, where a lot of the early work is focused, it looks like there's some strong potential there that's coming out of that data, right? Again, on that basis, better to take a short break, go through the data properly, and optimize the wells. I think the next thing to look out for is contracting a rig to come back in 2026 and then drilling Akpo Far East potentially, and then other infill wells, Egina and Akpo. It'll give, you know, it gives that break through the end of the year effectively on the work front. Does that make sense?
Yeah, you're not expecting any big difference between rig rates?
That was a good question. I mean, hopefully, it'll come down, but you know, that's an eternal aspiration. I think the thing to watch for there is in Nigeria, you know, there's not many deep water drilling rigs in the country. I think there's an optimization around rigs being in the country or available and rate. It's going to be a timing versus rate question in terms of getting after the activity with an available rig.
Sorry, the second question, Roger, if you need me to repeat it, was just in terms of the wells at Egina and the workover at Akpo, if you're able to give us some sort of context about sort of how material or whether we could see a production uplift from those activities in H2.
The wells are on now. All I can say is that we are clear, at least with the results, particularly the last well, which has resulted in an increase, if you like, on what we actually initially anticipated. It won't materially affect the outturn for the year. As you note, we've guided to a very tight production outturn range. We tightened it up because we do have confidence post the results of those two wells.
Okay. Great. Appreciate it. Thanks, Roger.
Thank you. It appears there are currently no other questions in the phone queue. At this time, I'd like to hand the call back over to Mr. Shahin Amini for any webcast questions. Over to you, sir.
Thank you. We do have a question with three parts from one of our institutional investors. I'll start off with that. First part is, has the timeline for the Namibia FID, so this is the Venus project FID, changed previously early 2026 and 2025? I'm actually going to put that to Oliver to answer.
Yeah, thanks, Shahin. I think the short answer is it hasn't changed. I think what's important to note is that a significant degree of front-end engineering work is ongoing this year. We expect that work to conclude towards the end of the calendar year, the end of 2025. I think there's potential for that FID to be in 2025. As we said on the call, the planning case is in early 2026. Either way, it doesn't change the prognosis, particularly to a first oil around 2029. It's a three-plus-year cycle time.
Thank you, Oliver. The second part of that question, I'll put that to Aldo. Could you please comment on your hedging position for the second half of this year?
Yes. As we also noted during the call throughout the financial statements and the MDNA, for the remainder of this year, we expect to lift 6 million bbl of oil spread throughout six liftings. Two of those we have already lifted at the beginning of July. Out of those six cargoes, three of them we have hedging a floor price of $64.50 per barrel on average. We have two other cargoes also already fixed for the first quarter of 2026 at an average price close to $63 per barrel. In the next nine months, we have quite a good part of our production hedged, but the other part of it, around a little bit more than 50%, is still exposed to oil price upside.
Thank you, Aldo. The third part of the question, and I'll open up to all three of you, is obviously we've talked about the Preowei, but if we could elaborate more on the project optimization work that's been carried on on the project so far, and any other hurdles towards the final investment decision. Oliver, do you want to tackle that first?
Yeah, thanks, Shahin. I think, as we touched on, and I think in the prior question, to start with the subsurface, there's work going on around a recoverable resource. It's early days, but that looks like there may be an increase to a degree in the recoverable resource, which will obviously help the economics of the project. On the back of that, you follow the flow. There's an optimization then through the FEED process, the front-end engineering design of the subsea tiebacks, so number of wells and scope of that tieback. I think it's incremental work. There was significant work done on this project previously, so it's incremental and adding to that and optimizing the current development scenario. We think that work will play out through the end of this year to lead to a potential FID decision next year.
Thank you very much, Oliver and Aldo and Roger. Next question, I'm going to put to Aldo. It is to do with financing and are there any plans to do a refinancing of the RBL facility? If yes, what are the plans and what is the outlook for that? Aldo?
Yeah, thanks, Shahin. As I've briefly mentioned, I think the idea, and we have been doing that for a decade now, and it's quite usual with this kind of structure, is that every two to three years you start looking at potential refinancing opportunities for an RBL. As we get closer to the low-life, the maturity of the facility, our borrowing base starts to be comprised or constrained by the low-life coverage. The idea would be to evaluate several options. We are not fully focused on only one single alternative. We are exploring a portfolio of alternatives and trying to identify, you know, which one or a combination of alternatives would fit in our company business plan and our company strategy. We'll go through these options in the near term and then decide which one is more appropriate for the business and the company as a whole going forward.
I think the good thing on that side is that we are not, you know, due to our strong liquidity, in a rush to take any of these refinance opportunities and we're able to evaluate the appropriate and the best strategy for the company. We have time to do that, not compressed by any liquidity in the near future.
Related question to do with the RBL facility, the existing RBL facility, we have talked about this liquidity headroom on the RBL. Can you elaborate? What does that actually mean?
Yes. When we talk about liquidity headroom under the RBL, it's just the difference between the borrowing base that we currently have available under our facility and the amount of the RBL that we have currently drawn down. To give you an example, at the end of the first quarter, our borrowing base was $634 million, while we had drawn down at that point only $540 million out of debt. We had an undrawn part of the facility of $94 million, which is what we are calling the facility headroom. This money is fully available to the company if we wish to draw it down again up to the constraints of the borrowing base.
Thank you, Aldo. A number of technical questions here. Actually, one with Preowei, that's an easy one to tackle. What is the expected share of production from Preowei? I can quickly tackle that. On the presentation slides, we have indicated a peak production rate of 65,000 bbl of oil per day, gross field basis, and net to MEREN, that would be around 10,000 bbl of oil per day. Next question is on Olympe- 1X. This is in Namibia, Block 2912. Oliver, any thoughts on when that could potentially be drilled?
Yeah, I think, as we said, we've taken a drilling break on the exploration front in Namibia. It's important to put that in context, but in 2024, there were two new 3D surveys covering large portions of the block, and work is ongoing to interpret those and optimize the next prospects to drill. Olympe is a leading prospect, as we said, for that. It's slightly different in that it's the same reservoir play, if you like, but it's a four-way structural closure. It offers a different kind of test, if you like, in the block. Importantly, beyond that, as that work is progressing, there are, of course, several other prospects maturing in there with significant potential as well. I think we'd look to restart the drilling campaign in 2026.
The next question to answer as the work matures is just how many wells is that, because I think there's an alignment across the joint venture to fully explore the block, to fully characterize everything that's in there in parallel with the Venus development. Exact timing confirmed on rig schedules, but it's 2026, and it could be a pretty exciting year in terms of the drill bit there.
Very good. Oliver, a follow-up for you on Equatorial Guinea. Can you give any more color on the farm-down process that's currently underway and what are the aspirations for the company in relation to that effort?
Yeah, we've had the two positions there for a couple of years, and I think it's important to again put context on where we are. We've done a lot of work reprocessing seismic data, a lot of technical and subsurface work to unlock both the blocks, and I think that has matured to a very advanced stage. Both would be described as drill-ready, if you like. We know what we'd want to drill and what that would test. Having got that far over a couple of years, it's been a pretty extensive farm-out process in the sense that lots of companies have shown interest. I think the timing is good in the bigger picture. A lot of people are back, particularly in this basin and the São Tomé side, looking for significant volumes. We hold effectively 80% in each of the blocks.
You go back to our capital discipline, and we would look to drill those at a reduced equity just from a risk-sharing perspective. Also, we've been successful in the last couple of years in attracting kind of a premium, if you like, on these opportunities whereby our capital exposure has been reduced in most cases to zero or at least a very, very small amount for the early phase of exploration and appraisal. I think the year-to-year operations are the same. As we said, we're mid-process. We're positively engaged with several companies, and I think we'll come back later in the year with clarity on both the farm-down position and outcome, and therefore the forward plan for the blocks in terms of drilling and capital allocation.
Thank you, Oliver. Here is the usual question on capital allocation and shareholder returns, buybacks versus dividends. I've got many, many questions. Clearly, from those in the camp who favor buybacks, why aren't you doing buybacks? Do you plan to do buybacks? There are quite a few of those, but obviously we have to put that within the broader context of the total shareholder return program we have. I'm going to hand it over to Aldo first, and then we can go to Roger for his views on this as well. Aldo, yeah, top one for you.
Yeah, no, I think it's a fair question, and we are always evaluating the portfolio of opportunities in terms of returning cash to shareholders and also, while at the same time keeping in mind the strategy of the business and the growth aspirations that we have for the group. We always discuss share buyback. I think if you look throughout this year, we have already distributed $50 million in dividends and around $8.5 million in share buybacks towards the beginning of this year. We are on track and firm on delivering the other $50 million in terms of base dividend. If we go on top of that, that's something we need to continue to evaluate on a quarterly basis. Again, it's an evaluation that we do not only from a capital allocation perspective, not only in terms of distribution, but also as well with regards to the company growth strategy.
Roger, any views on this hot debate, dividends versus share buybacks?
Thanks, Shahin. What I will say is today before yesterday, we had our second board meeting post the amalgamation. I can tell you that it is a rich topic of debate at the board, and it is a topic that comes up when we have investor meetings. Currently, we are going to continue, as we've announced today, with the dividend stream that we've got. As all of you are aware, should we distribute any of the excess free cash flow, we do have the ability to issue a buyback program. This issue, which is the best for the company in terms of returns policy, is debated at the board virtually every single board meeting, so it is right up there. We're continuing with the dividend at the moment, and we will again review it later in the year at the next board meeting.
We're continuing with the dividend as we speak, and we recognize that there is a continual debate on this issue.
Thank you, Roger. Just a question has just come in on the deleveraging, Aldo, that we've done year to date. Obviously, we still have substantial cash on hand. Do you envisage paying back more of the RBL in the near future?
Yes. After the end of the second quarter, we made another repayment, which we have already mentioned in the presentation, of $60 million. Now our drawdown portion of the RBL is around $480 million. We see scope to reduce that portion even further, including in the third quarter, and also more towards the end of the year. We'll continue with that strategy. The amount of cash we saved in reducing interest expense is quite material. We'll continue with that strategy towards the end of the year.
Thank you very much, Aldo. There are no further questions from the webcast, so I'll hand back to the operator and Roger.
Thank you. There are no further questions on the webcast. With this, I'd like to hand the call back over to our speakers for any additional or closing remarks.
Okay, well.
Thank you. This concludes today's conference call. Thank you for your participation. You may now disconnect.