Good morning, and thank you for joining us for Africa Oil Corporation's First Quarter 2025 Results Presentation. My name is Shahin Amini.

I'm Head of Investor Relations and Communications, and I'm joined today by Roger Tucker, our President and CEO; Aldo Perracini, our CFO; 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 on our regulatory filings available on SEDAR+ and on our website. Before we turn to the financial and operational highlights for the quarter, I must also highlight that yesterday morning, we announced a new brand identity for the company following the completion of Prime amalgamation.

This sets us on our way for the next phase of shareholder value delivery and growth. With that, I will hand over to Roger to share more on this exciting next chapter and to walk you through what has been truly a transformative quarter for the company.

Roger, we are ready for you. Please go ahead.

Thanks, Shahin. Following the amalgamation of Prime, I'm proud to officially introduce our new corporate identity Meren, which will take effect on Monday, the 19 of May.

The rebrand to Meren reflects a defining shift in our business. With the transformative deal now complete, we've doubled our reserves and production, taken direct control of Prime's balance sheet and significantly strengthened our cash flow profile.

We've also streamlined our business structure and evolved into a full cycle E&P business, one that is focused, resilient and firmly committed to delivering strong and sustainable shareholder returns complemented by our new enhanced payout policy. This is the right time for the change.

We have a refreshed board a clear long-term strategy and a business that is fundamentally advanced. I'm also pleased to bring aboard Aldo as our new Chief Financial Officer.

Starting 19 of May, our shares will trade under the new ticker MER on both the TSX and NASDAQ Stockholm and our new website mereninc.com, will go live to reflect our updated identity. Please note, this is an administrative change and shareholders don't need to take any action.

Now let's turn to the highlights of our first quarter 2025. Moving to Slide 5.

I'm pleased to report a strong quarter, reflecting continued momentum across our operations. We have maintained a strong balance sheet with significant liquidity headroom.

We have continued to benefit from robust high netback production and benefited from premium Brent pricing. Our infill drilling program targeting short-cycle, high-return opportunities continue to support strong and reliable production.

During the quarter, we lifted five cargoes out of the 12 expected for the year, achieving an average realized price of $79.5 per barrel, beating the average Brent price for the same period. This front-loading of cargoes at higher oil prices has significantly reduced our oil price exposure for the remainder of the year.

The strong performance across our producing assets have enabled us to proactively reduce leverage and deliver on our plans for shareholder returns. During Q1 2025, we declared our first quarterly dividend of $25 million, and I am pleased that we have now declared the second quarterly dividend of $25 million for distribution next month.

We ended the quarter with $428.4 million in cash and a net debt-to-EBITDAX ratio of just 0.3 times, a clear demonstration of our financial strength and disciplined approach to capital management. Altogether, this strong start to the year underscores the core strengths of our business, high-quality producing assets, a strong balance sheet and a focused strategy centered on delivering meaningful sustainable returns to shareholders.

Now let us take a closer look at production performance for the quarter by moving to Slide 6. Looking over the past year, it is encouraging to see that our infill drilling is performing well with Q1 2025 production down only about 2% compared to Q1 2024.

The infill drilling program provides us with attractive short-cycle and high-return investment opportunities as we counter natural field declines. Average Q1 2025 working interest production of 33,400 barrels of oil equivalent per day was above the higher end of our full-year guidance.

At Akpo, strong delivery continued through the quarter with the Akpo West Wells producing above expectations and supporting steady volumes. We are planning additional activity in Q2, including a development well and a well intervention to sustain the momentum and manage natural decline.

On Egina, drilling resumed in January and led to the successful completion of two new production wells, both are expected to come on stream in Q2 and will contribute to the stable production levels going forward. Operational uptime and efficiency at Egina remain high, supporting reliable delivery.

Agbami performed in-line with expectations with compressor maintenance completed as planned in the quarter. This is part of our broader strategy to maintain long-term asset integrity.

Overall, our Q1 results demonstrate the strength of our core assets that continue to deliver reliably and also present further upside potential, such as the Akpo Far East well, which I will cover later in this presentation. With that, I will now hand over to Aldo for the financial highlights.

Thanks, Roger. Moving to Slide 7.

In the first quarter, Prime completed 5 oil liftings with total sales of approximately 5 million barrels at an average realized price of $79.5 per barrel. This compares favorably to the average dated Brent price of $75.7 per barrel, reflecting continued strength in our marketing and sales strategy.

Looking ahead, 7 cargoes remain scheduled for the balance of the year. Of these, four have already been triggered at an average dated Brent price of $64.5 per barrel, while the remaining 3 cargoes are currently unhedged.

The combination of achieved sales in the first quarter and forward pricing on upcoming liftings has materially reduced oil price risk for the year. As an illustration, even if Brent were to average $50 per barrel from the second quarter through the fourth quarter, the full average dated Brent price is expected to be approximately $67 per barrel.

That give us a solid platform for growth cash flow generation through 2025, regardless of the near-term oil price environment. Let's move to Slide 8 for a look at our financial headlines.

First, let me remind you that the Prime amalgamation was completed on 19 of March. So Africa Oil's reported results are a hybrid between the periods from 1st of January to 19 of March and then through to the end of March.

So for example, our reported revenue for the quarter is only for one cargo that was listed post 19 of March, this was for $76 million. In our press release and MD&A, we have presented reconciliation tables to present summary income statement and cash flow statement as if amalgamation has been completed on 1st of January 2025.

I think it is important to focus on EBITDAX and cash flow items for the period on a consolidated basis, as if amalgamation has been completed on 1st of January 2025, in order to get a better feel for the performance of the underlying assets in our business. For the first quarter, we recorded an EBITDAX of $142 million and cash flow from operations before working capital adjustments of about $100 million, which compares to capital expenditures of about $28 million.

Our free cash flow before debt service and shareholder returns was actually higher at approximately $122 million, which included a $32 million receipt from our investment in Impact and the repayment of a loan of African Energy for $4.5 million. Looking ahead for the second quarter, will be the first quarterly period that we will report fully consolidated financial results and the reporting will be more straightforward.

Let's move to Slide 9 for a closer look at the cash movements during the period. Turning to cash management.

We closed the quarter with a cash balance of $428 million, up significantly from $61 million at the end of 2024. This is mostly driven by the amalgamation of Prime, which added $380 million in cash on completion of the deal.

It highlights the immediate financial benefit of the transaction and puts Africa Oil in a much stronger liquidity position to support shareholder returns and to deliver on our strategic objectives. During the quarter, we also received $60 million in distributions from Prime on the closing of the amalgamation and $32 million from our investee company Impact.

Given our strong liquidity position, we decided during the quarter to proactively reduce our RBL debt balance and pay down $130 million to take the outstanding balance down from $750 million to $620 million and reduce interest cost. We continue this approach by making another repayment of $80 million post the end of the first quarter.

Share buybacks remain an important capital allocation option for the company. And during the quarter, we executed $8.3 million in share repurchase before pausing the program in March on completion of the Prime deal and implementing the new capital allocation framework.

Our shareholder return policy under this framework is to distribute minimum of $100 million per year in base dividends. As always, future dividend distributions and share repurchase are subject to customary consents and approvals, including board approval.

Overall, the first quarter reflects disciplined cash management reinforcing our financial strength and provides a solid platform to deliver long-term value to shareholders. Let's move to Slide 10 for a quick look at our net debt and balance sheet strength.

As part of the Prime amalgamation, we have taken on the revolving RBL debt facility that provide us with liquidity at very competitive costs. We also gained solid relationships with a group of supportive lenders, which is a strategic advantage for us.

As already mentioned, we have proactively repaid the outstanding balance to reduce interest payments. But if the need arises, there is scope to draw down under the available borrowing base.

For now, deleveraging is a priority for us. We are also taking steps to cancel Africa Oil's undrawn standby corporate facility with a current availability amount of $65 million.

This was an important credit line for Africa Oil before amalgamation as there was a degree of uncertainty over the timing and quantum of Prime dividend distribution, and this provide important liquidity headroom. However, as we now have full control of the Nigerian business, this facility is no longer required, and we will save around $2 million in standby fees by canceling it.

This is another positive benefit of the Prime consolidation and highlights the cost synergy aspects of the deal. At the end of the first quarter, our net debt stood at about $190 million with an estimated net debt to EBITDAX of 0.3 times.

This is significantly below our maximum target of 1x and underscores the strength of our balance sheet and our capital allocation optionality as we look to execute our business strategy. On a final note, I want to share with you that the borrowing base availability amount is driven by the lower of the two cover ratios.

These are project life cover ratio and loan life cover ratio. In our case, the project life cover ratio is that driving the borrowing base, and therefore, there is scope for increase once we move into a refinancing exercise.

I will now hand over to Roger for the next slide.

Thank you, Aldo. Now let's turn to the operational outlook for our Nigerian assets.

We are committed to maximizing value from our three deepwater producing fields in Nigeria, working closely with our joint venture partners through a disciplined program of drilling optimization and strategic investment. At Egina, 2 producer wells were successfully drilled in the first quarter and are expected to come on stream in the second quarter, helping to support production volumes in the near-term.

At Akpo, a well intervention and development well are scheduled for the second quarter. Looking ahead, the JV is planning a pause in the drilling campaign during the fourth quarter of 2025 to allow time for detailed interpretation of new 4D seismic data and recently drilled well results, enabling us to mature and prioritize future infill targets with greater precision.

In parallel, we're preparing to spud an infrastructure-led exploration well on the Akpo Far East prospect with estimated gross field resources of 100 million barrels of oil equivalent and a projected cost of approximately $50 million. This well has the potential to add significant reserves and deliver near-term production through existing infrastructure, if it is a success, of course.

At Agbami, a full shutdown is planned for the fourth quarter as part of a wider maintenance program aimed at sustaining long-term performance. Interpretation of 4D seismic data is ongoing to shape our next drilling phase, and we are progressing rig and equipment contracting ahead of the 2027 infill campaign.

And finally, at Preowei, seismic analysis continues to help derisk the upside resource potential. We've also reengaged our FEED contractor to explore ways to optimize the development and execution costs ahead of a future investment decision.

I will now hand over to Oliver for a discussion on the outlook for our assets in the Orange Basin and Equatorial Guinea.

Thank you, Roger. Now let's move to Slide 12.

Offshore Namibia, the JV partners on Block 2913B and 2912 have continued the work on 2 fronts. On the first front, work continues to progress the Venus development project towards final investment decision, which is expected during first half of 2026 and with potential first oil in 2029.

The operator is guided to a development scheme with up to 40 subsea wells, all tied back to an FPSO and with a peak capacity output of 160,000 barrels of oil per day. Once online, Venus has the potential to produce for greater than 20 years and as such, will deliver a long-term sustainable cash flow to the company.

The second front in Namibia is the follow-on exploration activity on the blocks. The third campaign with the drilling of the Tamboti and Marula wells completed in May, with the results now being studied ahead of anticipated further exploration drilling in Q4 2025.

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 4-way structural closure and as such, presents a different prospect to the stratigraphic traps of Venus and Marula.

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 the costs, exploration and development will be carried through to first commercial production from the 2 blocks. Staying in the Orange Basin, but moving to South Africa, last September, we were granted an environmental authorization for the drilling of up to 5 exploration wells and the remaining regulatory process is continuing to move forward at pace.

With that, we currently expect to see the first exploration well on Block 3B/4B in 2026 and note the operator has identified Nayla, a prospect located in the northwest of the license area as a potential first drilling target. In terms of capital spend, we are also carried for 1 to 2 exploration wells through the farm-down deal that we closed last year with TotalEnergies and Qatar Energy.

Now turning to Equatorial Guinea. We continue to progress discussions with potential partners on Blocks EG-18 and EG-31 with the aim of completing the farm-out process by the end of Q3 this year.

These blocks offer a compelling mix of opportunities. On EG-18, we've identified a large Cretaceous age basing floor fan prospect geologically similar to plays we are pursuing in Namibia and South Africa.

Meanwhile, EG-31 lies in shallow water, close to existing LNG infrastructure and contains several gas-prone prospects with clear commercial short-cycle development potential in the success case. If we are successful in securing farm in partners and subject to the necessary approvals, the newly formed joint ventures could look to drill as early as late 2026 or into 2027.

I think critically, and as always, we remain disciplined in our approach to exploration capital, and we will not proceed with exploration drilling on a sole risk basis if we're unable to farm down on acceptable terms. We'll now move to Slide 13.

And this is a slide that we've shown in several quarter results recently, but we want to reiterate our capital allocation framework, which hasn't changed, and in particular, reiterate our disciplined approach that underpins our business plan and therefore delivery of our long-term strategy. At the heart of this is a prudent balance sheet management, sustainable leverage and a strong commitment to shareholder returns.

As part of that, we're maintaining a minimum liquidity of $150 million and keeping net debt-to-EBITDA below 1 times, 2 key metrics that will guide our approach to financial discipline going forward, both of which have been met in Q1. We've also significantly increased our base dividend to at least $100 million annually, sending a clear signal of confidence in our outlook and the quality of our cash flow generation.

The base dividend level continues to reflect our commitment to striking the right balance between delivering meaningful and consistent returns to shareholders today and equally investing in future growth to drive long-term value in the business. Our approach balances strong shareholder returns with funded growth, such as our exposure to the carried Venus development in Namibia.

With a streamlined business structure, strong liquidity, and the completion of the Prime transaction, we are now in a great position to selectively pursue new opportunities focused on producing cash generating assets and as we always reiterate, within strict strategic financial and operational criteria. Thank you.

And I'll now hand you back over to Roger.

Thank you, Oliver. It has been a great start to the year for the company.

We closed the Prime deal that has doubled our production, significantly raised our cash profile and given us greater financial resilience. We have paid a dividend of $25 million, the first tranche of our newly enhanced payout policy under our new capital framework, delivering on our commitment to our shareholders.

With our robust liquidity position, high-margin production and fully funded organic growth pipeline, we believe we offer a compelling balance between delivering shareholder value and pursuing sustainable growth. Our business is built on solid strategic foundations, and we are well placed within the independent exploration and production space to capitalize on emerging opportunity.

Thank you very much for your attention, and let's open up the Q&A session.

Good morning everyone. Thanks for taking my questions.

A few questions from me. First on production costs going forward.

I understand that there was more overlift in Q1 such that the production cost this quarter also or Q1 also reflects that overlift. I just wonder if you could guide some on the expected production costs on a consolidated basis going forward.

Second question I had is on Venus, promising to see that progresses. So I just wonder when should we expect an updated resource estimate from the operators?

Should we expect anything around FID? And my last and final question that is, what's your current production, i.e., in period after end of Q1?

Thanks.

Thank you very much, Teodor. So your first question on production costs, Aldo, do you want to have a first stab at that, please?

Yes. So there are two things.

One, in the first quarter you can see that we had a slightly higher production cost. Those are comprised of some one-off costs that were incurred in the first quarter of the year, mainly in relation to a planned maintenance in the Egina FPSO, and the GTC overhaul in the Agbami FPSO.

Towards the whole year, we expect to achieve similar production costs than previous period with the exception that we have this turnaround maintenance in Agbami towards the end of the year, which we will then incur in additional production costs in relation to that maintenance. But on a running business basis, we expect just a slight increase compared to the previous period.

And the next question from Teodor was -- and also could put this to Oliver. In terms of an updated resource -- reserves report on Venus, can you share any news on that?

Yes. Thanks.

So I think if we take a step back on the project time-line, I think the first observation, which is not new, is that it's got 4 wells on Venus. So we regard it as fully appraised.

So there is no more drilling to be done to tighten resource numbers, if you like, at this point. The project has therefore moved into pre front-end engineering and design, which is, as you'd expect, that will move through kind of into the front-end engineering design itself and then into a final investment decision, which, again, we said we anticipate early in '26 with some optimism that, that might come forward, but planning purposes that's in '26.

So within that frame, I think there is a couple of components in terms of news flow and how information will come out. I think the most important is setting those milestones in the project.

So FEED is obviously in this environment, critical from a final cost perspective, so you can kind of understand the final economics of the development. And of course, to the question underpinning that is resource level.

So I think what we anticipate is that as we mature through FEED, those resource numbers will become more widely known. I think it is fair to say that TotalEnergies is a large-scale company doesn't typically release those early in the project cycle.

So I think it's something we'll look to move towards this year, but they will -- in terms of the release, will go in tandem with the project maturation through to FID.

The third question was on the current production. And Teodor, I think your question was what was like the exit rate for Q3 -- sorry, Q1.

Basically, on that basis, I mean, we've got to be quite careful because if you just look at one particular week, there can be variations. But we are probably -- based on the data I have in front of me, we are probably looking around 32,000 BOEs per day on a working interest basis.

But again, there can be variations on that. It is important to emphasize that production is in line with our expectations.

And as we have reiterated in our financial reporting, the full year guidance remains unchanged. I'm going to come back to you to see if you have any follow-on questions.

Just back on the production cost. It's a fair estimate $60 million approximately per quarter IFRS production cost, as you may know over or underlift?

Can you repeat that number again, please?

$60 million per quarter. Is that a fair estimate?

It is a fair estimate. And yes, I think that's probably on the conservative side, but a fair estimate.

Okay. Perfect.

That's all from me.

Thank you very much. Have a great weekend.

Great to hear from you.

Thank you very much. We do have quite a few questions submitted e-mail and webcast.

And we're going to go to Aldo on a number of questions regarding the Q1 numbers. The first one is actually on the guidance.

It says, you have reaffirmed guidance based on Brent price of $75 per barrel. That's the full year average price.

And yes, Brent is trading at around $65. How long would Brent need to continue to trade at these lower levels before you amend guidance?

Thank you, Shahin. Yes, we have provided the sensitivity to our cash flow from operations guidance to look at lower average oil price of $65 per barrel.

So considering that the first five cargoes lifted throughout the first quarter of 2025, we achieved an average sales price of $79.5 per barrel. And then 4 cargoes out of the 7 liftings we expect for the rest of the year are hedged through a fixed date Brent of $64.5 per barrel.

Therefore, even if we had Brent at $50 per barrel, for example, for the remaining three unhedged cargoes, we would still achieve a full year average price of $65 per barrel. So that considering the average price of $67 and the sensitivity we have provided with our guidance, we would still expect to achieve and be within the guidance for cash flow from operations.

Thank you. Second question again on the financial statements.

We reported production cost of $51.2 million, and that is for the period from 19 of March to 31st of March. Why was this so high for that short period?

Okay. And I think it is important to remember that we are still reporting, the first quarter is still considered equity pick-up from 1st of January to March 19 in relation to the investment in Prime and the closing of the merge, the completion of the Prime deal.

So the cost of $41.9 million relates only to the period from 19 of March to the end of March. So that's the variation of the underlift -- under and overlifting position throughout the quarter.

So the adjustment of $41.9 million reflects the difference between the cargo that we lift post-amalgamation and the average production for that period.

And the follow-on related question is when will you start reporting fully consolidated reports and stop the equity method of accounting?

We stopped doing that from 19 of March. yes.

And for the next quarters, we expect the constructed numbers to look the same as our underlying financial number, Shahin. So that will go away from the second quarter onwards.

So it will be a lot more straightforward. The equity method is behind us.

It would be a lot more transparency, which was one of the strategic reasons and rationale for doing this deal.

That is correct.

We'll see that. Thank you very much, Aldo.

A couple of questions on Orange Basin, offshore Namibia and South Africa. If I may I want to put those to you, Oliver.

The first one is, what do you make of TotalEnergies' recent engagement with the Namibian authorities supposedly around fiscal terms?

Yes. I think we -- of course, we saw those reports in the media.

So I think we are not surprised by that. This is a very large scale project.

It's the first -- I think it will be the first project, deepwater project in Namibia. So it is a strategic importance to the investors, but of course, to the country as well.

So I think we are reassured to see that the TotalEnergies' CEO was actually in Namibia, met with the President and other ministers, which is a really important sign of importance of the project. I think within that, and I think the statements that were attributed there were around it is very deepwater depth 3,000 meters.

We're clearly in a macro sense, the world is more challenging than in price terms than it was last year. So I think it's natural that there'll be engagement around the fiscals and ensuring that the project is designed with those circumstances in mind.

So I think the commitment, the visit and some of the statements made very, very encouraging for the pace of the project.

Excellent. Thank you very much, Oliver.

Actually another follow-on question on 3B/4B, which is the South African side of Orange Basin. In terms of the timing for potential first exploration, well, any thoughts you can share on that?

Yes. I think firstly, our guidance remains 2026 is our planning assumption.

And I think we covered it in the presentation, but we're in the midst of the environmental regulatory permit process. So a permit has been issued to drill up to five wells on the block, which is good.

And there is, of course, a challenge process in South Africa, and we are going through that challenge process now. So there's a couple of milestones coming up this year, which I think will point to the ultimate timing of the well.

But for planning purposes, we remain focused on 2026 with the operator.

Thank you very much. Roger, a couple of questions on strategy.

So this is to you. With the recent volatility in oil and gas prices, are you seeing more opportunities?

Or do you see the M&A market changing in response?

We are not seeing anything material at the present time. But our strategy remains the same that we'll be extremely selective in what we go for.

And actually, we are in no rush at all. We don't need to rush into anything.

But we haven't noticed a significant change in the market landscape thus far.

And what are your criteria for the right M&A deal for the company?

It has to be accretive to shareholders. It also I think, as I've said many times before, we are an organization which is driven from the rocks up rather than the spreadsheet down.

So if we do anything, it has to be into an asset that actually matches the existing portfolio that we have got. And if we do anything, it will be into a high quality asset.

Very good. And in terms of regions, production of oil versus gas, operator versus non-operator, offshore versus onshore?

Obviously, with the name change Meren, there is a sort of an implied opportunity there that we're not necessarily going to be focused uniquely on Africa, and we are not necessarily going to be uniquely focused on oil, and the fundamental thing is that we will maximize all of the information and contacts that we have got. And we do have some significant additional contacts via the relationship with the shareholding of BTG within that Latin American region.

We've not made any decision to move anywhere. And with the management team that we have got, we would indeed consider potentially taking an operatorship if it was exactly the right opportunity.

And you mentioned of BTG Pactual choose invariable with the next question, which is what level of engagement you have with BTG? What are the objectives?

And is there strategic alignments considering that they are largest shareholder in Meren?

Well, we've obviously worked with BTG for five years or so in the Prime asset. So -- and you'll note that both Huw Jenkins and Edwyn Neves were on the Prime Board.

So we know these people extremely well. And it is a relationship that's been built over a five-year period.

Obviously, if you're going to do a transaction such as this, you have to have a shared vision for what the world offers and how this sector is going to evolve. And they indeed do have a similar view of the way the sector will evolve, and we look forward to attempting to grow this vehicle alongside our key cornerstone investor in BTG Pactual.

Thank you. Question for Aldo.

You still have a significant cash balance despite the repayments in Q1. Why have you not paid down more of the RBL facility?

Yes. We also noted, Shahin during the discussions that we have made the second payment to the RBL in the post the end of the first quarter.

So bringing down the current drawdown to $540 million. And as part of the Africa Oil Prime integration, we are reviewing the group structure cash and the cash management activities of the group, including the working capital requirements at the different subsidiary levels.

The idea is to find the most tax-efficient way to move the cash where it is needed. Continue to pay down debt to reduce interest expenses remains a priority for us, and we will balance that with the appropriate cash manage as we go.

And as part of our new capital allocation framework, there is the statement about the scope for supplementary dividends and/or share buybacks. Aldo, would you mind share your views on that from a high level?

Yes. As part of the amalgamation of Prime, there was a policy that was agreed and makes part of the overall strategy of the group, and that remains unchanged, and that remains a policy that we will follow as we go.

The distribution of the 50% annual free cash flow net of the base dividend remains a part of that policy. So there has been no change to the policy.

We will consider throughout the year the free cash flow and the numbers as we move. We need to understand how the numbers will perform in the following quarters of the year, and we will have active discussions within the management team and with the board on how and if we would make additional distributions.

So we need also to take into account always debt repayments, interest expenses and other needs of the group going forward. So we will consider the policy carefully, as we go and will always be subject to the board discretion.

Excellent. Thank you.

Let's turn back to Oliver for a number of questions, and that is on Equatorial Guinea. Can you share your thoughts on how the process is -- this is our farm-down process for the 2 blocks offshore Equatorial Guinea, what is the likely time line before there could be material update for the market?

Yes. So the farm down process is ongoing for the 2 positions we own there, which are very different, as we described in the presentation.

So you have EG-18, which is a very, very large deepwater basin floor fan, similar to much of the prolific oil discoveries along West Africa. And in the shallow water, you have EG-31, which is a gas focus, which is actually very, very short distance from the EG LNG facility, which we believe has a reasonable hologenic for any gas project.

So two very different things. But in short, we're in the process of running a farm-down process to bring in partners for both.

We currently have effectively an 80% participating interest in the licenses and we'll be seeking to bring at least one partner in for a material piece of equity. I think there is -- if you start particularly with deepwater large scale, I think it's a particularly interesting block technically.

But further than that, of course, what we are seeing in the market despite some of the short-term headwinds is a lot of the larger E&Ps and the majors actually seeking to grow and extend their reserve space. And that's a trend that's obviously changed in some cases in the last few years.

But therefore, we're seeing quite a lot of appetite to review the blocks. In terms of timing, there is always a balance between getting lots of people through the process and ensuring that people that you think are kind of credible, frankly, from an execution perspective.

And so we will look to close it somewhere through the third quarter, fourth quarter this year so that we end the year with a clear position on the blocks. As we said in the presentation again, this is exciting and interesting and potentially high reward.

But again, it goes back to our capital discipline in the sense that we will not allocate significant capital to frontier exploration. Doesn't mean we don't believe in it.

It means we are being disciplined on the spend.

Okay. Very good.

You were the points man for our successful farm-down of Block 3B/4B last year. Since then, obviously, we've seen more volatility in the market.

Have you seen any differences since doing that deal last year?

I think you almost have to make a differentiation with the Orange Basin. So I think it remains a very, very exciting basin.

It remains very early days. Of course, we've seen multiple discoveries, including those that we are involved in.

So look, I think the appetite for South Africa is large in the sense that the Orange Basin is untested in South Africa. But of course, almost 2/3 of the basin actually sits within South Africa.

So I think we're seeing strong appetite for the basin. I think from our perspective, we are very happy with our position because, of course, we've got Namibia, costs fully covered to first commercial production.

And in South Africa, again, we would hope to get through 2 exploration wells in that block without any capital commitment. So I think very happy with that position.

And again, the next 12, 18 months, pretty exciting actually in terms of getting results there.

Okay. And though, as you said, Orange Basin is very exciting.

There was a recent success Rhino. One of the questions we have received is, is this Rhino discovery has any implications for what Africa Oil or our partners may be doing in the basin in the near-term or longer-term?

Well, look, it is always nice to see success in the basin for yourself or someone else. I think no surprise that discoveries continue to be made, there is a prolific source rock, prolific reservoir system here.

So I think we'll see more, which is great for Namibia and hopefully, South Africa. Again, from our perspective, I think we are very, very glad to be partnered with -- through Impact with TotalEnergies and QatarEnergy and Venus because that is moving at pace to first oil.

And of course, while exploration success is very exciting, it is the production cash flow that we look forward to. So great for the countries, but I think encouraging for the basin.

But in our perspective, again, very happy with the portfolio we're investing in.

Okay. Very good.

A couple of questions on the dividend distributions. One is, can you maintain the dividends at current oil prices?

Or could there be discussions around lowering the payout if this lower oil price persists? And would you consider inorganic growth if there are interesting opportunities arise in this oil price scenario?

So I think first, if we go to Aldo to share your views and perhaps, Roger, you want to add some thoughts on that as well.

All right. In terms of the dividend payments, we have -- we are comfortable with the $100 million dividend payments on an annual basis.

And you can see we have declared the second dividend to be paid in the next 30 days or so. So considering our hedging strategy, considering the strong cash flow coming out of Nigeria, we are still committed to distribute $100 million on an annual basis, Shahin.

Very good. And Roger, the question then had a second part which was lower oil prices and opportunities in the M&A.

I suppose that is a benefit for someone with our strong financials.

Possibly, yes. I mean the -- not all owners of assets have the same balance sheet as us, but we've not seen any significant change in what's happening in the market.

And I think that the effect of the prices that we are seeing at the moment, not all companies believe that this is going to continue for an awful long time, and it needs to shake out a little bit. We're in a position of flux in the market at the moment.

But we are not rushing into anything at the moment.

Okay. And there's a question – there is an investor asking whether we can give a long-term schedule of the quarterly dividend in terms of record dates, payment dates and so on.

Aldo, I suppose that's not practical because every single dividend requires board approval. Is that correct?

That is correct. And we're also subject to the minimum amount of days under the stock exchanges that we need to comply with, Shahin.

So, yes.

But it's fair to say that we are as -- well, certainly, our plan is to continue doing a quarterly distribution, which would line up quite well with our quarterly reporting.

That is correct.

Very good. Well, I don't see any questions on the line.

I think we – there is no one else on the line, and we have kind of exhausted the questions from the webcast as well. So I will now hand over to the operator to conclude this presentation.