Meren Energy Inc Aktie

Hello, everyone. My name is Michelle, and I will be your conference operator today. At this time, I would like to welcome everyone to Meren Energy's Third Quarter 2026 Results Presentation. [Operator Instructions] This event is being recorded, and the recording will be available for playback on the company's website.

I will now pass the meeting to Mr. Shahin Amini. Please go ahead, Mr. Amini.

Hello, everyone. Thank you for joining us today for Meren's Third Quarter 2026 Results Presentation. My name is Shah Amini. I'm Head of Investor Relations and Communications at Meren. And I'm joined today by Oliver Quinn, our President and Chief Executive Officer; and Aldo Perracini, our Chief Financial Officer. We will begin with prepared remarks and then open the floor to questions.

Before we get started, I will remind everyone that remarks made during this session are subject to forward-looking statements, which involve significant risk factors and assumptions that could cause actual results to differ materially. More detail on these risks can be found in our regulatory filings on SEDAR+ and on our website. The information discussed is made as of today's date and time, and Verint assumes no obligation to update or revise this information to reflect new events or circumstances. The company's complete financial statements and related MD&A are available on the company's website and SEDAR+.

With that, I will now hand you over to Oliver. Oliver, please go ahead.

Thanks, Amini, and thanks, everyone, for joining us today. Q3 demonstrates strong continued execution on our strategy with production tracking at the upper end of our revised guidance range. Net debt is down to $185 million, remains at 0.5x EBITDAX, and we ended the quarter with around $328 million of liquidity. We've also declared the fourth $25 million dividend of the year, taking distributions in 2026 to $100 million and to around $200 million since the Prime amalgamation in 2025.

Maintaining a strong financial position is important as in the short term, we now commence a period of capital investment from Q4 and into 2027. At Akpo and Egina, a drilling program will commence shortly in parallel with a vessel-led well intervention campaign and a rig is planned to return to the Agbami area in the first quarter of 2027.

So as we head towards year-end, we move into a phase of new activity that will support the existing production base, whilst in parallel, we have renewed momentum around the maturation of the significant discovered resource base around our existing infrastructure. I'll come back to the key milestones and what they mean for the production outlook later in the presentation.

Turning to guidance on Slide 5. Production remains on track and the financial outlook has further strengthened. We've narrowed working interest production guidance to 25,000 to 27,000 barrels of oil equivalent per day and entitlement production to 29,000 to 31,000 barrels per day. We're also raising EBITDAX guidance to a range of $390 million to $440 million and cash flow from operations to a range of $250 million to $280 million.

Higher realized oil prices are clearly part of that, but the assets have also continued to deliver. Capital investment is now expected to be $70 million to $90 million in the year. That reduction is mainly operational timing, so the associated spend moves into next year as the activity phasing is finalized. So overall, we expect to finish 2026 with stronger cash generation and substantial liquidity ahead of a much more active investment program in the organic portfolio across the next few years.

Moving to Slide 6 and Q3 production performance. We averaged 25,300 barrels oil equivalent per day on a working interest basis and 28,300 on an entitlement basis. The trend through the year largely reflects the planned pause in drilling and natural decline. That pause is used to reinterpret the latest 4D seismic and improve the selection and sequencing of the next well activity and as such, has derisked the upcoming program significantly.

The intervention program is getting underway and the Akpo and Egina drilling campaign is expected to begin this month, starting with the Akpo Far East near-field exploration target. I'll go through the drilling program in more detail later in this presentation. But the key point I'd like you to take away is that the operationally quiet period is behind us, and we're now entering a sustained period of activity across the portfolio.

I'll hand over to Aldo to take you through the financials.

Thank you, Oliver, and hello, everyone. We lifted two cargoes in Q3 at an average realized price of $92 per barrel, representing a premium of around $6 to Dated Brent across July and August when the cargoes were lifted.

With the legacy trigger price forward sales arrangements now behind us, our cargoes are priced in line with the Dated Brent shortly after the lifting date. We also continue to benefit from the amended Akpo and Egina gas sales agreement. Gas revenue was $12 million in Q3 compared with $4.5 million a year ago.

On hedging, we recorded a $35 million loss on commodity contracts in the quarter, of which $13 million was related to settlements during the period with the balance a noncash mark-to-market of open positions at the end of the quarter as oil prices rose. The purpose of the program is to provide visibility of cash flows to support our capital allocation priorities.

For 2027, we have collars on a portion of our production with floors of around $70 per barrel and upside to around $93 per barrel. So the approach is about balance, providing visibility of cash flows that underpin our investment plans while maintaining exposure to stronger oil prices.

Turning to the financial highlights. In Q3, we generated $113 million of EBITDAX and $74 million of cash flow from operations before working capital. This demonstrates the strong cash flow generation of the business, driving a revision in our full year guidance. Capital investment was $14 million in the quarter. With the PML 52 rig now expected in Q1 2027, part of the planned spend moves into next year and guidance has been revised to reflect that.

This reduction reflects the timing of activity with investments stepping up as the drilling campaigns progress. We generated free cash flow of $59 million in the quarter and $77 million year-to-date. Operating costs averaged around $16 per barrel in the first nine months. Q3 was higher, reflecting the timing of routine maintenance and nonrecurring operator personnel costs. That supports strong margins and keeps the business resilient across the oil price cycle.

Turning to cash movements for the third quarter. We began the quarter with $78 million of cash and our operations generated a further $73 million. We invested $14 million back into our assets and returned $25 million to shareholders through the dividend. We also drew $41 million under the RBL to manage working capital across the business.

As a result, we ended the quarter with $146 million in cash, which puts us in a strong position as investment activity picks up. Our capital allocation priorities remain unchanged, balancing investment in our highest value organic opportunities, balance sheet strength and shareholder returns. This approach preserves financial flexibility while supporting disciplined investments into the business. Next slide, please.

Moving to liquidity management. Net debt fell to $185 million in the quarter with leverage of 0.5x at our through-the-cycle target. Following our successful September RBL redetermination, our borrowing base is $513 million, leaving $182 million of headroom and total liquidity of around $328 million. That trend is particularly important as activity now picks up. It gives us more than enough capacity to fund the drilling program from operating cash flow while maintaining resilience through the oil price cycle.

With that, I'll hand you back to Oliver.

Thanks, Aldo. Now let's turn to the next slide and our business outlook for the next year. After an extended period without drilling, the next 12 months mark a significant increase in activity for Meren. In Nigeria, we are entering a sustained investment program that runs into the early 2030s and offsetting natural decline, adding reserves and progressing our discovered resources through our existing infrastructure to deliver overall production growth.

That activity begins with the PML 2 and 3 drilling campaign around Akpo and Egina. Drilling is expected to commence this month, starting with the Akpo Far East exploration well located around 5 kilometers from the Akpo infrastructure and which, if successful, could move quickly into a production tieback.

The campaign then continues with infield wells across Akpo and Egina alongside the vessel-led well interventions that support near-term production. In PML52 and PPL -2003, the rig is expected in Q1 2027. The initial program includes three firm Agbami infill wells that will deliver incremental production in 2027 and appraisal of the adjacent Ikija discovery.

The Ikija well supports definition of a future development through a tieback to the Agbami FPSO. Alongside the near-term investment activity, the path for the Egina tieback developments is now much clearer. Following interpretation of the latest seismic data across Preowei, the project is moving ahead through the FEED process in 2027 based on an optimized lower-cost development concept ahead of FID.

In parallel, the Egina South discovery that sits across two licenses will be appraised through a well in the license adjacent to Meren's position, and this should derisk the resource range and allow the tieback concept to Egina to be optimized with no appraisal cost for Meren.

So over the next year, there are several tangible milestones for the Nigeria portfolio. Delivery of the interventions, commencement of the Akpo and Egina drilling campaigns, arrival of the Agbami area rig and maturation toward FID for the Preowei and Egina South tieback developments.

More broadly, the investment environment in Nigeria continues to be supportive with the deep offshore incentives order signed in August that offers tax credits for qualifying projects reaching FID by the end of 2029, further enhancing the investment proposition of Meren's deepwater discovered resource base. Beyond Nigeria, we're continuing to progress the longer-term opportunity set.

On Venus, the operator has said the project is ready for sanction and that it is working towards FID in the near term with first oil targeted in 2030. For Meren, our interest remains fully carried through to first production, giving us exposure to long-term and diversified production growth without any upfront capital exposure.

In South Africa, the minister's dismissal of appeals against the environmental authorization to drill up to five wells on Block 3B/4B is a positive development for the project. The Nayla prospect remains ready to drill with timing subject to any further proceedings that may be initiated.

Taken together, we're moving into a much more active period for the business. The immediate focus is on executing the drilling program in Nigeria while continuing to progress the series of growth opportunities across the wider portfolio. And that gives a good sense of what we're building towards more broadly, which I'll turn to on the next slide.

On Slide 12, we can see the direction of the organic business based on the multiple growth options in the portfolio today. The starting point is the Nigerian production base. The interventions in the infill program are intended to offset part of the natural decline and protect the cash flow from those assets, and that's a near-term priority.

The next layer is the discovered resource around the existing hopes. Preowei, Egina South and Ikija offer meaningful options for production growth as they each mature toward different FID points. These are greenfield developments with the attraction of utilizing our existing infrastructure and allowing us to optimize CapEx and reduce project risk.

Then there is Venus. Based on the operator's current public plan, Phase 1 can add a long-life production stream around the turn of the decade. And beyond that, we have a portfolio of exploration exposure in Nigeria, the Orange Basin and Equatorial Guinea that could deliver material upside through a large carried component that minimizes the upfront risk capital required to test these options.

So overall, we move into 2027 with a strong financial position that underpins our ability to deliver growth on multiple fronts, a return to near-term operational activity, development project maturation across several near-field resource projects and material carried exploration upside options.

Thanks for your time, and I'll now hand you back to the operator for questions.

[Operator Instructions] Our first question comes from Jeff Robertson from Water Tower Research.

Oliver, can you talk a little bit about the incentive -- the tax credit incentives with the new Nigerian incentive order and how that could affect the ultimate development economics at Preowei? And then secondly to that, are there other projects in the portfolio that could advance to FID before the 2029 deadline?

Yes. Jeff, thanks for the question. I think just as a refresher for people on Preowei, that is a 150 million barrel plus gross discovered resource, about 25 kilometers from the Egina FPSO same license area. So that's a project that actually has made great progress recently. We will move back into feed after a revised and improved subsurface picture.

And again, we'll move very fast towards an FID there stretch target end of '27. So it's a pretty exciting big project for us. I think specifically on the point, look, if we step back again, we've seen a raft of measures from the current government in Nigeria over the last few years in terms of fiscal support, particularly for the deepwater in the contracting landscape kind of bring in more competition there, which ultimately puts pressure on CapEx for these projects, which is great from our perspective.

The specific incentive that you mentioned there, it's effectively a production tax credit, which is $3, $4 a barrel that would be applied as a credit for projects FID before '29. So like, I think, firstly, we see Preowei doesn't necessarily need that fiscal incentive to be attractive to us. It's a good tieback project. But of course, that accelerates its value to the JV, and therefore, means we bring that project as fast pace as we can to be within that window, and it certainly will be in terms of '29. So it adds significant value.

And then secondly, on the follow-on, I think there's another, call it, a lookalike of Preowei Egina South, which as the name gives away, is close to Egina as well, very, very similar kind of plus or minus 150 million barrels gross, similar distance tieback to the Egina FPSO. And the way we look at that is that's a project that would follow Preowei -- you bring -- ideally bring Preowei on and then a short period of time later, you bring on Egina South to phase them.

So I think even with that, then we would look to certainly get that FID on Egina South within the window of the tax credit in '29 for sure. And that will be a driver for the time line of that project. So yes, certainly, for Preowei, it's very helpful. And I think for Egina South and potentially some other tiebacks that are less mature it just adds to the compelling case that already exists in Nigeria.

And can you remind at Akpo Far East, what you might anticipate the production from that project being?

Yes. So that's kind of super exciting well for us. I mean I think we'll spud that well. We've said mid-November, and we're almost there. So I think we're on track to do that. And again, that well is about 5 kilometers from the nearest Akpo infrastructure. So it is an exploration well. So there's clearly some geological risk on that, but relatively low, I would say.

So the plan would be to drill that through the end of this year, see what we get. And in a success case, I think we would do some extra work on the well to keep it as a potential producer. And then maybe somewhere through '27, six to nine months, we hook that up as a first well of a wider campaign, a wider development, if you like, of the discovery.

But the aim would be to bring accelerated first oil there again in '27. I think we'll see what the well brings. But in terms of rate, I think first well producer, new reservoir, you'd hope to do something around plus or minus 10,000 barrels a day growth. So meaningful from a field perspective for sure.

And then lastly on that, Oliver, have you been able -- or has the operator ordered some of the longer lead time items that might be needed to bring that on?

Yes. So the benefit of the current campaign is that we've got several activities. So the rig has arrived in the Akpo field area about five days ago, just getting predrill prep now. So of course, it's going to drill Akpo Far East. It's then going to go drill in the Akpo field itself. It's going to drill not on our license.

Again, it's kind of third party, but an appraisal well on the other side of Egina South. So there's a whole lot of activity in there and a sustained campaign. So in that respect, there's been planning done to account, particularly for the success case on Akpo Far East. And so it retains that flexibility to, again, do what we need to do to put a completion and get that ready for being a producer through '27. So we feel pretty good about that.

I will now hand over to Mr. Amini for the written questions.

We have a couple of questions on the Q3 results, and I'll put this to Aldo. Aldo, the first one is that given the EBITDAX realized year-to-date and our revised full year EBITDAX guidance, this implies that the Q4 EBITDAX could be around $58 million to $100 million compared to $113 million in Q3. Is this conservatism? Or is there something that the market should expect that could weigh on Q4 results?

Yes. So I think we're going to be careful with reading too much into what we see on the implied quarters for EBITDAX. I think the full year guidance, we have to remember is a range. So it's not just -- we shouldn't take it as a quarterly forecast. And a single quarter can be quite sensitive in terms of timing of the cargoes and the lifting. So we are comfortable with the range, and I expect to land within it.

Okay. Second question for you. The third quarter realized price of $2.40 per barrel was below the Q3 average of $97. So the question is why is Meren pointing to a premium having been achieved?

Yes. So again, it comes down to timing on this one. We had two cargoes in Q3, lifted in July and lifted in August. And during those two months, the average Brent was around $87 per barrel. So compared to that window, we sold them to a premium of around $5.5 per barrel. So the higher quarterly average actually reflects the price throughout the whole quarter, but recall that we have discretionary lifting, right? So that's what matters for the price realization.

Thank you. So the next question, and perhaps this is one for Oliver. It's regarding future opportunities in Nigeria. And the question is, is Meren looking to expand its working interest in more assets in Nigeria? For instance, there is a marginal field bid round coming up. Oliver, can you share your views, please, on opportunities in Nigeria and your potential plans.

Yes. Look, I think it segues with the question Jeff asked in the sense of Nigeria and its landscape. So again, when we look at two key components here. The first one, of course, begins with the subsurface and the potential of the basins there for resource, and it's very high. I mean it's a prolific petroleum system in the Delta. It's prolific petroleum system in the deepwater.

So look, we start with that simple promise that there's a lot of resource here. There's a lot of resource that's discovered, not developed and there's a lot of resource to be discovered, right? So a great place to play in that respect. And then you move to the second bucket, which we've touched on, which is, again, what's the aboveground situation and how attractive is that from an investment perspective.

And I think the short answer is it's very attractive right now. I think from a high level, we have a government that is extremely supportive of the sector, not just in words, but also when you look at the actions. So it's a government that's delivered on that, and we've just touched on some of those fiscal incentives again.

But that's created a landscape, which you can see across the industry has brought a lot of confidence. So project FIDs have increased hugely, particularly in the offshore. Transactions have been moving. So yes, look, I think it's a good place for the industry. And therefore, as an incumbent with that advantage, it's a great place for Meren.

I think again, we're very -- as we always are disciplined on our capital allocation here. We have some fantastic organic growth projects and very happy to see those have turned the corner really and moving fast. And on top of that, we remain open-minded if there are good growth opportunities in the offshore in Nigeria, then we're certainly interested. And we think those could be a good addition to the current business with the right transaction.

A question on Nigerian drilling activity. The point here is that we had previously guided that the rig for Ikija and Agbami could be operating by end of this year, but it has slipped into next year. How confident are we on the arrival of that rig and start of that campaign?

Sure. Yes. Look, I think end of year is always a milestone that triggers a statement like that. The reality is it's an operational delay. The rig is on contract elsewhere and that work has been extended, which again is kind of normal business, if you like. It's very hard to predict the end of the well activity if a well is an exploration well has made a discovery and then there's decision to test or whatever, then that runs on. So that's what we're seeing.

I think it could be mid we'd have had this few months pushback before we commence, and it wouldn't have been as visible but you trip over into a new year and it triggers, hey, it's '27, not '26, which is all true. So yes, look, I mean, the short answer is very confident that the joint venture is aligned, but Ikija again, is another discovered resource that, in this case, could be tied back to the Agbami FPSO.

So in some ways, a lookalike project is the way to think about it with Preowei Egina South. So for us, it's another great organic growth option. I think it makes sense with the JV over ikija. We're all aligned to appraise that and optimize the potential development plan. So the desire is there to do that.

And then when you look at the other part of that program is to drill infill wells in the Agbami field. And I think we see some really exciting wells there that could really lift production. So JV is aligned. Everything is moving ahead, and we've had a few months operational delay just because the rig is active elsewhere. But normal business, nothing that we're concerned about.

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

Oliver, can you talk a little bit about the potential for movement among reserve categories in 2027 based on the type of activity you've laid out?

Yes. So I think, again, just as a note on timing, of course, we go through annual reserves process and our updated reserves report will get disclosed in Q1. So I think that's a key point for people to look out for to see the actual numbers there. But I think, yes, in terms of the big buckets, I think 2P is concentrated in Nigeria today, more around the production fields.

So look, I think we'll look to incorporate in our next disclosure the updated subsurface work on Preowei. And let me say for now, that's positive in terms of the 2P number in Preowei. So we think that looks better. And then I think on the other near-field discoveries, which are the big buckets of contingent resource for us 2C, look, those will -- with activity there, drilling on Egina South, drilling soon to come on Ikija.

I don't think that moves them into a two-piece category immediately. But of course, it brings them down the funnel towards that much more clearly. And I think we'll be able to line up for people a view there of the visibility of the maturity of those reserves and therefore, as they get there and therefore, the value of them.

Look, I think the other big bucket, we haven't really touched on this call that I'll be guided by TotalEnergies as operator here. But of course, our indirect stake in Venus is maturing. Total has said the field is FID ready as it were from a project perspective and hopeful that, that comes soon. And I think for Meren, that's another area where we would look to be able to add and demonstrate our net share of reserves in that.

And of course, I'll let the numbers come out and speak for themselves, but people can see the scale of that project, the numbers that are out in circulation. They can do the math or the math depending on which side of the Atlantic you are on that and work out what it means for us. But we would hope to make good progress on adding Venus into our reserve resource report pretty soon.

Oliver, from your understanding, is the Venus FID just trying to tie out the final economic details on economic terms for the project with the government?

So yes, I mean, I think we're careful here to be -- to follow the operator because they're managing this through the final stages. So I think everything that we say mirrors that. I mean we're all fully aligned, I think, in terms of the JV and our ownership in impact that's in that JV. So yes, look, the project, I think as they've said, is project FID ready. But like all these things, it's the first development, oil and gas development in the country really.

And so there's a lot to go through there when you're the first project. So there's a natural kind of time sink, if you like, to get that aligned with the government. And again, what's our role here, it's to support impact and they're doing a good job of supporting the operator and the JV to try and close that down. So look, I think I'd point people to the statements by the operator. I think they're very positive. Look, and we think it's a great project. And so it's a matter of just lining those final pieces up and then that thing will move pretty quickly.

And lastly, I know you don't -- Meren does not have an outlook out for 2027, obviously. But based on the increase in rig activity in Nigeria, would you anticipate a similar number of liftings to what will be achieved in 2026 for 2027?

Yes, good question. I think plus or minus, if I say that, I mean, I think we'll see if you start with the production profile. We've obviously had natural decline feeding through here in the last kind of 18 months because we've had this pause in operational activity. Again, as of this weekend, that activity pause is over. So we get back to rig and then again, a second rig in '27.

So naturally, that's going to add barrels in the near term and the short term that supports gross field production and therefore, supports the kind of lifting. So yes, look, I think we'll let the guidance come out, but I think it would be not a huge change on our expectations from this year with that kind of increased activity in the fields as well, and that will offset a lot of the natural decline in the fields that we saw this year.

I will now hand back to Mr. Amini for more questions.

Oliver, here's another one for you at a strategic level. The company is looking at its organic growth opportunity focused on Nigeria. And with oil price volatility and unstable macro backdrop, is it really realistic that there will be good opportunities for inorganic growth? Any means that you want to share on that? And following on from that, is there still full strategic alignment on the Board and with our major shareholder on the growth of the company and what the future trajectory could look like?

So I think the inorganic question, of course, comes up a lot in the sector. I think if you take a step back here, yes, we've got volatility. We've had that since the Iran war in, I guess, February last year. But I think that's just the latest phase of volatility. I think that's just the world that we're in for various reasons. And so I think success looks like the ability to find value even though there's volatility around is not going to go away.

So look, then you turn that to inorganic opportunities. And I think, look, clearly, there are things out there. There are things out there that would be accretive in value to us. But again, as we've been through the last period, we're very disciplined around what we would do. We stick to our capital allocation framework because, again, we keep a fortress balance sheet here because of that volatility, which we've got.

We keep cash going into our organic growth investments because they're very high return. And by definition, we're already in them, so they're lower risk than external things. And of course, we've been consistent in '26 in our shareholder return and just announced the next GBP 25 million dividend, the last one for '26. And so we've returned cash, and I think we've returned cash whilst keeping that balance sheet strong, whilst keeping the ability to fund our organic growth in Nigeria through future operating cash flow.

And so look, that means are we a strong player in the inorganic space? I mean, I guess we are, but also that means a duty to act with discipline and then really turn that into operational world, which is, well, how do you seek out the places where there's true value, right? And those situations do exist. It's just harder work than perhaps in a lower oil price environment, but I think you can still find things that make sense. You've just got to be sure to be disciplined with it, which we are.

I think in terms of the second part of the question, I mean, yes, we've got a very solid cornerstone shareholder, very strategically aligned on our view of the sector, on oil price outlook and therefore, on growing the business and adding things in as they come along. So I think that's fairly straightforward.

A couple of questions to Aldo now on the near-term outlook and next year. Aldo, how many cargoes are currently scheduled for fourth quarter 2026? And how much of the end Q3 can investors expect to see by year-end? That's part one.

Okay. So we expect for the last quarter and just reminding everyone that this can change in terms of movement in oil price and cost and production performance. However, current indications that we're going to have two cargoes in the last quarter of 2026. We ended the Q3 with a little bit over 400,000 barrels of oil in under lifted position. So with two cargoes in our current expected entitlement production for the last quarter, we expect to end the year with roughly half of what we had on the under lifting. That's based on the current assumptions.

And second part is on the CapEx. There is also CapEx deferral as we are now guiding to the lower end of the original guidance. So CapEx guidance -- sorry, CapEx from 2026 to next year, is that going to be front-loaded in 2027, i.e., in early part of 2027? Or will it be spread more evenly across the year?

Yes. So I think we have -- let's look at CapEx from 3 different perspectives here, right? So the rig first, which is the one we moved into Q1 next year. Once it arrives at mid to end of Q1, it's going to be there for a while, right? It will be one well in Ikija and at least three wells in Agbami. So it will remain there for the rest of the year.

Another rig has the right for PML234, there will be a combination in that drilling campaign of wells being drilled in our block as well as the Egina South block on the OPL 257 just south of us, which is not our block. So therefore, once the rig is there, it will be not accruing CapEx or there will be no CapEx to us. And then beyond that, of course, it will depend as well on the plan for Akpo Far East, right? Assuming we have a success on the Akpo Far East exploration well, we expect them to -- the rig to come back soon into the block and then we'll drill the development wells.

And of course, and then in the case that it's not a success, then we will be deciding on the next wells in terms of wells for Egina. So it'll be a little bit more fluid from a P&L 234 perspective. And the other part is just the operational -- normal operational maintenance CapEx, including the asset integrity for the FPSO. So that's the type of CapEx you should expect going throughout the whole year.

So given that fluid in the -- what could happen operationally, is it too early to give an expected range for full year 2027 CapEx guidance range?

Yes. It's too early.

So we will update the market in due course once we have the formal guidance on that. There's actually another question I'm going to put to you, A. The Q3 unit OpEx was $18.50 per BOE and that is a rise from $10.70 a year ago. Is this the new run rate now for OpEx?

No, it's not. In Q3, it reflected the time of routine maintenance and some nonrecurring personnel costs in terms of the operators in Nigeria. And that was also spread at a lower enticements volumes as well for the quarter, given, for example, the impact in Agbami and also remind you that when oil price is higher, it tends to reduce our enticements barrels, right, given the PSA fiscal regime. So we see that as a one-off situation in Q3 and then it should normalize back to what we have been seeing in the previous quarters.

And we have one follow-up question, which I will put to Oliver, and that is on the license in Equatorial Guinea -- has obviously taken some time on the farm down process. Oliver, is there anything that you can add to what we've already included in the commentary in the presentation? And what is the potential outlook for these opportunities in EG?

Yes. I think as we've said, we're still in an active process there and looking at the options for both positions. And again, the focus is on saying, can we get something together there that fits within our capital allocation framework, returns required and discipline. So I think, look, we're progressing that quite well. And I think through the next period, we'll come to conclusion on the direction there. And I think that will be much clearer for the market.

Thank you. And actually, this reminds me of our farm down of Block 3B/4B in South Africa, which took longer than market had anticipated. And once we delivered the farm-down deal, it was a very good farm deal to Total and our energy. So for a company such as where we are opportunity rich, it's perhaps good to take our time and wait for the right deal rather than rush into something that is suboptimal.

Okay. On that note, there are no further questions. I thank everyone for joining us today for our first quarter results. And well, thank you, everyone.

Hello everyone. My name is Kahelani, and I will be your conference operator today. At this time, I would like to welcome everyone to Meren's Second Quarter 2026 Results Presentation. After the speakers remarks, there'll be a question-and-answer session. [Operator Instructions] This event is being recorded, and the recording will be made available for playback on the company's website.

I will now pass the meeting to Mr. Shahin Amini. Please go ahead, Mr. Amini.

Hello, everyone. Thank you for joining us today for Meren's Second Quarter 2026 Results Presentation. I am Shahin Amini, Head of Investor Relations and Communications at Meren. I'm joined today by Oliver Quinn, our Chief Executive Officer; and Aldo Perracini, our Chief Financial Officer. We will begin with prepared remarks and then open the floor to questions.

Before we get started, I will remind everyone that remarks made during this session are subject to forward-looking statements, which involve significant risk factors and assumptions that could cause actual results to differ materially. More detail on these risks can be found in our regulatory filings on SEDAR+ and on our website. The information discussed is made as of today's date and time, and Meren assumes no obligation to update or revise this information to reflect new events or circumstances, unless if required by law. The company's complete financial statements and related MD&A are available on the company's website and on SEDAR+.

With that, I will now hand you over to Oliver. Oliver, please go ahead.

Thanks, Shahin, and thank you everyone for joining.

Starting with Slide 4. The quarter shows our strategy working exactly as designed, high-quality, low-cost production underpinning the business and a disciplined capital allocation framework that balances investment in growth, maintaining financial strength and shareholder returns. In the core business, our Nigerian assets delivered to plan with first half production of around 28,000 barrels of oil equivalent per day, and that keeps us firmly on track to meet full year production guidance.

At less than $15 a barrel, our cost of operations remains low and resilient through a volatile landscape. Looking forward, there is a significant return to activity in Q4 across all fields with a well intervention campaign using a dedicated vessel and 2 rigs returning to commence drilling campaigns across Agbami, Akpo and Egina, including infill wells, discovered resource appraisal and high-impact near-field exploration.

Financially, the picture continues to be one of discipline and financial strength. Net debt to EBITDAX of just 0.5x, top quartile in our peer group, with around $320 million of total liquidity following the earlier RBL refinancing this year. Also we've declared our third dividend of 2026, taking year-to-date distributions to $75 million. And since closing the prime amalgamation last year, we have returned $175 million in dividends to our shareholders.

So with a robust first half performance and a clear path to recommencing investment activity in our production assets this year, we have raised our full year management guidance, and I will cover the detail later in the presentation. Mid to longer term, the wider portfolio has real optionality, and we continue with a laser focus on capital allocation as demonstrated with the restructuring of Impact Oil & Gas announced in May. We've simplified Impact to create a pure-play Namibia-focused vehicle, removing Meren's exposure to non-core South African exploration costs. This focuses Meren's regional portfolio in the high-quality Orange Basin with our effective interest in the Venus development and adjacent exploration unchanged alongside the directly held 18% carried interest in South Africa Orange Basin, Block 3B/4B.

Turning to Slide 5 and our production performance. Our assets continue to perform well with entitlement production of around 30,000 BOEs per day. Akpo and Egina performed in line with expectations and Agbami improved progressively through the quarter as the post turnaround maintenance recovery continued. Importantly, moving back to operational activity begins to provide support to production levels through year-end 2026 and into 2027.

With that, I'll hand over to Aldo for some more detail on the financials.

Thank you, Oliver. This quarter, we saw a recovery in realized pricing compared to the prior period. We lifted 2 cargoes in Q2 at an average all-in sales price of $92.8 per barrel against an average dated Brent for the quarter of $103.8 per barrel. The 2 cargoes tell the story of a transition. The first cargo was a cargo priced under the legacy trigger price mechanism where we realized $63.6 per barrel. The second cargo was a spot cargo, and we achieved $121.9 per barrel, which was both a significant premium to Brent as well as a positive differential to dated Brent.

The last cargo under the trigger price mechanism is now behind us, and we will no longer use this structure to manage oil price exposure. This structure served its purpose in the past. However, we believe it is not well suited to the current volatile commodity price environment we are experiencing. Our commodity exposure is now being managed through financial derivatives, and we continue to hedge approximately between 30% to 50% of entitlement production over a rolling 12 months period. Full details can be found in the MD&A. Post quarter end, we lifted 1 cargo in July with an all-in sales price of $90 per barrel against a dated Brent of $81 per barrel for the month.

Turning to the financial highlights. We had a strong quarter and a marked pickup in cash generation. EBITDAX was $108 million in Q2, taking the first half to a total of $220 million, supported by 2 cargoes and stronger realized pricing, partially offset by lower entitlement production and higher royalties due to the higher pricing. Cash flow from operations before working capital was $60 million and $139 million for the first half. The gap to EBITDAX primarily reflects cash taxes. Capital expenditure was $50 million in the quarter and $24 million for the first half, mostly invested in Nigeria as we prepare for the drilling and well interventions with the remainder of the spend weighted to the second half of the year.

And free cash flow was $53 million in Q2, bringing the first half to $18 million. The message is simple. The portfolio is highly cash generative and first half performance is tracking well against guidance with scope to revise higher, which Oliver will cover. The upgrade reflects both our first half delivery and a stronger dated Brent assumption converted into cash by our cost discipline.

Now turning to cash movements in the quarter. Operations generated $67 million, reflecting the 2 liftings and a solid underlying performance. We invested $50 million in the asset base, mostly in Nigeria. We repaid $80 million under the RBL, lowering interest costs and reducing outstanding debt to $290 million at the quarter end with net repayments across the first half at $40 million following the Q1 refinancing. We distributed $50 million in dividends, the first 2 distributions of 2026 with a third distribution declared today.

We will continue to allocate capital with discipline, protecting flexibility as activity in organic growth investment builds. Balance sheet strength remain the foundation of our business, giving us the resilience and flexibility to allocate capital through the cycle. Organic growth is our core value driver today and even more so as we move into a very active phase with disciplined investment in short-cycle, high-return opportunities within our asset base.

On shareholder returns, the base dividend policy has been our focus for returning capital, and this continues to be calibrated to market conditions and our investment priorities. We have been consistent, balance sheet and the highest return organic growth takes first call on our capital resources. About liquidity management, the headline here is Meren's financial strength and flexibility, and that matters even more as drilling activity ramps up. We ended June with net debt of $212 million and a net debt to EBITDAX of just 0.5x, comfortably inside our through-the-cycle target of 1x. We also retained $241 million of RBL headroom and $78 million in cash with a total liquidity of $319 million.

In practical terms, we enter the next operational phase from a position of strength, able to fund planned investment while staying resilient through the price cycles. With that, I'll hand back to Oliver.

Thanks, Aldo.

Turning to Slide 10. We are revising our full year 2026 guidance upwards, given both the positive first half operational performance and financial outlook. We've narrowed the working interest production range to 24,000 to 27,000 barrels of oil equivalent a day and entitlement production narrows to between 28,500 and 32,500. On the back of a higher assumed Brent price of around $85 a barrel for the year, we're raising EBITDAX guidance from an initial $270 million to $360 million to between $390 million and $430 million and cash flow from operations to $235 million to $260 million, raising the midpoint of these ranges by around 30% and 12%, respectively.

We have adjusted down our capital investment guidance range with the deferral of some drilling activity to 2027, and that's partially offset by additional activity for Egina and Akpo through the arrival of an intervention vessel to perform workover activities on wells later this year and that will support short-term production ahead of the more significant impact of the infill drilling in 2027.

Turning to Slide 11. Let's take a broader look at our operational and business outlook for the next 12 months as activity picks up significantly across the portfolio. Starting with Nigeria and Agbami, the rig will arrive in Q3 to drill a campaign of up to 6 infill wells across the field following an appraisal well on the Ikija discovery. This Ikija well has the potential to derisk further contingent resource, and if successful, will mature the discovery towards development planning as a subsea tieback to the Agbami FPSO, which would offer a short cycle and high IRR development opportunity for Meren, leveraging our existing infrastructure.

The second rig for Akpo and Egina is expected to arrive and drill the Akpo Far East exploration well ahead of a series of infill wells. Akpo Far East is an attractive near-field target, and if successful will be tied back into the existing Akpo infrastructure less than 5 kilometers away, again leveraging our existing infrastructure. With commercial success, early production could be brought online late 2027.

Looking further through 2027, we expect infill drilling to continue on all 3 of our producing fields and providing effective support to field production levels throughout the year and into 2028. Beyond drilling operations, we will also see a return to the FEED studies for the Preowei field following interpretation of new seismic data that has underpinned a potentially higher resource base and lower cost development.

Moving to Namibia and the Venus project. We are very encouraged by the recent public statements of the operator, TotalEnergies, regarding progress of negotiations with the government of Namibia toward reaching final investment decision. There is strong alignment between the JV and the government on developing the strategic project, the first oil development in Namibia and in the Orange Basin, and we continue to anticipate FID can be achieved in 2026 with first oil still targeted by the end of 2030.

Venus is a major deepwater development that diversifies our production base through the addition of another low-cost and long-term production stream. The FID milestone once achieved, will further underpin Meren's broader Orange Basin investment case with significant additional exploration potential around Venus as well as in our carried South Africa Orange Basin exploration position in 3B/4B.

Finally, turning to Equatorial Guinea. Recall that earlier this year, we secured 2-year license extensions for both blocks, giving us additional flexibility as we progress partnership discussions and align next steps with the government. We continue to be engaged in active discussions with interested parties. And once we have the right partnership in place and the right capital structure, drilling activity could take place within the next couple of years.

So to conclude, on Slide 12. Meren has a strong foundation, high-quality, low-cost production, low leverage and the financial capacity to invest through the cycle. From that base, we're moving into an exciting and active period with key operational and project milestones through the remainder of 2026 and into 2027.

Investment in our Nigeria portfolio supports both short-term production and cash flow as well as the maturation of a deep portfolio of future low-cost oil resource options. Beyond Nigeria, progress in Namibia and the wider portfolio is set to deliver significant long-term and low-cost growth opportunities that have the potential to deliver significant shareholder value.

With that, thanks for your time, and I'll now hand back to the operator for any questions.

[Operator Instructions] Our first question comes from Jeff Robertson with Water Tower Research.

Can you hear me?

Yes, go ahead.

Our next question comes from Teodor Sveen-Nilsen.

Can you hear me?

Yes, we can. Go ahead.

So a few questions from me. The first one is on the drilling campaign in Nigeria you're talking about. I assume that will make some positive contributions on production for 2027. Should we expect that that drilling campaign and the infill wells will decline or should we remodel some production growth in 2027 versus 2026? So that's the first question.

The second one is also related to that. Given that you step up drilling activity, also assume that CapEx in 2027 maybe will be slightly higher than 2026. Can you confirm that? And third and final question for now, that is lifting schedule. Could you -- you mentioned that you had one lifting in July. How does the full H2 lifting schedule look like?

Yes. Thanks for the question. It's Oliver here. I'll take the first 2, and then I'll hand over to Aldo for the lifting schedule. So yes, look, I think on the activity in Nigeria, I think, firstly, very happy to get back to activity across all 3 fields. And again, as we said in the call, 2 rigs coming, intervention vessel ahead of that. So I think important to characterize is the range of activity there. So firstly, we're drilling a near-field exploration well outside of Akpo, which is kind of super exciting catalyst, very low cost and could be quite a significant resource. So there's a potential significant value add from that activity. Similar in adjacent to Agbami, we'll drill in the Ikija appraisal well, which again is testing future resource, if you like, tieback potential to existing infrastructure. So those are important in the longer term, mid-term sense of significant value creation, value add to the portfolio.

And then you look at the rest of the campaign and the intervention vessels, and those are adding kind of to the point really, those are adding production very short term in the intervention vessel sense. Those things come on as soon as the vessel has done its activity. And then in the wells, it takes a couple of months to hook them up, of course. So what that will result then is longer-term value creation growth in the resource base, which is important. And then in the short term, it will arrest -- firstly, it will arrest the natural decline of the fields through '27, which given we're kind of in the mid-life here is important. And then depending on results, yes, look, I think we'd expect to see some incremental extra performance from that activity, but I would characterize it as firstly, from a production perspective, arrest decline, keep production stable through '27 and then with some positive wind behind us, if you like, an increase on production levels from that kind of plateau through '27.

So we look at the year as important because we start to see the results of that activity. And if you look at the production levels as we go through the back end of '26, we certainly, again, would hope to maintain those and, if possible, increase those.

All right. So I'll cover the question about the lifting schedule. And I think just before I answer, I mean, reminding that lifting schedule is conditioned on 2 things, right? One is the performance -- the underlying performance of the FPSO, right, the production, but as well as the fact that we are in the PSC arrangements, any change in oil prices or even assumptions on CapEx and OpEx can change the lifting schedule. So it is a little bit fluid.

But with that disclaimer, we expect the second half -- I mean, as you correctly pointed out, we already lifted cargo in July successfully. And we have expected for the rest of the semester, let's say, another 3 to 4 cargoes to be lifted throughout the second half of 2026 on top of the July cargo. So we had 3 cargoes in the first half and will be slightly more concentrated on the second half with something between 4 to 5 cargoes for the second half. Yes.

Okay. Could I just follow up on that, that mean -- probably that implies that lifting will be more or less equal to production in the second half. So we shouldn't expect any material overall under-lift.

Yes. We finished June with -- as you could see in the financial statements, we finished with an under-lifted position. And therefore, with that under-lifted position, which was roughly 600,000 barrels plus the production throughout the second half, then we get to in our current assumptions, 6 cargoes for the year -- for the second half, sorry.

And on the 2027 CapEx, are you in a position to say anything about that?

Yes. I mean, obviously, it's a bit early in terms of budgets and specifics firming up for next year. But I think what we do have line of sight to is, of course, the activity that we've outlined today. There'll be some optimization of that in '27, which will drive the final capital figure. But I think, look, if you look at our capital guidance for this year, it's come down a little bit. And I think that's really not a change of activity or cost, it's really a deferral of some of that activity into '27. So look, at this stage, I think a broad view on it, but it will be something similar to where we are this year, if not lower.

Our next question comes from Jeff Robertson with Water Tower Research.

Oliver, can you talk or can you share any color on what kind of reserve movements you might expect from the drilling campaign that is laid out for late this year in 2027?

Yes. Jeff, thanks for the question. I think if you look at it, again, kind of 2 buckets, if you like. So firstly, the series of activity around the field, so the Akpo Far East is effectively exploration near field and then Ikija next to Agbami's appraisal. So those are either adding to contingent resource to kind of 2C in the case of Akpo Far East. And in the case of Ikija, that's again firming contingent resource to say, do we have sufficient volume in that discovery to underpin a project, move it towards an FID and then move that into 2P in reserves.

So I think those are in that contingent increasing the pathway maturing towards 2P. I think specifically to go back on Akpo Far East, what's interesting with that is it's about 5 kilometers from our existing subsea infrastructure on Akpo. There's plenty of ullage over the FPSO. So that would be a very short cycle project. So I mean, again, you can see it in the call here, but it could be kind of 12, 18 months to first oil from that in the success case. So although the well would actually -- it's an exploration well and would add resource, we would expect that very, very rapidly to move to actually to reserves and 2P in the success case because of that cycle time. So that whole bucket is a bit of 2C and then some success case incremental 2P in the next 12 months on Akpo.

And then if you move to the fields themselves, I think largely, it's infill wells, interventions that are targeting current 2P. Again, some of those targets have some reasonable upside on them, which would be contingent today and would move to 2P, but I would characterize it as it's broadly about production, sustaining production, increasing cash flow through '27 rather than adding significant 2P to that reserve base, if you like. So it's really getting the most out of that 2P and moving some of it to 1P.

And Aldo, can you share some thoughts around how the drilling campaign and the capital that will be spent on the drilling campaign will affect entitlement production in 2027?

Yes. So I think what you're referring to is we're going to have from the last quarter of this year, let's say, 2 rigs drilling in the different areas, right, one with Chevron and one with Total. So we should expect that 2027, we're going to have a higher CapEx rate compared to 2026. 2026, if you follow our guidance as well as the actual results, you're going to see that we are very concentrated on the last quarter of this year as well, right? So we -- in terms of the first half of the year, we delivered -- we spent $24 million only, and we expect the bulk of the expenditure to be in the last quarter of 2026.

So I think, let's say, let's look at 2026 second quarter and expect that the expense will be similar on a quarterly basis throughout 2027 as we keep drilling the wells on both blocks. So when you do that in an entitlement, regime, maintaining everything else the same, you should, in theory, increase your entitlement production, which will then generate the entitlements for the additional lift, right? So that's how you should expect it to happen.

Of course the other big factor is the oil price. I mean, today, the oil price volatility...

That's why I said everything else the same.

It will be, but until we're nearer to the end of the year. So we'll obviously do our full year 2027 management guidance in due course, and we'll update you, Jeff.

And last question, on 2027, just generally with -- if you arrest the decline and grow production, then on the fixed cost, your unit LOE should trickle down, shouldn't it?

[Technical Difficulty]

We are currently facing a technical challenge. Please hold and we will be right back.

Can you hear us?

Yes, we can hear you.

Yes. Apologies, we had a technical malfunction at our end. If you can you hear us, can you please repeat the last question?

Yes. In 2027 with the drilling campaign and adding -- with the expectation of adding production, do you anticipate much of an impact on production costs just from a unit standpoint?

[Technical Difficulty]

Sorry, Jeff, again, we're still suffering from some problems. Can you just repeat that?

Yes. What -- do you expect an impact to 2027 production costs from the 2027 drilling campaign?

Jeff, that's [indiscernible] just repeat that once more.

Shahin, should we expect an impact on 2027 production costs, at least on a unit basis from the 2027 drilling campaign with the expectation of incremental volumes being added?

Yes. So it shouldn't impact production costs. Those costs will mostly be reflected in our CapEx requirement in 2027. So production costs will be a function of what we're going to get from the operators' budgets for next year. So if you look at the last quarters, you can see that we have been spending consistently a little bit below $40 million per quarter. So we do believe that remains our view for the short-term, Jeff, and the drilling expenditures will be reflected in CapEx.

Apologies for that technical mishap at our end.

There are no further questions at this time. I will now hand back to Shahin to read through your written questions.

Thank you. There's a question on hedging. And the question is, are we under the RBL agreements, do we have to hedge? And can you just share your views on the hedging plan moving forward and what has changed?

Sure. So in relation to hedging, no, we have no obligation under our RBL to have minimum hedging or any type of hedging strategy. I think, of course, the banks consider that we will have a prudent management in terms of commodity price risk. So we do that consistently, and we have an internal policy which we follow, and we have explained that in our MD&A. So roughly, we hedge between 30% to 50% of our gross production on a 12-month rolling basis. So the only -- we keep with the hedging strategy. We think it's a protection against the volatility in oil prices. And that's especially even more important than we step up the drilling operations in the next year.

So we will continue with following our hedging policy. The only changes worth highlighting is that we have moved from doing the trigger price mechanism from the past, which was something had its purpose back in the days. But as I mentioned before, in this volatile oil price environment that we have and also the fact that the floor has increased dramatically with the sanctions in the Middle East, we have moved to a more structured hedging implementation through financial derivatives, and you can see the full details in our MD&A.

And turning to the Preowei development, Oliver. Do you see further -- I suppose this applies to other fields in deepwater offshore Nigeria. Do you see further near-field opportunities? And do you see positive takeaways for Preowei? And how do you see that moving forward?

Yes. I think it's important to take a step back around the Nigeria production assets and the portfolio and we talked on this call, we're excited to drill the Akpo well coming up, we got appraisal well on Ikija. So again, testing and maturing significant resources there next to infrastructure, the super kind of high-value stuff, short-cycle developments. But more widely, of course, we have Preowei, which is -- it's a tieback project to the Egina FPSO. As a reminder, Preowei itself, it's a significant field. I mean it's kind of expected to deliver peak production gross 65,000 barrels a day.

So that's a big opportunity for us as a tieback that's maturing well. There are others there is an Egina South discovery, which again, the name gives it away, but it's a tieback potential development to the Egina field. It's actually across our block and it goes into a neighboring license area.

So Total are in the license area adjacent to our side, if you like, and they are planning an appraisal well on that forthwith. So again, that will -- although that's not a well on our side of the license, it matures that project into what could be a Preowei type scale tieback as well. So those are 2 big opportunities. And then as we look more widely around the field, I think there's been a series of kind of new 3D seismic acquisitions over the last few years, particularly over Preowei for example, that have really unlocked the subsurface a bit further. And actually, there's a good portfolio there of follow-on opportunities in terms of low-risk field exploration, discovered resource, et cetera.

So if you put all that together and how do we look at those assets. Now, of course, they have very low lifting costs, very reliable base production, very long field life through the next decade, so significant and sustained cash flow, very, very secure cash flow and, again, in a volatile world because of those low lifting costs. But actually, there's more than that now because we've got really, really big kind of 200,000 barrel a day FPSOs. Those FPSOs have ullage capacity as the core fields have matured. And so of course, we're now quite aggressively looking with the partnership on what other aspects of volumes could we tie back into those fields.

So I think we're really positive about that. It does take time to get through the cycle and make the right decisions and make the optimal development plans, if you like, but we're working hard with our partners on that. And I think we'll see a series of both near-field exploration, contingent resource maturing to FID tieback projects through the next couple of years, and there'll be quite a lot of news flow on that really.

A question on recent fiscal incentives announced in Nigeria for the deepwater projects. Any views on these and any specific comments on how these could relate to assets in Nigeria?

Yes. I think that's almost the second part of the question we just addressed because we've got great subsurface resource here. We've got great running room. We've got great facilities. The other piece of the equation, of course, is obviously above ground and you say, well, okay, how does that work in terms of the economics, the commercial, the stability, the wider landscape, if you like. And Nigeria is in a very, very good place. I think everyone can see in the industry that, firstly, there's a stability now. There's a really, really strong support from the top level and throughout government to mature the hydrocarbons and maximize recovery.

So that industry landscape is fantastic from an investor perspective. It's the best it's been for a long time, and there's some really, really hard work has gone in there from the government side. So that gives you good landscape to say, well, hey, I've got great resources. I've got great kind of political landscape and support here.

The third piece then is really to the question is the fiscals. And so of course, we're in deepwater. And like any deepwater project, you need terms of work to respect the scale of the CapEx that goes into these projects, the duration of that CapEx investment and therefore, the duration of a reasonable return. And what you see in Nigeria is a series of, I guess, executive orders there that are translating through the system into real fiscal incentives. We've seen it with some other operators in the deepwater. We've seen FIDs on other projects in the deepwater.

And I think that for us is just really encouraging that the more resource we see around our blocks, the more of the contingent resource that we mature towards reserves, the bigger that portfolio of opportunities comes for us, and therefore, the better we can allocate capital to the high ranking returns, all with a high degree of certainty of the landscape we're operating within. So that all said, I think to say we are very excited by the portfolio in Nigeria. We're very excited by the political government landscape and the support we're seeing there. I think it's one of the leading countries right now in terms of not just saying that they want the hydrocarbons out of the ground, but actually putting plans and opportunities in place to allow investors to do that.

A couple of questions on shareholder returns policy. So let's give this to Aldo. Combining these 2 questions with perhaps a more constructive oil price outlook, what is the company's thinking around capital allocation and shareholder returns?

Yes. So in terms of our capital allocation, well, our priorities and the policy will remain the same. As we have explained throughout the different presentations and results, I think our priority is first to protect the balance sheet which will be always number one. And the second one, we want to make sure that we go through the cycles, being able to invest on all these organic opportunities that Oliver just mentioned, right? Those are high returns, short-term paybacks, utilizing our existing partnership in a country that we understand well and is very supportive. So in case of Nigeria. And also we -- that remain our priority #2 after the balance sheet. So that wouldn't change.

And then third case in terms of distributions, that remains subject to review and Board approval on a quarterly basis. We always look at the market and our investment priorities, and we'll come up with the distribution policy, which is not only something interesting for our shareholders as well as a show of discipline from the company perspective. So that remains -- there is no change to the capital allocation policy.

There are a number of questions on Equatorial Guinea. So again, I'll combine them because they are common themes. And the questions are what are our timing expectations. And we basically have stated our position in the shareholder report, and we will update the markets in due course. I don't think there's anything else to be added at this point. And there's a couple of questions on strategy and inorganic growth, Oliver. One is Meren is very active in West Africa. Are there still thoughts around growing outside this area? Or will you stay focused on West Africa for the time being?

Yes. I think it's a great question. I think firstly, it relates back to the capital allocation point really because, again, I think we've been very clear and consistent about our capital allocation priorities and M&A and inorganic growth is in there, but it's in there in a very disciplined way, right? We're only going to do things that we have a high degree of confidence in and therefore, that we understand very well before we pursue a transaction. So that does take you to the geographic component because, of course, doing transactions, M&A in areas that you know well because you're already working there is, by definition, somewhat less risky from a transaction perspective. So West Africa remains critical in that respect. And I think that will be the case for considerable time. We also see, of course, significant flow of opportunity in West Africa. Again, there's the benefit to focus in the sense of understanding an area, understanding the players, the assets, the direction of travel, and that's really positive.

So I think firstly, positive on West Africa, good flow of opportunities. Again, we look at lots of things, but we act with discipline. If we see the right thing, we'll make the right move. More broadly, though, I think we do look slightly more wider around, let's say, the Atlantic Basin, Atlantic margins because, again, there are a lot of thematics there in terms of the technical world, in terms of the fields, in terms of the developments, in terms of the kind of aboveground opportunities and risks.

So that's a natural extension for us. But again, it's a wide lens, but we look with discipline and we look carefully. And we've evaluated these things, geography is an important component, but it's only one of those components in the mix of the decision.

Thank you, Oliver. There are no further questions. So I'll hand back to the operator.

This concludes today's call. Thank you for joining. You may now disconnect.

My name is Michelle, and I will be your conference operator today. At this time, I would like to welcome everyone to Meren's First Quarter 2026 Results Presentation.

[Operator Instructions]

This event is being recorded, and the recording will be available for playback on the company's website.

I will now pass the meeting to Mr. Shahin Amini. Please go ahead, Mr. Amini.

Hello, everyone. Thank you for joining us today for Meren's First Quarter 2026 Results Presentation. My name is Shahin Amini, and I'm Head of Investor Relations and Communications at Meren. I am joined today by Oliver Quinn, our President and Chief Executive Officer; and Aldo Perracini, our Chief Financial Officer. We will begin with prepared remarks and then open up for questions.

Before we get started, I remind everyone that remarks made during this session are subject to forward-looking statements, which involve significant risk factors and assumptions that could cause actual results to differ materially. More detail on these risks can be found in our regulatory filings on SEDAR+ and on our website. The information discussed is made as of today's date and time, and Meren assumes no obligation to update or revise this information to reflect new events or circumstances.

The company's complete financial statements and related MD&A are available on the company's website and on SEDAR+ website.

With that, I'll hand you over to Oliver. Oliver, please go ahead.

Thanks, Shahin, and welcome again, everyone, and thank you for joining us today for our Q1 call.

Let me start on Slide 4, which really summarizes a very strong start to the year, underpinned by a high level of operational performance in our production assets, complemented with an improvement in our financial flexibility and the continuation of our shareholder returns program. In March, we refinanced our reserves-based lending facility, significantly enhancing our financial flexibility and crucially our ability to fund the deep hopper of organic growth opportunities across the business and at a very competitive cost of capital. Quarter end liquidity post refinancing has risen to $366 million. On the shareholder returns program, we've now declared 2 quarterly dividends year-to-date to a total of just over $50 million.

And again, in our operations, our Nigerian assets performed above plan through the quarter and in particular, supported by the post turnaround recovery following planned Q4 2025 maintenance on the Agbami field. On the commercial front, we've also successfully executed an amendment to our gas sales agreement for Egina and Akpo, and that has secured higher gas prices and crucially with an index that includes some exposure to LNG pricing.

I'll now move to Slide 5 and our production performance for the quarter. In Q1, we delivered working interest production of 28,400 barrels of oil equivalent per day, which is at the upper end of our full year guidance. On an economic entitlement basis, production came in at 31,000, again, comfortably within our guidance. Looking across the assets, Akpo and Egina both performed in line with expectations through the period, continuing to deliver the steady, reliable base production we've come to expect from these high-quality fields. On Agbami, you'll recall we had an extensive planned maintenance exercise in the fourth quarter of last year, which weighed on Q4 production. Since completion of the program, Agbami has been ramping back up through Q1 and is returning to anticipated production levels.

In terms of activity outlook for the remainder of 2026, we have progressed in line with the program outlined at our 2025 full year results and with the joint venture partners across all 3 of our producing assets preparing to start drilling campaigns through late 2026. The rig for Agbami and Ikija drilling campaign has been contracted, and we expect to have a firm rig contract for Egina and Akpo campaigns shortly.

I'll now hand you over to Aldo to take you through the financials.

Thanks, Oliver. Turning to Slide 6. In Q1, we had one lifting at an average all-in realized price of $64 per barrel, which compares to the average dated Brent price of $71 for the month of February. This cargo was under a forward sales contract with a fixed dated Brent price that was triggered last year. Post quarter end, we lifted 2 cargoes during April. The first was the final trigger price mechanism cargo with an all-in realized sales price of $64 per barrel. The second lifting was priced in accordance with spot price and achieved an all-in sales price of $122 per barrel. With the legacy trigger mechanism now behind us, our hedging program for the remainder of 2026 is focused on swaps and collars. These instruments are designed to provide meaningful downside protection while maintaining some exposure to market pricing.

Moving to Slide 7 and our financial highlights. Q1 EBITDAX was $100 million, tracking within our full year guidance. The key driver in the quarter was the step-up in gas revenue following the amendment to the PML Q3 gas sales agreement in January, as already mentioned. This secures a higher long-term gas price and includes a mechanism to recover the historical pricing differential back to 2020. We received a cash payment of almost $14 million and recognized a fair value of $27 million as part of the mechanism to recover the historical difference.

Total revenue for the quarter was $114 million, comprising of $64 million from one oil cargo and $50 million of gas revenue, with $41 million of the gas revenue related to the amended gas sales agreement. Cash flow from operations before working capital was $79 million and reported CapEx was $9 million. Spend was light in the first quarter as expected, with activity expected to ramp up in the second half as we mobilize the drilling rigs. Free cash flow was negative in $36 million, driven mainly by $106 million working capital outflow. This mainly reflects a higher under-leased position and a buildup in trade receivables linked to the gas revenues. Debt service costs, including fees related to the RBL refinancing also impacted the quarter. But the key message is that underlying operating performance remains strong. The business is resilient, and our full year guidance is unchanged.

Turning now to cash management. We entered the year with a cash balance of $175 million and ended the quarter with $162 million, consuming about $13 million during the quarter. Cash flow from operations after working capital was negative in $27 million, comprising a healthy $79 million before working capital and a large negative working capital movement given that only one cargo was monetized during the quarter. Capital investment during the quarter was $9 million, which was predominantly directed towards Nigeria. We drew down $40 million on the RBL to support our working capital and liquidity position given the phasing of cash flows. We incurred $10 million in fees and expenses associated with the successful refinancing of the RBL. Post quarter, we are also pleased to announce the second quarter dividend of 2026 of approximately $25 million, bringing year-to-date distributions to just over $50 million.

Moving on to liquidity position. Turning to our broader liquidity position. I'll give a quick recap on where we stand. The chart on the left shows the progress we have made over the recent years, reducing combined debt and net debt, lowering interest in costs and maintaining a disciplined approach to capital structure. At quarter end, net debt stood at $208 million, up from $155 million at year-end, largely reflecting the drawdown discussed on the previous slide. Importantly, net debt to EBITDAX remains very comfortable at 0.5x, well below our target of 1x. The key development in the quarter was the successful completion of our RBL refinancing, which materially enhanced our financial flexibility.

There are 3 points I would like to highlight. First was the lenders' appetite. We contracted commitments of $600 million with an accordion feature of up to $1 billion. The facility was more than 2x oversubscribed, which demonstrates the strength of our asset base and the continued support of our banking group. Second, the tenors. We extended the tenor to 6 years, including 2-year grace period and reduced our cost of borrowing with the loan life average margin down by 12.5 basis points. And third, the flexibility. The revolving structure allow us to draw and repay as needed, helping us to manage liquidity efficiently while executing our business plan. The accordion also gives us additional capacity to support growth initiatives where appropriate. As shown on the right-hand chart, following the refinancing, we retained more than $200 million of RBL headroom, which together with our cash, give us ample capacity to support our forward plans.

With that, I'll hand back to Oliver to talk through the latest updates across the portfolio.

Thanks, Aldo. Now turning to Slide 10 and an update on the portfolio and business outlook. Starting in Nigeria, we expect the drilling campaign for Akpo and Egina to start in late 2026 with the drilling of the Akpo Far East prospect. This is a very attractive near-field exploration target with an estimated 150 million barrels of gross unrisked resource and if successful, subsequent first production will be through a 5-kilometer tieback to existing Akpo infrastructure. The campaign will then shift focus to drilling infill wells across Akpo and Egina with first production from these wells expected in 2027.

We also anticipate that TotalEnergies will drill an appraisal well on the extension of the Egina South discovery on the neighboring block, which will move the Egina South project further towards a final investment decision point. In a success case, this provides Meren with another material short-cycle, high-return growth project that alongside the Preowei development, leverages our existing Egina FPSO as a tieback hub and delivers more long-term low-cost production.

Moving across to the Agbami drilling program, which we now estimate to begin in the fourth quarter. This will commence with the appraisal of the Ikija discovery. The development concept for Ikija is a subsea tieback to the Agbami FPSO and so like the Egina tieback projects offers another compelling high-return growth option using our existing infrastructure. Following the Ikija appraisal, the rig will move to drill a sixth infill well campaign on the Agbami field through 2027 and into 2028, and that will start to deliver incremental production from early 2027.

So in summary, after a period of lower activity in Nigeria, we're shifting gear across our deepwater hubs. We have a clear and active program ahead across near-field exploration, appraisal and with infill drilling adding incremental production.

Turning to Namibia. Venus continues to progress towards a final investment decision, which we anticipate in the coming months and with first oil targeted for 2030. The operator has completed the FEED and submitted the field development plan with capital costs matured through competitive EPC bidding. Importantly, Meren remains fully carried through to first commercial production with no financial cap. That gives us exposure to a major long-term growth project without the upfront capital burden.

Finally, in Equatorial Guinea, we have secured license extensions of up to 2 years on both of our blocks, EG-31 and EG-18, and this gives us additional flexibility as we progress partnership discussions and define the forward plan for those positions. So overall, we are entering a period of meaningful portfolio activity with near-term drilling in Nigeria, a major development milestone approaching in Namibia and continued optionality across Equatorial Guinea.

Now turning to our capital allocation framework on Slide 11. Our balance sheet remains in excellent shape with quarter end cash of $161 million and enhanced liquidity provided through the RBL refinancing that gives us $600 million of commitment and delivers significant financial headroom to support the next phase of our growth. Leverage remains low with a net debt-to-EBITDAX ratio of 0.5x. And again, this financial strength allows us to invest with confidence in the deep organic growth portfolio. It also allows us to return value to shareholders and having distributed $100 million in dividends during 2025, we've now delivered just over $50 million year-to-date in 2026. So with the business streamlined, the balance sheet is strong, we have the optionality to pursue inorganic opportunities where they meet our strategic, financial and operational criteria.

So to conclude on Slide 12, Q1 has seen another quarter of strong performance, and it's this consistent delivery that allows Meren to continue to deliver a differentiated investment case anchored by our strong pillars of financial strength, high netback production and deep portfolio of organic growth opportunities. I'm confident Meren is well positioned to both capture the value in our portfolio and to pursue the right inorganic opportunities as the sector continues to evolve.

Thank you for your time, and I will now pass back to the operator for any questions.

Our first question is from Teodor Sveen-Nilsen from SB1.

A few questions from me. First one is on lifting schedule. You obviously lifted less than you produced in the first quarter. What should we expect in terms of lifting compared to production in second quarter and third quarter?

Second question is on the balance sheet strength. You obviously have a very strong balance sheet now with net debt to EBITDA of 0.5, while the target through a cycle, as I interpreted is 1x EBITDA. How should we think around that? Will there be an extraordinary dividends? Or are you preparing to ramp up CapEx significantly?

And my last question that is on Venus development. I understand that Total is still working on that as you discussed, but I just wonder if you could provide some more color on what we know in terms of first oil potential new resource report, et cetera?

So I will cover the first 2 questions, and then I'll pass on to Oliver to cover the question about Namibia and Venus. So in terms of liftings, the expectation for the full year 2026 is between 7 to 8 cargoes with one cargo already being lift in the first quarter. So the reason why I gave you an estimate is just that oil prices have an impact on entitlement production, as you know. And therefore, that can change the lifting schedule as oil price moves significantly, right? So right now, we see a potential between 7 to 8 cargoes to be lifted and sold in 2026.

Now coming back to the question about balance sheet strength. Yes, I think we do believe between the cash position and the availability, the headroom in the RBL in terms of available liquidity to Meren, we are in a pretty strong position to go through the year and the years ahead. The reason why we do that, as you know, we want to protect our portfolio of organic growth opportunities and as well keep the company robust to continue with the dividend payment. Those are the priorities that we have.

Now in terms of extraordinary dividends for 2026, we do believe, first of all, it's a little bit too early to opine on that. I mean we feel strongly about the base dividend that we have mentioned before. However, we need a little bit more time to evaluate throughout the year and the performance about any potential extraordinary distributions. At this point, we're not in a position to comment on that. And I'll pass on to Oliver to talk about Namibia.

Yes. Thanks, Aldo. So I think on Venus, we point to the operator guidance really, which has been very clear in the public domain, which is the anticipated target for an FID of the first phase of Venus is July this year. So that's, of course, pretty imminent. And then typical for kind of project like that, first oil is 3, 4 years. So we kind of see that somewhere 2030 for first oil. So look, I think what's behind that, the project development plan is submitted to the government, the contracting work for kind of subsea, all of the critical path items, FPSO is mature. So really, it's about closing out key items and pushing hard for that July time line. So that's the market that we're looking for as a partner, if you like.

Okay. Could you just remind us of expected Total production for the first phase there?

Yes. So again, there's an easier thing to point to the public numbers from the operator, TotalEnergies. So it's an FPSO gross capacity would be 160,000 barrels of oil a day with reasonable uptime, let's say, it runs at maybe 150,000 gross at the field level. And then through our kind of holding and impact, which sits on the license, net-net, we're just under 4% of production there. So call it circa 6,000. But again, as you know, but we like to remind people, we're fully carried on the CapEx and the upfront costs there. So that's kind of 6,000 barrels, but it's a very valuable 6,000 barrels that comes effectively risk-free to us.

Next from Jeff Robertson from Water Tower Research.

Oliver, with respect to the drilling campaign in Nigeria, can you talk a little bit about movement of reserves between categories that you might anticipate in 2027 and 2028?

Yes. So I think as we said on the call, we've got 2 rigs coming. So again, just to remind people, one is in Agbami field and the other rig will go between Akpo and Egina fields. So look, I think with Agbami, it's a 6-well campaign. So the first well will actually be the Ikija appraisal well we mentioned on the presentation there. So after that well late this year, rig moves into the field and those are 6 infill wells.

Then on Akpo and Egina, the rig -- the current plan is to drill this Akpo Far East exploration target upfront. So that will be the first well. And then through late '26, '27, go in and drill a number of infill producers there. So I think in terms of what that means to the question in terms of reserve categories, a lot of that is 2P because it's already proven in the field, if you like, it's proven probable in the field. So it's a matter of accelerating it into actual flowing barrels. I think when you look at Ikija, and I think you look at the other tiebacks around Akpo and Egina, some of those are 2P like Preowei already and then some are contingent resource.

So the key maturation there is to prove up volumes on Ikija, for example, Egina South rightsize the development and then that would remain 2C in the short term. But of course, as we progress towards FID, it accelerates that becoming 2P. So that would be quite an incremental step-up for us in those wells.

As you move those wells from 2P to 1P, will that have an impact on the collateral and the borrowing base?

I don't think hugely so because I think we -- the fields are mature, the infrastructure has been there. It's all on stream. So I don't think it makes a significant change. I think what does make a change is maturing that 2C kind of around the fields, if you like, so that we get closer to those becoming developments and FID, they become 2P, so they become more relevant in that respect.

And then secondly, with respect to inorganic growth, can you just outline maybe the characteristics of an acquisition opportunity that would make sense given your portfolio -- your current portfolio and your capital outlook over the next couple of years on your organic opportunity set?

Yes. That's a great question. I think take a step back here, short term, to say the least, we're in a volatile world here in a geopolitical sense. And of course, that plays straight through to oil price. So I think that does for anybody in that kind of M&A world, it makes life trickier in the short term. I think what's important from our perspective is fine. We deal with that, but it doesn't change our ultimate strategy and direction. It's a matter of how you execute in a stormy world. It's not a matter of kind of let's pause or anything like that because you just -- you don't know what's coming next. So we'll continue to be very outward looking, let's say, on that front. And again, despite the short-term kind of volatility, the shape of that looks the same. And I think that focus is geographically priority Atlantic margin. I think that makes sense to us from an expertise perspective, knowledge networks, both technical and above ground. So that's a geographic kind of focus.

And then from a characteristic perspective, look, I think we see a lot of organic growth as we talk about in the business coming through and adding barrels kind of back end of this decade, and that's all very kind of high-return opportunity, high netback. But adding in from an inorganic perspective, flowing barrels and scaling up the business ahead of that would be an important characteristic. I'll caveat all that, of course, with the fact that not just short-term volatility, but we are super disciplined around that. It's pretty hard to beat some of the returns we see in the organic portfolio, and that's the hurdle that we use to test the external opportunities, right? So it's got to be as good as or better than what we've got internally. And again, that's a pretty tough bar, right? I mean we see opportunities to do that, but they're select.

Our next question is from David Round from Stifel.

Just on your inorganic aspirations, how much firepower do you ideally want to have ready for a deal? And what happens with any excess? Because obviously, we're in an environment now, and you've already talked about the prices that you're realizing. I mean you could end up in a very healthy position. I'm just sort of wondering sort of what happens to that. I'm nervous to use the word windfall, but that excess cash.

And secondly, sort of linked to that, I guess, just if you wouldn't mind reminding us exactly what hedges you have in place in H2 and the extent to which you're benefiting from current prices or just any sort of ceilings on those colors we just need to be aware of, please?

Yes. Thanks, David. Let me take the first one, and then I'll hand over to Aldo around the hedging one. So look, I think as noted, the balance sheet came into the year strong and clearly strengthening in the current environment. We could all take a view on the outlook here, but I think the house view here is this is not getting resolved quickly, and therefore, very difficult to see a world where the oil price fall significantly in the near term. So that will help. And again, you get into the nuance of what sort of transactions would you do? I think cash transactions today are pretty difficult. We have the capacity to do that. But I think how do you close the kind of buyer-seller gap in this environment is tough. And that takes you into kind of more other ways to do things that are kind of merger-type territory and those types of transactions, which, of course, may involve a component of equity really. The measure on those, of course, is can you get an agreement on fair value? Can you be sure that you're fully valued in your own equity, et cetera, before you do that.

So I think we're pretty open-minded as to what the best way to do things would be. And I think that firepower is significant. But again, I think the point that we'd really like people to take is we're super disciplined about using that. We're very active in looking for opportunities. But again, they've got to -- as I said earlier, they've got to compete with the organic capital allocation internally, and that's a pretty high hurdle. So look, it's a good problem to have. It's a good challenge. And I think as we get through '26 and the outlook for the world, we get stronger from a balance sheet perspective. And I think that just helps to open up even more opportunity.

Yes. And on the hedges, I mean, I realize that we have in our MD&A, the hedging position until the end of the quarter. And then I realize that the reference we make is in relation to what we call the post-tax net entitlement, but I think it will be easier to say the percentage that will tie with total production, right, which is easier to compare with other companies. So if you get our hedging book for the remaining of 2026, the remaining 3 quarters, in relation to total production, we are hedged a little bit below 40% of the remaining production. And within those hedges, we have a mix of swaps and some collars. That's for the remainder of 2026.

Now if you look at the next 12 months, the percentage of lifting volumes, we would be more towards the low 30%. So between 30% to 35% is what we have in the next 12 months. And in 2027, what we are working, as you can see in the MD&A, is on placing more white collars, which still provide us with a significant floor protection while keeping a substantial participation in the upside. So that's how we have been treating hedging in the current terms.

There's no further questions at this time. I will now hand over to Shahin Amini for any written questions in the meantime.

Thank you, operator. A question on Akpo Far East. If it is a successful exploration well, what is a realistic time line for monetizing this asset using the nearby infrastructure?

Yes, that's a great question. So I think it's in the presentation, but Akpo Far East, it's actually within the license of the Akpo field. So from a fiscal perspective, it's all ring-fenced, which as an aside, supercharges the economic success case. Development-wise, it's about 5 kilometers from the kind of western side of the structure back to the Akpo subsea infrastructure. So I think as we see it today, pre-drill, you would look to have 1, 2 early producers possibly in 2 years, hooked up back to that template for early production. And then again, depending on the size of the discovery and the resource, you would step out with some more subsea infrastructure over Akpo Far East itself, and that would be maybe 1 year, 18 months following the first oil. So it will really be stage development with a focus to get early production and then follow that up again depending on the scale with incremental build-out on the subsea to fully develop the opportunity.

2 questions on Equatorial Guinea. First one on the license extensions. Did these extensions come up with any additional commitments? And the second question is, if you are looking to farm these down, do you still want to retain operatorship? What is the overall philosophy in terms of farming these down?

Yes. So on the license extensions, we've got up to 2 years on each block. There are, in short, no significant commitments there. There's a regular kind of license holding cost, but there's no capital -- firm capital work program associated with that. And I think what's important to take from that is it reflects our partnership with the EG government where we both recognize that we're in the middle of this farm-down process. We're in a very changing world where it's significantly increased appetite for West African assets and opportunities. And so it makes sense for us to have that extension for both parties, the government and ourselves to continue to allow us to give us the best chance to get a good farm-down deal there on both blocks.

I think on the latter question, I think 2 different things there. So EG-31 is an inboard block. It's shallow water kind of gas development appraisal opportunity. I think that's something that we would be comfortable to operate as Meren. And I think in the outboard EG-18, that's a different type of opportunity. That's a kind of very traditional deepwater big exploration target. So I think, look, we'd be comfortable to drill an exploration well there, but that's something that we partner with a larger company to develop. So I'd look at them in slightly different ways.

I think again, I would just reiterate what our aims are here is around capital allocation and discipline. So for the big exploration opportunity, just as we've done in South Africa 3B/4B, it's a matter of using some of our equity to bring a partner in and then use that as a funding solution for the higher risk early stage. So that's probably more of a priority than the operatorship. I think there's some flexibility around the operatorship depending which way it goes in terms of partners.

Very good. Question on Block 3B/4B in South Africa Orange Basin. The question is now that the suspension on the appeals process has been lifted and the specialist panel has been put in place, do you see tangible operational logistical synergies that can be shared between the South African assets and the Venus development project in Namibia, and considering the Orange Basin ecosystem?

Yes. So let me, again, preface the answer with what's happening there more broadly. So I think as many people are aware, the Orange Basin, roughly 2/3 of it geologically is in South Africa and then 1/3 is above the border in Namibia. And of course, huge success in Namibia, both Venus and our interest there, but also more broadly, multiple wells, billions of BOEs discovered. So a prolific kind of basin emerging. But not really any wells drilled yet in the South African side, which again is 2/3. So I think that is for aboveground reasons in the sense of the appeals process and the permitting process in South Africa has been a much longer process, let's say.

But to the question, it is now moving again. So I think we've gone through a period where that was suspended in order to kind of reset the approach more broadly for the industry, and I think that's a good thing. And so look, the next stage is to get through that appeals process. I think we're confident we've done all the right work there in terms of the environmental permitting to fulfill our regulatory requirements, but that's the next point is to get through that stage.

Then you move to the operational bit. And I think, again, first thing there, the prospects are mature, they're drill ready, the well planning is done. So in terms of moving from green light on the final permit appeal process through to drilling becomes an operational matter of rig availability and timing, but everything is kind of ready to go, let's say, which is good.

And then to the actual question, in terms of logistics, yes, absolutely, I think there's going to be a lot of rigs in Namibia, development drilling on Venus, et cetera, appraisal, [indiscernible], all the rest of it, several operators. So that's bringing a supply chain that's emerging and growing in Namibia. And again, that could be useful in South Africa. Equally, we've got, of course, very good infrastructure in South Africa with Cape Town as a harbor and a port. So I think, yes, it brings optionality, but I don't think it fundamentally changes it.

What's distinctly important for us is our partnership because we had a much higher stake in the Block. And of course, people will recall, we farmed down to TotalEnergies and QatarEnergy in 2024. And look, huge interest in the Block, unsurprisingly given its location in the Orange Basin. Part of the rationale for partnering again with Total is the fact that they're obviously -- they were at the time and even more so now kind of the biggest, most active operator in Namibia. And so of course, we'll naturally benefit from the synergies that brings because they've got Namibia activity. They've got other blocks in the Orange Basin in South Africa. And so we'd expect that to play through, again, a kind of cost efficiency on the drilling and logistics support more broadly.

And question for Aldo. And Aldo, you have gone into some detail on the hedging program that we have, but I think further color from you in response to this question would be helpful. If you could please explain more about the predicted selling price in terms of hedging for upcoming cargoes during 2026. And I suppose we could qualify that question with reference to our previous trigger price mechanisms perhaps. Aldo, would you please share your thoughts on that?

Yes, of course. So yes, I think now in the first quarter as well as the cargo that we already mentioned in the second quarter that had the trigger price mechanism, they are based on the legacy instruments that we were using before the prime amalgamation back in March last year, right? So this one that we leased in April was the last one. So we don't have additional hedges using that type of structure. So the remaining hedges for 2026, they were placed late last year, early 2026 when we all expected a much tighter oil market given all the situation in the past.

Now of course, with the war in Iran and all the consequences coming after that, what changes for us is not the hedging policy per se. We do believe that the hedging policy is something put in place to be agnostic to oil prices. The only thing that changes for us is the type of instruments that we have in use. Now with a higher curve, we are able to place good protections for the downside, but while keeping material participation in the upside. So that's the only change. That's how we start doing in Q1 2027. So you should expect for the remainder of 2026 prices, as you can see in our MD&A, so more towards, let's say, pre-war price estimates. But coming into Q1 2027, we should start seeing the different colors and a better participation in the upside.

Yes, sorry. And there was another question on working capital profiles for the rest of this year and the hedging. And Aldo, you already answered this. And I just want to refer everyone that if you refer to the shareholder report on Page 15, you have a breakdown of our hedging for the second half of this year. And again, just reiterate what Aldo has already said on expected cargoes from Q2 to end of the year, we expect 7 to 8 cargoes. And if anyone wants more detail, I encourage you to reach out to the IR team at Meren, and we can help you if you need to go into further detail.

And on that note, there are no further questions. Oliver, do you have any final concluding remarks?

No, I just thank you for joining everyone and taking the time today.

Thank you. And I'll hand back over to the operator.

Thank you. This concludes today's call. Thank you, everyone, for joining. You may now disconnect.

Hello, everyone. My name is Jenny, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Meren's Fourth Quarter 2025 Results Presentation. [Operator Instructions] This event is being recorded, and the recording will be available for playback on the company's website.

I will now pass the meeting to Mr. Mussannah Chowdhury. Please go ahead, Mr. Chowdhury.

Hello, everyone. Thank you for joining us today for Meren's Fourth Quarter 2025 Results Presentation. I'm Mussannah Chowdhury, part of the Investor Relations team here at Meren. And I'm joined today by Oliver Quinn, our Chief Executive Officer; and Aldo Perracini, our Chief Financial Officer.

We'll begin today with prepared remarks and then open the floor to questions. Just before we get started, a quick reminder that today's presentation contains forward-looking statements. These reflect our current assumptions and expectations and are subject to risks and uncertainties that could cause actual results to differ materially. More detail on these risks can be found in our regulatory filings with SEDAR + and on our website.

With that, I'll now hand you over to Oliver. Oliver, please go ahead.

Thanks, Mussannah, and thank you, everyone, for joining us today. This is my first results presentation as Meren's CEO, and I'd like to begin by thanking my predecessor, Roger Tucker, for his strategic leadership and personal support over the past few years. I'm proud to have been given the responsibility to steer the company through its next phase of growth to lead a great team of professionals and to continue working with our industry and government partners towards long-term value creation.

Turning to Slide 4 and an overview of 2025. I'm pleased to report on a year of strong delivery. To begin with, last March, we closed a transformational prime consolidation deal, doubling our reserves and production from our high-quality and high netback assets offshore Nigeria. This was a strategic transaction as we simplify the ownership structure of our core assets, enhancing day-to-day control and creating a strong platform for further growth.

Through 2025, we have successfully integrated Prime and have a lean and fit-for-purpose organization to manage our production assets as well as progress our strong portfolio of growth opportunities. Underpinned by closing of the Prime amalgamation, we delivered strong shareholder returns with USD 100 million in base dividend and $8 million in share buybacks. Alongside shareholder returns, the balance sheet has been strengthened with the repayment of $420 million of the outstanding RBL facility, delivering both cost savings and a healthy year-end net debt-to-EBITDAX ratio of 0.4x, all whilst maintaining significant liquidity to cushion the business against market volatility.

Aldo will talk in more detail about the maintenance of a prudent leverage position and our broader approach to ensuring financial resilience through the cycle. 2025 was a year of transformation for Meren, but our focus today remains on continuing to maintain our balance sheet strength, enhancing the production profile through organic growth opportunities, and continuing to mature options to deliver long-term value to our shareholders.

I'll now take you through our production performance on Slide 5. For 2025, we achieved working interest production of 30,800 barrels of oil equivalent per day and 35,100 BOEs per day on an entitlement basis, both in line with our full year guidance. During the first 9 months of the year, the Akpo and Egina infill drilling campaign supported steady average production of around 32,000 BOEs per day on a working interest basis with production lower during the fourth quarter primarily due to planned maintenance shutdown on the Agbami field.

Q4 production was also impacted by minor facility issues, including temporary shutdowns related to power supply, particularly during the second period of the quarter. These issues were actively managed through targeted operational interventions, enabling the fields to continue performing in line with expectations following resolution. As previously communicated, the Akpo and Egina drilling program was paused in the third quarter to allow incorporation of positive early results from our recently acquired 4D seismic data set that will aid in the optimization of drilling locations. Due to the earlier finish of the 2025 drilling campaign, our full year capital expenditure came in at the lower end of our guidance range. In 2026, we expect to see sustained drilling campaigns in each of Akpo, Egina and Agbami commencing later in the year.

I'll now hand you over to Aldo to take you through the financials.

Thanks, Oliver. In the fourth quarter, Meren completed three oil liftings for around 3 million barrels at a realized all-in sales price of $64.4 per barrel. For 2025, we have completed 12 total liftings totaling around 12 million barrels at an average all-in sales price of $72.2 per barrel. Comparing favorably to dated Brent at $69.1 per barrel. Meren has applied a variety of different hedging instruments to protect the downside while also maintaining partial exposure to potential upside. This will include a mix of physical and financial hedges such as swaps, collars and puts, and you can find further details on this in our Q4 MD&A.

Moving on to financial highlights. Before going through our numbers, it is important to note that we have reported an impairment of $105.3 million this quarter in relation to the Agbami cash generating units. I must emphasize that this impairment is noncash and it has no impact on our cash flows. This charge has come as a result of oil price volatility in 2025 and updated cost forecast relating to the Agbami field.

More specifically, the updated cost forecast is mainly in relation to planned long-term life extension activities, allowing the FPSO to continue to operate reliably and safely through to the end of the license. This will also allow more flexibility on the FPSO to support future infield drilling and tieback opportunities, which we will touch on shortly.

Moving on to our highlights. For 2025, we delivered an EBITDAX of $441 million. This fell just short of our full year guidance, mostly due to a larger overlift adjustment for the period relative to the estimates for the midpoint range of the revised guidance and other smaller variations on Nigerian royalties and levies. Cash flow from operations before working capital came in at $262 million for the year with a reported CapEx of $100 million largely driven by drilling activity in Akpo and Egina this year and facility costs on Agbami, both of which have met our 2025 guidance. Free cash flow before debt service and shareholder distributions was $289 million. As Oliver mentioned earlier, we have significantly deleveraged the business this year, paying down the RBL by $420 million, as well as distributing roughly $108 million in shareholder returns.

Moving on to cash flow for the year. This slide shows the 2025 movements and year-end 2024 cash balance on a constructive basis as if the premium amalgamation had closed on first of January 2025. We ended 2025 with a cash balance of $175 million compared to an opening cash balance of $461 million. Net cash generated in operating activities for the year was $348 million, which included a positive working capital movement of $86 million, primarily driven by the receipt of oil sale receivables driven by the timing of cargo liftings.

The cash outlay of $480 million post consolidation was for the repayments of the RBL, clearly demonstrating our intention to optimize our capital structure and resulted in about $12 million savings in reduction of financing costs. We also distributed a little bit over $108 million during 2025, comprised of about $100 million in base dividends and $8 million in share buybacks.

Overall, through disciplined cash management, we have materially reduced our debt, strengthen the balance sheet and established a solid platform for sustainable growth and value creation. We are also pleased to announce our first quarterly dividend of 2026 of $25 million, which will be paid next month.

Moving on to the next slide. At year-end 2025, our amounts drawn under the RBL stood at $330 million with a net debt position of $155 million and net debt to EBITDAX of 0.4x, significantly below our target of onetime. The chart on the right demonstrates our consistent and prudent approach over the last few years towards debt management with continuous efforts to optimize liquidity while minimizing borrowing costs. It is worth recalling that post premium amalgamation, we canceled an undrawn $65 million Meren corporate facility to eliminate standby fees.

As a post fourth quarter update, we drilled down an additional $40 million under the RBL due to normal working capital timing related to liftings and short-term liquidity positioning within the group. So we have very good flexibility on the RBL revolver facility at competitive borrowing costs. We are currently in the process of refinancing the RBL that facility which will allow us to save more on borrowing costs and to enhance our debt amortization profile. In the meantime, as shown on the right hand side, we do retain an ample liquidity headroom.

Moving on to the next slide. With our full year results, we have also announced our full year management guidance. Our working interest production guidance comparing to 2025 actuals reflects the timing for the recommencement of infill drilling campaign, which is currently expected to start towards the last quarter of the year. Our EBITDAX and cash flow from operation guidance relative to 2025 actuals reflect the lower production base and accounts for a lower full year Brent oil price at $63 per barrel compared to the actual Brent average of $60 per barrel for 2025.

Moving on to the next slide. And before handing back to Oliver to take you through our organic growth opportunities, I will briefly highlight the positive developments in Nigeria. Implementation of the PIA was supportive to our business, and this positive development has been followed by a number of presidential executive orders aiming at facilitating investment in Nigeria's oil and gas sector and tackle project execution risks such as cost inflation and schedule delays. So we are seeing greater fiscal clarity, stronger government engagement and targeted incentives aimed at supporting upstream investments.

Recent final investment decisions on projects such as Bonga North the Ubeta gas project and the HI offshore gas project demonstrate renewed capital commitment and growing confidence in Nigeria as a long-term energy investment destination. For us, a more stable and predictable operating environment is constructive for both capital allocation and valuation across our Nigerian portfolio.

We are also seeing Nigeria's USD credit spreads tightening significantly from peak levels, reflecting a meaningful reduction in the market's perceived sovereign risk and improving investor confidence in the country. This has also been reinforced by recent positive credit rates and developments in recent months. We are very pleased to see these positive developments and continue to have high confidence in Nigeria and its oil and gas sector with clear fiscal and regulatory frameworks supporting our core business and key assets.

I will now hand over to Oliver to take you through our portfolio outlook.

Thanks, Aldo. Turning to Slide 12 and our business outlook, I want to focus on the organic growth opportunities in the portfolio, starting with our production hubs in deepwater in Nigeria. For Akpo and Egina, we are planning to recommence drilling in late 2026 with the Akpo Far East exploration well. Akpo Far East is a near-field prospects located just 5 kilometers from existing production facilities and represents the test of a fast-cycle infrastructure-led tieback opportunity with around 23 million barrels unrisked mean recoverable resource net to Meren.

In a success case, first oil could be achieved through the Akpo FPSO in less than 2 years. The drilling campaign will then move toward infill drilling across both Akpo and Egina from late 2026 and into 2027. And this will add new production as we move through 2027. Beyond that, we have made progress around our undeveloped discoveries, Preowei, Egina South and Ekija, all located within 20 to 30 kilometers of existing Meren production hubs.

That proximity is important as it offers a growth portfolio of short-cycle, capital efficient and lower-risk developments that utilize our existing brownfield infrastructure and together consist of around 42 million barrels of resource net to Meren. At Agbami, drilling also recommends in late 2026 with a campaign including appraisal of the adjacent Ekija discovery and 6 infill wells within the field. We are excited to get back to drilling in 2026 and the combination of testing new, low-cost resource and short-term production growth through infill drilling presents a series of low-risk, high-return opportunities to bolster our production profile and in turn, supports long-term value for shareholders.

On Slide 13, let's turn to another key growth area for Meren, the Orange Basin. Beginning with Namibia, the joint venture continues to progress the Venus development project, which remains on track for final investment decision this year. According to the operator TotalEnergies, FID is targeted for mid-2026, with the environmental and social impact assessment now published and the environmental clearance certificate application submitted marking a key regulatory step towards FID.

As a reminder, front-end engineering and design, FEED, is progressing with a plan for 40 subsea wells tied back to an FPSO with a peak capacity of 160,000 barrels of oil per day and a production life of 20 years plus, delivering significant and sustained cash flow to Meren. As we get closer to the final investment decision, we anticipate scope for us to include Venus in our annual reserves reporting process. Beyond Venus, several material exploration prospects remain to be tested on the license with planning in progress.

And importantly, we retain full exposure to these high-impact opportunities with no upfront cost as all exploration and development spending is carried through to first commercial production. In Block 3B/4B in South Africa, the legislative notification and appeals process remains suspended pending the Supreme Court of Appeals judgment for Blocks 5, 6 and 7.

From a project perspective, the identified lead prospects, Nila is drill-ready and the operator TotalEnergies is ready to commence drilling once the appeals process is concluded. To remind you, the cost exposure to Meren in South Africa is limited with the transaction completed with TotalEnergies and Qatar Energy including a capped exploration carry. Whilst the regulatory issues elsewhere in South Africa of cause delay, our 18% carried interest, combined with the scale of the prospects identified means we remain excited about the potential for the block and its ability to act as a transformational catalyst for Meren.

Now turning to Equatorial Guinea on Slide 14. We hold two operated licenses to offer another set of organic growth options within the portfolio. Starting with EG-31. This is a shallow auto gas position close to existing infrastructure and situated around 30 kilometers from the Punta Europa LNG facility. Through 2025, our evaluation is focused on maturation of the existing Gardenia gas discovery that represents a circa 200 Bcf gross resource with the potential to be developed as a low CapEx, low unit cost short-cycle projects that utilizes capacity in the adjacent LNG facility.

Beyond Gardenia, several nearby gas prospects, Macif and Whistler offer material longer-term growth potential with unrisked gross prospective resource estimates of around 5 Tcf. As part of our wider organic growth options, EG-31 provides an attractive rightsized LNG opportunity with low CapEx exposure through utilization of existing gas and LNG infrastructure.

Moving to EGA team, a deepwater exploration block with oil prospectivity. We have identified basin floor fan targets with multibillion barrel potential in a series of stacked prospects. Across both blocks, we have been running a farm-down process. And whilst the two opportunities offer differing investment profiles, industry interest has been encouraging, and we are now in active discussions with potential partners.

Importantly, we have secured 2-year license extensions for both blocks, giving us additional flexibility as we progress partnership discussions and align next steps with the government. With the right partners in place, drilling activity could take place in the next couple of years.

Moving to Slide 15. I want to bring together these catalysts to outline the breadth and scope of our organic growth portfolio set across four countries and multiple basins. Whilst delivering corporate transformation from Meren in 2025, we have remained focused on active in deepening our evaluation of organic growth options and are confident as we move through 2026 that we are building a strong portfolio that offers compelling growth through choice and most crucially, whilst remaining within our disciplined approach to the balance sheet and financial frame.

I'll conclude on Slide 16 and revisit our capital allocation priorities. Disciplined capital allocation underpins our business plan and the execution of our long-term strategy. Firstly, our balance sheet remains a core pillar of the business. Throughout 2025, we have demonstrated that discipline, and we will continue to maintain a minimum liquidity position of $150 million and a net debt to EBITDAX target ratio of 1x or less.

Secondly, we see compelling value creation in our organic growth portfolio. Our Nigerian assets provide multiple pathways to grow production through infill drilling and subsea tiebacks. These low-risk short investment cycle opportunities, leverage existing infrastructure, generate capital-efficient returns and help build a durable foundation for long-term value creation.

With a streamlined business firmly in place and a strong balance sheet, we continue to selectively screen inorganic opportunities that meets our strict strategic and financial criteria, ensuring they are accretive and complement our existing business and priorities.

Thank you, and I will now pass you back to the operator for Q&A.

[Operator Instructions] First question comes from Jeff Robertson with Watertown Research.

Thank you. Good morning. Aldo, can you talk a little bit about the timing of the liftings you anticipate in 2026?

Yes. So for -- we have to look at the lifting as per FPSO, right? That is discretionary, and that creates the timing difference in relation to the liftings. So for 2026, we are expecting around eight cargoes spread throughout the year. So I think it's safely to assume they are evenly spread throughout the year just for simplification purpose.

And Oliver, with respect to EG, does the 2-year license extension give the potential partners that you have had discussions with time to get an exploration well drilled on EGA team?

Yes. Jeff, yes, I think the 2 years is important in the sense of -- as we said in the presentation, we are in active conversations on both positions, and they are very different things, of course. But what that 2 years does is, it just gives us a runway to complete those conversations and see where we get to without license time pressure, if you like, which is good. It signals strong support from the government for the ongoing process.

And to the specifics, yes, I think, look, it depends exactly when we might close the transaction and who it's with. But I think it's sufficient time to mature and drill a well. I think when you look at 31, we're very focused on Gardenia because that's a discovery. So that's kind of appraisal development straightaway that shallow water is technically not challenging. Quick to do. And 18 is deepwater. But again, we have one very, very high-graded prospects. I think people have looked at it take different views, of course, but they see the same prospect.

And so therefore, you know what you're going after. It's not a matter of saying well, hey, let's get a partner and then rework the whole block. So yes, there's a reasonable time line there. I think next key step is kind of as we go through the first few months of the year here, where do we get to on the commercial front? And can we get the right partnership in place so we get the right funding structure to unlock both opportunities.

Under the timing of the extension for Block 18, would the permitting of an exploration well add any time to the extension such that a group could consider the results of the well?

Yes. So I think in the detail of it, you've got a 2-year -- well, whatever license period you've got, say, 2 years in this case. You drill a well, you make a discovery, let's say, and then you move in, in the contract, it defines kind of appraisal periods, commercial evaluation periods before you would declare commerciality and that brings time to do that, if that makes sense.

So the first period is in summary, really for the first primary activity. And then depending on success and how clear it is from the first well, there is a period for appraisal there where you can come and put an appraisal plan together. That could be more appraisal drilling. It could say, well, hey, I'm going to test a well or whatever, but you have that period to do that.

And lastly, for now, with respect to inorganic growth, Oliver, when you think about Meren's current opportunity set over the next couple of years, which would require capital dollars. What type of asset it's best in the portfolio do you think?

Yes. Good question. So I think I'll start with what we have today, and I think hopefully you saw that in the presentation that I'll take a step back, really when we completed the prime amalgamation, of course, we were doubling down on production reserves, cash flow that we knew well because we've been a co-owner.

We also knew there was a lot of organic growth opportunity in there. So exploration resource, contingent resource, high-value stuff. I think as we've moved through putting the two organizations together with a bit more capacity over the last 6 months, we're more excited about that. So I think we see a lot more opportunity around that portfolio for tiebacks to the three FPSOs. EG, as we've just talked about, we've matured that very well, and that's come a long way and looks exciting.

So I think that set of opportunities in the company today is exciting and I think has emerged in a very strong way as a set of options. The other backdrop there, and Aldo touched on this in the presentation is the Nigeria landscape has drastically improved. I think both fiscally, politically support, you see production rising there quite quickly. You see investment dollars coming back from international firms as well as local companies. So there's a better landscape there beyond the technical for maturing things in Nigeria.

So in sum, we're really excited about what's in the current portfolio. When you look at the character of that, it's high-value contingent resource coming into production short period, but infill drilling next couple of years, new kind of tiebacks end of the decade. So that's great, and that delivers a lot of value. What it does mean when we look at the inorganic space is we say, well, look, are there opportunities out there that could add production, cash flow, scale up the business in that respect in the shorter term.

So they would complement the growth that's in the current portfolio, but they would kind of build the balance sheet, build the operating cash flow, let's say, and help us kind of fund some of those organic opportunities because, again, as we show our kind of capital allocation, we're not going to overlever the business to do that stuff, right?

We develop a series of options, but we're choosing which ones to do in the context of that disciplined balance sheet. So again, some inorganic growth, if it's the right opportunity. And again, we're very, very disciplined on that, could help unlock some of those barrels as well

[Operator Instructions] Our next question is from David Round with Stifel.

Perfect. Sorry about that. A few questions from me, please. The first one is on the gas sales agreement. I read something about that this morning. Just wondering if you can give us a sense of how meaningful that may or may not be. The second question for me, please, is you've mentioned ATCO Far East and Acacia as specific targets.

Just wondering how quickly those could be tied back in a success case. And I suppose if that is going to take a few years, how many infill wells should we be assuming each year to support production in the meantime? And if I -- actually, I'll sneak just a follow-on to that. You've got a '26 CapEx budget of $100 million to $140 million, I think. Are you able to just break that down for us, please, just in terms of how many wells are assumed in that? Is it all just long lead items, please?

Yes. Thanks, David. I'll take the first one on the gas and then I can come back on the second one, and we can get to the third.

Yes. Okay. So in relation to the gas sales agreement, it was a result of a prolonged negotiation that we were having to revise the index that's based on the contract that we signed back in 2018, given that it took some time to get that result.

So there will be a couple -- a few impact that you're going to see through cash flow and P&L in the coming period. So there will be first one lump sum payment that we're going to receive now in the first quarter of 2026. Second, there will be an increased price coming from the revised index, which will flow through all the periods as we produce and export the gas from Akpo and Egina and there is a third component, which is the recovery of the arrears, right?

The difference between what we should have received back from 2020 compared with what we have received and that delta we will receive also in time through a reduction of the handling fee. So you should expect a larger impact in 2026, given to the resolution of the contract. And let's say, on an ongoing basis, we are talking maybe something about, let's say, doubling the gas revenues that we have comparing with the last 2 to 3 years. So it should be meaningful, especially in the first year.

Okay. I think on the second one, David, it's a good question on Nigeria. So maybe I'll just take a step back. We're getting two rigs back end of this year, which we'll come on to on timing and your CapEx question. But actually, what has happened is we've had the longest drilling break across the three deals since kind of first oil. So when you look at our '26 guidance, it's effectively that's what it reflects.

There's, of course, natural decline, as you'd expect. But we've had this long drilling gap that, again, we haven't really had before. And that's probably what's underpinning that decline. So we turn to how do you firstly arrest that decline? And then how do you grow from the base, if you like. So I think in terms of arresting the decline, it's, as you said, the infill drilling.

So when we look at that next program, to start with Agbami, rig will come somewhere at the end of this year. I mean there's operational uncertainty on exactly what time the rig arrives. But nevertheless, it's firm, it's coming. And there are 6 infill wells planned on Agbami through '27 across the year. So when you look at that, I mean, that's quite -- for a field of that age, it's quite positive. It's quite sustained. So there's a relatively big infill drilling campaign there, which will arrest natural decline. And then we go across to Egina and Akpo with TotalEnergies operating.

And again, in parallel, if you like, TotalEnergies are contracting for a rig. The plan is to bring the rig in again, towards the end of this year. So we're kind of guiding Q4 plus or minus operational kind of issues on where the rig is coming from. And again, interestingly, there's two buckets of opportunity there.

One is the kind of Akpo Far East, so testing growth, either prospective resource that's near field, contingent resource. And then as we move into '27, the focus will be on infill drilling Egina and Akpo, so three wells there. So that gives us in the kind of near term, if you like, at the end of this year, the kind of barrels that are coming on stream. It will be early '27, but barrels come back on stream and rest of natural decline. and equally gives us some more certainty on prospective resource, contingent resource and how that may play out.

On the latter, I think reality for the tiebacks is Akpo Far East is quick because it's 5 kilometers from the FPSO. So we hope to get first oil from that in the success case in less than 2 years. And I think the wider tieback opportunity set, we didn't talk about it today really, but Preowei near Egina, there's Egina South, which is a similar size discovery to the south of Egina.

Those things are kind of 3-year cycle. And again, we are optimistic of making project progress on those this year, and then that would be Preowei first oil '29. Egina South, a bit more uncertain, but again, 3-year cycle, so kind of end of the decade. Akpo, which we did mention is a potential tieback to Agbami.

And again, similar to the well that we will drill probably end of this year, early next year, that's an appraisal well. So again, it's discovery contingent resource. And depending on what we find in that appraisal well, that's again circa 3-year cycle tieback to Agbami. So I think I'd characterize it good campaign of infill drill coming in the short term, kind of end of this year, good testing of contingent resource that gives us kind of a lot of options for growth barrels end of the decade. And then that leaves us kind of one more gap, which is, well, what more infill drilling is there to do before the end of the decade to keep production up in the fields.

And so I think there we see 2 or 3 options at least in Egina and Akpo, so potentially '28, '29. And in Agbami, 6-well campaign is pretty big anyway, but we're working there on is there another similar campaign a year or so later. So I think we'll be on and off active on the infill drilling in summary through to '29, 30 with the aim of sustaining base production. And again, in parallel, that keeps us going while we grow the kind of contingent resource projects and prioritize which of those are the best to do.

Okay. That's really helpful. And sorry, just a final one, just around CapEx for this year. I mean, is that mostly long lead items?

It's -- there's some long leads in there. I think the range that you see is really the timing of rigs arriving. So it's a classic year-end issue. So we're planning on Q4, but those rigs could arrive just contractually operationally, possibly Q3, and they could equally arrive late Q4. So it gives us a bit of a range on that number. But it's primarily -- we're assuming the wells are drilling Q4, so it's CapEx in the ground as it were. We did put some numbers in some CapEx into long leads last year for Agbami, for example. So that was done kind of '25 mainly.

Our last question comes from David Mirzai with SP Angel.

Firstly, on exploration, you've got Far East Deep. You've got [indiscernible]. Is this in reference to deeper reservoirs or down fault? Have you intercepted them? What's the reservoir like? What's the kind of risk both around volumes and deliverability in regards to these prospects?

Secondly, appraisal. You pointed out your contingent resources on Preowei on Ekija in South in Nigeria, but also the existing Gardenia discovery in Equatorial Guinea. Obviously, these discoveries have been around for a while. You've had capacity in nearby facilities and they haven't been developed. What's the key hold up, the key contingent reason behind these resources not being developed to fully utilize their respective FPSOs?

And just lastly, on scale, I mean it's quite kind of observable to any analyst and investor that the market wants fewer oil and gas companies with greater scale, broader portfolios, more ability to finance their own developments and that they reward effectively higher cash flow with lower debt levels and with greater liquidity.

Now having gone through the process of combining in Prime, that's clearly the next step forward for you. And I just want to kind of get your thoughts around what scale is enough or what your investor base is really looking for you to bring you up to the next level.

Yes, thanks for the questions. I think we start with the first one, the exploration point and kind of split that up. Akpo Far East is exploration. So that is prospective resource, let's say, it's kind of 1 in 3, 1 in 4 chance of success geologically. I think -- the commercial chance of success on the back of that is extremely high because it's very close to the existing infrastructure. It's within the kind of field physical ring fence, if you like.

So the economics are extremely compelling. So it wouldn't take a huge volume there to reach commerciality. So that one is about geological chance of success. I think the others, just to segue that. So Ekija Egina South are appraisal. So those are contingent resource for us today. So the discoveries that we think, again, are strong candidates for tieback and development, but they do need some appraisal drilling to confirm volumes and technical parameters.

And then Preowei is slightly different again because that is actually reserves for us, that's 2P reserves. And that really reflects the fact that Preowei has been very advanced as a project. It was delayed in COVID as many things in terms of CapEx contracting costs, but it stayed in 2P reserves for us because it's very advanced as a tieback to Egina, and that's a project that we are pushing with the operator and our partners to mature this year towards a final decision.

So they're all slightly different. I think the only pure exploration one in that set is Akpo Far East. The others are really about appraisal and again, just rightsizing, improving commercial volumes. I think the second question, the wider point on Gardenia and some of the other resources. Look, I think there's a timing point to a lot of this stuff. So in two respects, one, the projects themselves and actually the second one, the market, which I'll come back to because I think it also addresses your third point.

But if you look at our three FPSOs in Nigeria, huge fantastic facilities, huge capacity. They've been full for most of their life, of course, and their varying ages. They are in this natural decline phase, which you see in the base production. But what that means is there's an optimal timing point here of saying, well, actually, when is the right time to develop resource to backfill those facilities.

And that's now because you don't just want to be able to bring a small amount of resource in. And of course, you want -- for the economic development, you want to be able to maximum development of something like a Preowei. So I think the timing point is partly on the infrastructure and when is that infrastructure available, when is the right time to backfill. I think specifically, again, on EG, look, we've had that block for a couple of years, '31, but having worked that through, matured it, particularly Gardenia as a discovery.

Again, that's a timing point in that the monetization is through the existing EG LNG brownfield facility. And so it's the optimal timing of doing the project, knowing that there's capacity in the brownfield infrastructure, which you will use to produce LNG off the back of it. So I think that timing is now.

So again, we'll make decisions on all of those through the coming period in terms of the right thing for capital allocation. But certainly, the project aspect has unlocked. I think more broadly, again, the second point on that, where is the industry? And I think you alluded to it again in your third question, but the industry is back in a kind of growth mode.

I think a lot of bigger companies are short of resource. And so there's a lot more support for the right type of project, the right type of CapEx. Now again, from our perspective, we are super disciplined on the balance sheet. So lots of good opportunities, but what we're not going to do is overleverage the balance sheet, expose ourselves to CapEx overruns, et cetera. So we'll do it in a prudent way, but I think it's a good time to be maturing contingent resource and pushing that into reserves and ultimately monetization. So there's a macro backdrop, I think, is important there as well. I can move on to the third question, David, or if that covers your first two.

Sorry, I was just being unmuted there. Yes. No, just to dig down on Akpo Far East, what is the geological risk, sorry?

Geological sorry, specifics. Yes, it's trap really. So the reservoir is same as the Akpo field. So we understand it well. It's a phenomenal in the detailed kind of type permeability reservoir, super good fluids.

So the thing on Akpo Far East is the trap. Is there an updip trap that works? And then I think there's a secondary more commercial risk on fluid. But that's secondary in two senses, one that we have a good handle on the seismic. So we think we understand that fluid and it's oily and we can characterize that.

And actually, the second part of that, Akpo, of course, is a very gassy field, and we export that gas. And as Aldo just talked about earlier, we've got improved pricing on that gas as well. So I'd say that's a secondary risk, but the geological -- fundamental geological risk is trap, yes.

That's great the first two. Obviously, question three around scale. You've talked in your first two answers that you're being prudent with the balance sheet because cost overruns. Obviously, there's that argument that if you are twice as large as you are now, you have to be a lot less risk averse.

Yes. No, I think it's a great question. And I think in terms of the strategic position of the company, again, I'll take a step back. 25 years ago, we were Africa Oil as it was, a completely different company, much, much smaller in scale. You roll forward through that period, we've doubled reserves, production, et cetera, which has been a big step forward in the scale sense.

I think that has allowed us to mature some of these projects in a better way with more confidence because of the scale. So I think it speaks to your point. As we then look forward, look, I think there's a balance here because I recognize and agree with the points you make about the industry. I think it is overdue this space within the industry, let's say, the international independents.

It is overdue some consolidation, some capital efficiency, G&A efficiency, et cetera, absolutely. And we see that. I think when you come to execute around that, I think, again, our message is disciplined. So yes, the ultimate prize does all the things that you described, again, agree with that. So for us, it's not so much that fundamental principle. It's the pathway to get there.

So again, we look at the business today, it's incredibly strong balance sheet. We have some natural decline in production this year, but it's arrested and we go back into kind of growth through the end of the decade. We didn't, for example, in this call, talk about Venus and Namibia, but Total have signaled very publicly that it's FID this year that adds barrels for us in 2030 on their time line. So we go back into that mode.

So I think great. But what we're saying is, look, we protect that. That's always the #1 job is to protect that business, make sure it's robust. But equally, go and look at inorganic transactions that are accretive to that. And then they really have to be. We don't want to dilute that business just for the sake of scale, but we recognize there are steps that we could make that give us both scale and they are accretive. And those are the things that we are kind of narrowing our focus to. But I think short answer is yes, we are still active in that world. We still look at things. But again, we do it with rigor and discipline.

There are no further questions at this time. I will now hand back to Mussannah to read through your written questions.

Thank you, operator, and thank you once again, everyone, for joining today and submitting your questions. I'll go straight into the questions. So I think one for you, Oliver, is given the transformative potential of the Venus discovery, we currently have 3.8% effective interest through our stake in Impact. While this free option structure is highly capital efficient, does management view this level of exposure as sufficient to capture the full value creation potential of the Orange Basin? And is there potentially a pathway or a world where we increase that exposure?

Yes. Look, I think it's obvious question on Namibia and Impact. And again, for the third time on this call, take a step back. I mean, if you go to where we were a few years ago with this, Impact has done a fantastic job over a decade of driving Venus as a target at play, attracted TotalEnergies in, got the well drilled, made a great discovery.

As co-owners of Impact, we're faced with the kind of interesting dilemma here that this huge world-class discovery, but of course, it quickly needs capital funding and capital funding of a big scale. I think as we've outlined many times on these calls, we've got a funding solution in place.

We're not exposed to the capital, and we transformed that into a kind of CapEx demand that we couldn't fulfill into one that becomes a growth is a growth opportunity, adding barrels in 290. I think that then takes you to a place that says, well, it looks great. We'd like to have more.

But I think with respect, we have another large shareholder in Impact. It's really the two of us own kind of 97%, 98% of that company now. And so we both see that. So I think, yes, in principle, of course, we'd like more exposure to a project with no CapEx or risk exposure and lots of barrels coming. But recognize that equally our fellow shareholder also sees the same attraction. So yes is the short answer, but the execution path on those things is a bit trickier.

And then one for Aldo. Aldo, could you please give some more detail on the Agbami impairment and the increased costs expected going forward?

Yes. Of course, I think in Agbami was what we tried to explain throughout the materials that was not just related to one single item, right? So it was a combination of lower oil price and an increase in costs, mainly in relation to the life extension of the FPSO.

So in terms of oil prices, I think that's obvious, right, throughout 2025 in relation to the decline. And then more specifically in relation to the Agbami FPSO life extension, Agbami will continue to produce beyond 2044, which is currently our license -- next license renewal period. So there's a significant amount of reserves already as 2P to be recovered from the field.

However, what the life extension allow us to do not only to recover these additional reserves in a safe and reliable way, but at the same time, allow us to continue to invest or to develop or to plan for bringing contingent resources as 2P, right?

And the 2P numbers are the ones we use for the impairment calculation, the recoverable value, but the 2C numbers, so the additional few wells that Oliver mentioned beyond the campaign 27, 28, [ Ika ], which is a to the Agbami FPSO, as well as other nearby opportunities outside our blocks -- those will all -- would all be produced through the Agbami FPSO.

However, we need to make this investment upfront to extend the life of the facility and make sure that we comply with all the requirements and certification as well as having a reliable FPSO. So I think it's just a reflection of that. And when we get to mature midlife fields that we have to go through this exercise. So that's the detail behind the impairment on Agbami.

And just two more, I suppose, for you is can you give us some thoughts on the percentage of total hedging for 2026? And I think the second from this investor was can you just give us some color on our plans for the RBL going forward?

So first of all, in relation to hedging, we have a policy where we hedge between 70% to 100% of our post-tax net entitlement production on a rolling 12-month basis. So what does that mean? It means that we check first, the amount of barrels that are exposed to oil prices, right, as we have cost recovery, for example, in our agreements in Nigeria, that means that not all barrels are exposed to oil prices, right?

So we first calculate the post-tax and net entitlement and out of that, we hedge between 70% to 100% on a rolling 12 months basis. Now we make a combination of either physical port sales or swaps where we lock in the price that's close to the forward curve at the moment that we enter into the hedge. But we also have a mix of solar and food structures where we keep some participation on the upside as well for a certain percentage of these hedges.

So that being said, at the end of 2025, we had approximately 3.5 million barrels of oil for 2026 sales that were hedged through a combination of physical and financial instruments. Out of that, 2.3 million are on the first half of 2026, which those are primarily hedged through the physical for sales, so through the physical offtake agreement with an average floor price of around $62 per barrel.

And in the second half of the year, we have 1.3 million barrels hedged using a mix of swaps and collar structures. So we provide good downside protection, but we also retain some exposure to the upside. So that's in relation to the hedging part.

For the RBL, I mean, as we saw through the presentation, our numbers, we -- it was very important for us in 2025 to pay down a substantial amount of the RBL facility, right? We had -- we started the year 2025 with substantial large cash position and to reduce financing costs, it made total sense for us to pay that down and reduce the financing costs.

As we mentioned throughout the presentation, we estimated that we save around $12 million in financing costs just by doing that. Now the next step in relation to debt management, the last time we refinanced the RBL was in 2023 on the back of the license extensions in Nigeria.

So we are now getting to that period where to keep a substantial headroom in the RBL facility, not necessary to utilize the money, but to have the flexibility to do so. We are in the process of refinancing the current RBL and we expect to finalize that sometime soon in the first half of 2026. So with that, we increased the RBL capability. But at the same time, we will continue to be very disciplined of how much we draw from the facility to reduce financing costs.

Thanks, Aldo. And then Oliver, I'll put this one to you, and it's something you briefly touched on a little earlier. How much risk do you see when it comes to securing the Nigeria drill rigs this year? And if you could just give us some more color on that?

Yes. No, I think we're not concerned about that. I think we're very advanced, both joint ventures in the recontracting process. So I think we'll -- we're very confident those rigs will come this year that we'll get back to drilling.

And again, I think what's been a quiet period for us, and that reflects our production, but actually, we're going to turn that around with those rigs coming towards the end of the year. And again, a combination of infill drilling, short-term barrels and getting back to testing some contingent resource and long-term growth and value.

So look, I think first part of the year operationally quiet while we finalize the campaign. But then as we move into the latter half, it's pretty exciting for us to have two drill rigs again active for a prolonged period on our major assets. So I think that's quite a positive view to the year overall.

Oliver -- and just keeping on Nigeria, as a question, our reserves have dropped from 2024 to 2025. Of course, there's been a portion of production in there as well, but maybe you can give some color on that and how we're arresting that decline.

Yes. And again, I think if you look at the shift in 2P, that is dominantly the produced resource. I mean every year, you're going to get some minor ups and downs on your kind of existing well stock and fields based on latest performance. But again, when you look at the year, it's really around the fact that we've had this, again, longest period in the kind of history of the fields without active drilling and adding new wells.

And so you see that in the sense that you produce 2P reserves faster than you're replacing it in that context. But I think again, the two key points are, you look at our contingent resource, that has grown significantly through '25. So again, in terms of options for future value and growth of the business, that's good.

And secondly, again, to the prior question, we're very confident that we're getting back to drilling here, not just with 1 rig, but with 2 and sustained campaigns starting end of '26 through '27. And therefore, we'll start to grow again on that time period, which I think is really positive as we look at the cycle, oil price cycle in particular.

And just two more before we close off. So when we speak about capital allocation, balance sheet strength and organic opportunities are the first 2 that we speak about. Just what should everyone read from this? And then shareholder returns, of course, and M&A coming third or inorganic opportunities, I should say.

Yes. I think we've been very focused on the balance sheet, and we talked about that a lot on this call. And I think, again, that's important as a base to the business.

Aldo talked about the moves we made last year. We paid down debt. We've got a lot of liquidity. We've got low leverage. And I think the way people should look at that is it's prudent. It's, of course, a volatile world, and I think our view is it will remain so. So we just have to deal with that.

But starting with a strong balance sheet opens up a lot of options for us. It opens up options to allocate capital for organic growth, options to, as we are doing, returning cash to shareholders. And again, we've touched on it, the inorganic growth. It puts us in a very strong position to test from that kind of balance sheet, is there an organic transaction out there that makes sense for us?

And is it better than the kind of organic growth capital allocation options we've got in the portfolio today. But that balance sheet gives us choices. And I think that's what's really key in this message is strong balance sheet, strong hedging in place for this year, very, very good foundation to grow the business, right? And there are a number of choices to do that, and we're always seeking to have those choices.

And in parallel, again, we've been very strong on shareholder returns to recognize that we want to grow the business, but equally, we're not going to grow it at any cost.

Perfect. And just lastly, and one on EG. Given the size of the prospects in EG, would it be possible to go into EG-31 alone? Or how much are we willing to give away farming to a partner?

We're definitely not going to give anything away if I put my commercial heart. But look, I think we're 100% in those licenses. Our partner is GPetrol a state national oil company. And so they have 20%, but they're carried in the early stages here.

So it's 100% funding. So look, it's just -- it's a risk allocation and capital allocation that we're not going to do a project at 100%. That's not a statement of view of risk or value on the project at all. It's a point of saying, again, it's a portfolio effect, it's risk sharing and it's bringing in strong partners helps any project, and that's our focus. I think the important point on 31 is, again, we need to be really clear that the Gardenia discovery itself is something that could become a short-cycle fast track development with the right partnership in place.

So it's not high-risk exploration dollars. It's lower risk short-cycle brownfield LNG, which could be incredibly low-cost resource for us as a company. So look, we wouldn't do 100%. But equally, we want to hold a material position in the project, recognizing the potential value it can bring to us.

And again, I'll go back to the theme of it's around prudent capital allocation and discipline within that. Great growth options, we'll pursue them, but we'll do it in the right way that doesn't jeopardize the company.

Okay. Thanks, Oliver. That's all the questions we have for today. So operator, I'll hand back to you to bring us to a close.

This concludes today's call. Thank you for joining. You may now disconnect.

Hello, everyone. My name is Sophie, and I will be your conference operator today. At this time, I would like to welcome everyone to Meren's Third Quarter 2025 Results Presentation. [Operator Instructions]. This event is being recorded, and the recording will be available for playback on the company's website. I will now pass the meeting on to Mr. Shahin Amini, Meren's Head of Investor Relations. Please go ahead, Mr. Amini.

Thank you, operator. Hello, everyone, and thank you for joining us for Meren's Third Quarter 2025 Results Presentation. I am joined today by Roger Tucker, our President and Chief Executive Officer; Aldo Perracini, our Chief Financial Officer; Oliver Quinn, our Chief Commercial and Operating 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 that are available in SEDAR+ and on our website. Also, all dollar amounts in this presentation on U.S. dollars unless otherwise stated. With that, I will now hand over to Roger. Roger, we are ready for you. Please go ahead.

I am pleased to present another strong quarter with continuing delivery on shareholder returns and delivery. The completion of the prime amalgamation marked a step change for Meren, and we have now honored our enhanced dividend policy with the declaration of the fourth quarterly distribution of $25 million, taking the total payout for 2025 to $100 million. So together with our share buybacks year-to-date, we have delivered meaningful shareholder capital returns of approximately $109 million.

We have also materially reduced our outstanding RBL debt amount to underpin a stronger, more agile company that is built to deliver long-term returns and withstand market volatility. These deliverables reiterate the quality of production assets in Nigeria and the company's financial strength and our disciplined capital management. Maintaining a strong balance sheet continues to be one of our top priorities. Overall, it's been a resilient quarter and we've delivered on we set out to do, reinforcing our financial position and our commitment to creating long-term value for our shareholders.

I'm also pleased to report that we have completed the integration of Prime and the combined organization is working very well and seamlessly under the Meren banner. I will now hand over for Aldo to give a more detailed commentary on the quarter's performance.

Thanks, Roger. Now turning to our production performance. In the third quarter, we delivered production of 31,100 barrels of oil equivalent per day on a working interest basis and 35,600 barrels per day on an entitlement basis. This brings us to a working interest of 31,800 barrels of oil equivalent per day and 36,300 barrels of oil equivalent on an entitlement basis for the first 9 months of the year, both of which sit within our 2025 guidance, which remains unchanged from the second quarter.

Performance remained steady quarter-on-quarter, supported by strong contributions from the newly commissioned Egina wells and a successful well intervention on an Akpo well. These gains helped offset temporary impacts on plant and maintenance activity. With the Akpo and Egina drilling campaign now on pause, work is focused on integrating for the seismic and well data to define and mature the next set of infield targets.

Turning on to the next slide. In the third quarter, Meren completed 3 oil liftings for around 3 million barrels at a realized all-in sales price of $70.8 per barrel. Year-to-date, we have completed 9 liftings of around 9 million barrels at an average owing sales price of $74.9 per barrel, which compares favorably to the Dated Brent at an average of $70.9 per barrel.

We have 3 cargoes scheduled for the first quarter of 2025. Two of these are hedged at $64.6 per barrel with 1 cargo unhedged that will be sold at spot. For 2026, we have hedged 2.6 million barrels of oil at an average Dated Brent of $62.4 per barrel. The sales achieved in the first 9 months, combined with our hedging strategy for the remainder of the year, creates a prudent balance between risk management and market exposure, reducing volatility risk while preserving potential upside. This approach ensures we remain well positioned to generate solid cash flows through to the end of the year regardless of market fluctuations.

Moving on to the financials. For Q3, we delivered an EBITDAX of $120 million, bringing total EBITDAX year-to-date to $368 million. Cash flow from operations before working capital came in at $66 million for the quarter with reported CapEx of $22 million, largely driven by the web intervention in Akpo. Free cash flow before debt service and shareholder distributions was $126 million.

Overall, for the first 9 months, free cash flow before debt service and shareholder return stands at $229 million. We are on track to meet our management guidance as revised in Q2, and our full year guidance ranges are unchanged. Let's now turn to cash flows for the period.

We closed the quarter with a cash balance of about $177 million compared to an opening balance of $267 million at the end of Q2. We achieved about $66 million in cash flow from operations before working capital adjustments and interest and had positive working capital movement of $81 million, most of which about $63 million was due to trade receivables driven by the timing of cargo liftings and receipt of sale proceeds between the second and the third quarters.

Our major cash outlays were RBL repayments, dealing distributions and capital expenditures. In line with our approach to disciplined balance sheet management we proactively paid down our RPO balance by $18 million, bringing our total debt to $360 million. This has been paid down further post quarter, which I will touch on shortly.

In line with our new payout policy, we made our third dividend payment of $25 million, bringing dividend distributions to $75 million year-to-date. And as Roger had mentioned, we are pleased to have announced our fourth dividend distribution of $25 million to be paid next month. Through disciplined cash management, we have materially reduced our debt interest expenses strengthen the balance sheet and establish a solid platform for sustainable growth and value creation. Moving on to the next slide.

Deleveraging the business has been a priority for us since assuming Primes are beyond facility following the amalgamation. The balance was $750 million at completion. We have looked to approach this proactively and in a disciplined manner. At the end of Q3, our RBL balance stood at $360 million, reflecting $390 million in repayments since taking this facility on, contributing towards a meaningful reduction in interest costs.

Post quarter, we paid down $430 million, bringing total repayments to $420 million year-to-date. At the end of the quarter, we had a net debt of $183 million and a net debt-to-EBITDA ratio of 0.4x, well below our onetime ceiling for the year, demonstrating our strong credit profile. We will continue to optimize our capital allocation strategy, strengthening Meren's financial profile and positioning us to deliver value for shareholders. I will now hand over to Oliver to take you through our business outlook.

Thanks, Aldo. Turning to Slide 10 on Nigeria. Following the break in the Akpo and Egina drilling campaign in Q3, work is underway to restart the campaign. The current drilling break has provided time to fully interpret the latest 4D seismic data and identify several future infill drilling opportunities. Operationally, progress is being made to secure a deepwater rig to drill the Akpo Far East nearfield prospect, followed by further development wells on both Akpo and Egina in late 2026.

Akpo Far East is an infrastructure-led exploration opportunity with an unrisked best estimate of greater than 150 million barrels of gross oil equivalent. If successful, it will deliver a short-cycle, high-return investment, leveraging existing Akpo facilities and potentially adding significant near-term production and reserves.

Turning to the Preowei development. Project optimization work continues with recent seismic data indicating an increase in recoverable resources and likely better connectivity in the reservoir that may lead to a reduction in the development well count. This optimization exercise is continuing and will conclude through 2026.

At Agbami, interpretation of recent 4D seismic is ongoing alongside rig and long lead item contracting in preparation for a 2027 infill drilling campaign. In addition to the infill drilling an appraisal well is planned on the Ikija discovery, which in a success case will be tied back to the Agbami FPSO.

Let's move to Slide 11 for an update on Namibia. Joint Venture continues to advance the Venus development, which remains on track for FID next year with first oil expected in 2030. The environmental and social impact assessment is continuing to progress, which is a key step towards regulatory approvals. The plan outlined includes 40 subsea wells tied back to an FPSO with a peak capacity of 160,000 barrels of oil per day and once online, Venus could produce for more than 20 years, generating significant and sustained cash flow for Meren. 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 Canadian NI 51-101 reporting process.

On the exploration side, work continues to plan for drilling on several remaining prospects with Olympe remaining the key target and testing a different geological concept from Marula and with a significant potential resource base. And importantly, we retained full exposure to these high-impact opportunities with no upfront cost as all exploration and development spending is carried through to first commercial production.

Moving to Slide 12 and staying in the Orange Basin. Let's turn to South Africa and Block 3B/4B. In September last year, we received an environmental authorization to drill up to 5 exploration wells. And whilst progress is being made to move through the legislative appeals process, this has now been temporarily suspended pending a Supreme Court judgment in relation to Block 5, 6 and 7.

Despite this pause, the operator continues to prepare for drilling with the Nayla prospect remaining the likely first target and with sufficient potential in a success case to support stand-alone development. To remind you and important to note, the transaction completed with TotalEnergies and QatarEnergy last year will cover Meren's costs for 1 to 2 exploration wells, so there will be no demand on our capital as drilling commences. In summary, across the Orange Basin, we maintain a leading independent E&P position with exposure to multiple near-term development and exploration opportunities and all without any near-term capital requirements.

Now turning to Equatorial Guinea on Slide 13. Meren holds 2 licenses offering differing opportunities. In board, Block EG-31 offers a compelling low-risk appraisal opportunity that could unlock a low CapEx, short-cycle brownfield LNG project with a cost of supply competitive with U.S. gas exports. The block lives and shallow water, close to the existing onshore EG LNG facility and contains several further gas prone prospects in areas where historic wells have proven the presence of gas.

The second position, Block EG-18 is a deepwater exploration opportunity with billion barrel scale oil potential. Recent seismic reprocessing and technical evaluation has unlocked a large Cretaceous age basin floor fan system with several stacked prospects identified within the same play that has been actively pursued by several majors across the border in São Tomé.

A farm-down process for both positions has attracted strong interest, and we are actively engaged in discussions with potential partners for 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 comments.

Thank you, Oliver. It's been a solid quarter for the company. We ended the period with a strong liquidity position and net debt to EBITDA of 0.4x and we have significantly reduced debt to optimize interest expenses, underscoring both the strength of our balance sheet and our disciplined approach to cash management.

I'm pleased to have announced our fourth quarterly dividend, which will see the completion of our $100 million dividend plan, a clear reflection of our ongoing commitment to shareholders. Looking ahead, we see meaningful value across our portfolio with excellent catalysts in the pipeline, each providing strong long-term growth potential. Thank you. And with that, let's move to the Q&A.

[Operator Instructions]. Our first question comes from Jeff Robertson with Water Tower Research.

However, can you give some insight into the production profile in 2026 in fields in Nigeria? And what you anticipate the lifting schedule might be for the first couple of quarters of the year?

Yes. Jeff, thanks for the question. So as we go in to '26, we've got activity commencing again in the fields. We've got 3 wells, if you like, 3 infill well activities, Akpo and Egina. Now we've got an Akpo Far East exploration well, which is important and likely in the Ikija well over on Agbami, which is appraisal. So I think the key thing is on those wells, they'll be back end of the year. So we don't expect to see a meaningful production impact from them until early 2017. So they're important, but they're late in the year.

So where that takes is we'll see some natural decline through the year. And I think we're currently working through the final work program and budget with the operators in the next couple of weeks here, but we do anticipate kind of seeing decline into the kind of high 20s in terms of production at working interest level before, again, that picking up again as we come through the end of the year and into '27.

I think on the second part, the lifting schedule, I think we're anticipating around 10 cargoes it's a pretty evenly spaced throughout the year. I think you'll note this year, we've lifted all our cargoes for the calendar year as of November, so we don't have any in December. And then I think our next cargo is coming in 2 cargoes, I think in Q1 next year.

And just to remind everyone, we'll do our full year management guidance for 2026, early next year, potentially in sort of late January or February. So we'll have more detail on the outlook for the 2026 for our business.

And is it correct to think that the Akpo Far East prospect is -- if that's a success that can be handled by the existing field infrastructure without any significant capital upgrades?

Yes, that's right. So it's kind of super interesting. It's only just single-digit kilometers east of Akpo in the facility. It's a large kind of target that could, for a first phase, come on within 18 months, 2 years tied back to the Akpo facility. So it's very reachable. The timing has really been around age and availability over Akpo. That's now with Akpo's natural decline there's time and space, if you like, could come together. And so yes, that will be tied back very, very quickly.

Next question comes from David Round with Stifel.

A couple for me guys. The break from drilling in Q3, are you able to elaborate how that break has helped improve your thinking around future targets? And then also just I guess, more generally, are you noticing any different approaches between the different operators you've got in Nigeria? And then the second one, separately, just on EG as a clarification. Are you looking at farming down those blocks individually or together?

Yes. David, thanks for the question. So look, a good point, you take a step back on actually on Egina and Akpo, which is where the drilling break occurred this year. So again, we said this a lot, but kind of world-class fields kind of textbook petroleum engineering with 4D seismic over them. So that allows us to shoot surveys at regular intervals, of course. And in those fields, in particular, we can see fluid movement, we can see oil, water, gas, and that allows us to kind of really hone in on the infill targets.

So specific to the question, we took a drilling break in Q3. We've had new 4D come in over the deals and the reason then to have that break and go back kind of Q3 next year drilling has been to allow that new data to be incorporated. It looks very positive from us. So I think we'll see the 2 -- well, 2 targets on Egina, and one on Akpo, again, Q3, Q4 next year, and then we'd anticipate running into '27 that there'll be some more follow-on drilling on the back of that data. So yes, it's been useful. I mean there is obviously a short-term impact at these middle-age fields from not drilling, but I think it allows us to come back with a more focused kind of target campaign.

Just to move to the EG question. So the simple answer is we see them as separate processes. Now they have run kind of on a time line in very close parallel almost on top of each other. So look, there are parties that are interested in both. There are parties that are interested in one or the other and again, we touched on it in the presentation, but they're very different in nature. So EG-31 is kind of gas brownfield LNG tie back through existing facilities, et cetera, 18 in the outboard multibillion barrel kind of oil target, so a kind of material kind of catalyst if that comes in. So yes, very different opportunities, and therefore, we run a parallel but separate process, if you like.

Okay. Very clear. Just in terms of the operator's approach in Nigeria, any differences there? Or are they kind of getting on with things in a similar kind of fashion?

Yes. Look, good question. I didn't mean to skip over it. Yes, I think they're both very active, which from an operator perspective is what you look for, right? I mean the fields, as we know, they're heading to midlife, they're in that kind of natural decline. What they need is a bit of care and activity. And I think on both -- from both operators, that's what we're seeing.

So we didn't talk about Agbami so much, but the plan is to come back. Chevron will drill kind of 6 infill production injector wells in 2027. So it's a pretty big campaign given the age of the field and kind of speaks to, a, their activity as an operator, which is very positive; and b, the nature of the resource base.

I think Egina and Akpo, again, slightly different. We're seeing the same infield activity focus from TotalEnergies. There's lots of opportunities there to mature, but there's a wider set of tieback and kind of organic growth opportunities around those FPSOs as well. So we're seeing, obviously, the Preowei which is ongoing. But there are several other discovered resources within the license that we see TotalEnergies is taking quite an active view on at the moment. So yes, look, I think we're comfortable that they're both engaged and active, which again is a nonoperator, really important to see that.

There are no further questions at this -- there are no further questions at this time. I will now hand back over to Shahin Amini to read through your written questions.

Thank you very much, operator. We've got a number of questions submitted over the Q&A facility and a couple of questions who were e-mailed to us earlier today. So I'm actually going to start with an e-mail question from one of our long-standing shareholders in Sweden. And I'm going to put to Aldo, what are your expectations in the common quarters for further reductions in net debt?

Okay. Thank you, Shahin. In relation to debt reduction and the leverage in the balance sheet, I think we have done focus -- we focus a lot throughout 2025. You have seen the amount of reduction we did with the existing RBL as is natural in this kind of instruments, as we progress towards the maturity of the facility we get compressed by the loan life cover ratio, and therefore, we have to continue to make payments or we continue to have a reduction in our borrowing base, and that will continue to happen throughout 2026.

So in terms of what we plan for the next year compared to 2025, I think the main difference is that we have already started the process to refinance our existing facility. And so far, we have been getting strong indications from the banking syndicate. And if we're able to achieve that target, which we expect for the beginning of 2026. We then should be in a position to keep our borrowing base higher for a longer period of time, which will give us additional liquidity for whatever reason. So organic growth, inorganic growth and et cetera. So that's the plan in relation to that as we get into 2026.

Thank you, Aldo, and the same investor, a couple of follow-on questions. I'm actually going to address this myself because these questions are kind of detailed about our 2026 estimates and outlook.

As I mentioned earlier, we will give a more detail -- well, we will give a detailed management guidance next year. And Oliver, I think it's fair to say that right now, the team are very busy with the JV partners in sort of setting the Board program on budgets for next year, correct? So there's still some what we need to get through before we ready to give the share management guidance.

That's right. We'll play that out through the end of the year. And as you said early next year, there will be a clear forward plan on production forward vision on that production.

Okay. Very good. And going back to Aldo. This is a long-standing point of debate base. And that's -- the question is that as you're lowering net debt in 2026, what is your expectations or what is your outlook for one in terms of capital allocation and shareholder returns? Can you sustain the dividend?

Okay. Good question, and we get that question a lot. I think the sense in terms of capital allocation, again, the focus in 2025 was to reduce the RBL as we were not utilizing the whole liquidity we have available under that facility. And then we achieved significant interest expense reduction throughout the year, which I think it's an important way to generate equity value for our shareholders.

Now when we look forward, I think we all -- the way we look through capital allocation and distributions, we look at mainly 4 things. First, we look at the short term or the cash generation coming from the Nigerian agent assets and then how short-term production behaves, that's the first bit. The second bit would be in relation to organic growth through the existing portfolio. As you know, in Nigeria, we fund organic growth with existing cash flow from operations. And outside of Nigeria, we fund organic growth through the carry arrangements which we have put in place with partners, for example, in Namibia with TotalEnergies' true impact.

The third part that we look, we then look at the debt obligations. Again, as I mentioned, we would continue to have a reduction in the borrowing base through 2026. So to address that, we have restarted the refinancing exercise, which will give us additional liquidity to go through that.

And then the fourth part, which is a little bit of our control or a lot of our control is the oil price movements, right? I think we are looking at oil price forecast for 2026, which are very -- and most of them on the bearish side, which we see also reflected on the forward curve. So we're going to take -- we're going to be very, very careful when we look at additional distributions in 2026 or elsewhere as we prepare for a year where we expect to have a lot of cash flow volatility given the oil price.

So that's the mechanism. Those are the -- that's the process that we go through when evaluating dividend distribution. So when we go through all of that, as of this moment, we don't foresee any surprises into 2026. But again, keeping an eye on oil price, which should be the major variance.

Thank you, Aldo. And there's a couple of questions on M&A. As always, we can't go into detail. So -- but perhaps from a more philosophical and high-level point of view, Roger, perhaps you want to -- first, how does Meren see M&A opportunities in the market and 2 specific jurisdictions have been mentioned, but 1 continent, South America and Nigeria in 2 different questions. How do we view opportunities?

Thanks, Shahin. So we are looking at a whole series of opportunities. But as I've said before and as Oliver has said, we're in no rush. We have a balance sheet, which allows us the opportunity to wait and find the right opportunity. I think in the short term, it is likely if we do anything, it is likely to be within West Africa and we are reviewing a series of opportunities there.

But all I can say at the moment is that we are in -- have the luxurious position of being able to wait until we find the exact right opportunity. So no rush. We are reviewing very, very carefully, and it will -- whatever we do will fit with our investment criteria.

Thank you. That's really -- I don't have any other questions that we haven't already answered from the webcast. So I'm going to hand back to the operator to bring this presentation to a conclusion.

This concludes today's call. Thank you very much for joining. You may now disconnect.