Hello, everyone. Thank you for joining us today for Maran's fourth-quarter 2025 results presentation.

I'm Mussanah Chowdhury, part of the Investor Relations team here at Maran, 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 on SEDAR+ and on our website. With that, I'll now hand you over to Oliver.

Oliver, please go ahead.

Thanks, Mussanah, and thank you, everyone, for joining us today. This is my first results presentation as Maran'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 am pleased to report on a year of strong delivery.

To begin with, last March, we closed the 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 simplified 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 $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 Maran, 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 30.8 thousand barrels of oil equivalent per day and 35.1 thousand boe 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 boe 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 expectation 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 a 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 on 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, Maran 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. Maran has applied a variety of different hedging instruments to protect the downside while also maintaining partial exposure to potential upside.

These 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 unit. I must emphasize that this impairment is non-cash 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 forecasts 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 infill 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. We have 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 constructed basis as if the Prime amalgamation had closed on 1st 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 $420 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, strengthened 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 amount drawn under the RBL stood at $330 million, with a net debt position of $155 million and net debt to EBITDAX of 0.4 times, significantly below our target of 1 time.

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-Prime amalgamation, we canceled an undrawn $65 million Maran corporate facility to eliminate standby fees.

As a post-fourth-quarter update, we drew 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. We have very good flexibility under the RBL revolver facility at competitive borrowing costs.

We are currently in the process of refinancing the RBL debt 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 account for a lower full-year Brent oil price at $63 per barrel, compared to the actual Brent average of $69 per barrel for 2025.

Moving on to the next slide. Before handing back to Oliver to take you through our organic growth opportunities, I will briefly highlight the positive developments in Nigeria.

The 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. 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 rating 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 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 prospect 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 Maran.

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 Ikija, all located within 20 to 30 kilometers of existing Maran 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 Maran.

At Agbami, drilling also recommences in late 2026 with a campaign including appraisal of the adjacent Ikija discovery and six 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 Maran, 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 Maran.

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.

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 Appeal's judgment for Blocks 5, 6, and 7.

From a project perspective, the identified lead prospect, Naila, 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 Maran in South Africa is limited, with the transaction completed with TotalEnergies and QatarEnergy including a capped exploration carry.

Whilst the regulatory issues elsewhere in South Africa, of course, 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 Maran. Now turning to Equatorial Guinea on slide 14, we hold two operated licenses that offer another set of organic growth options within the portfolio.

Starting with EG-31, this is a shallow-water gas position close to existing infrastructure and situated around 30 kilometers from the Punta Europa LNG facility. Through 2025, our evaluation has 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 project that utilizes capacity in the adjacent LNG facility.

Beyond Gardenia, several nearby gas prospects, Massif 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, right-sized LNG opportunity with low-capex exposure through utilization of existing gas and LNG infrastructure.

Moving to EG-18, 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 for Maran in 2025, we have remained focused and 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 1 times 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 meet 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.

Thank you. Good morning.

Aldo, can you talk a little bit about the timing of the liftings that you anticipate in 2026?

Hi. Good morning.

Yes. For we have to look at the liftings as per FPSO, right?

That it's a discretionary and that creates the timing difference in relation to the liftings. For 2026, we're expecting around eight cargoes spread throughout the year.

I think it's safely to assume they are evenly spread throughout the year just for simplification purpose.

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 EG-18?

Hi, Jeff. 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're very different things, of course.

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.

To the specifics, yeah, I think, look, it depends exactly when we might close a transaction, and who it's with. I think 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. That's kind of appraisal development, straightaway, and it's shallow water, so, technically not challenging, quick to do.

And 18 is deepwater, but again, we have one very, very high-graded prospect. I think people that 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. There's a reasonable timeline 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?

Yeah. I think in the detail of it, you've got the 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 and the contract, it defines kind of appraisal periods, commercial evaluation periods before you would declare commerciality, and that brings time to do that. That makes sense.

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.

Lastly for now, with respect to inorganic growth, Oliver, when you think about Maran's current opportunity set over the next couple of years, which would require capital dollars, what type of asset fits best in the portfolio, do you think?

Good question. I think if I start with what we have today, and I think hopefully you saw that in the presentation, 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, 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. I think we see a lot more opportunity around that portfolio for tiebacks to the three FPSOs, EG as we've just talked about with mature that very well and that's come a long way and looks exciting.

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.

There's a better landscape there beyond the technical for maturing things in Nigeria. 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. 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, 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 in 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.

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.

Thank you.

Thanks, Jeff.

Can you hear me?

Hey, David. Got you now.

Yeah.

Perfect. Sorry about that.

Few questions for me, please. The first one is on the gas sales agreement.

I read something about that this morning, just wondering if you can get us give us a sense of how meaningful that that may or may not be. The second question for me, please, is you've mentioned Akpo Far East and Ikija as specific targets.

Just wondering how quickly those could be tied back in a success case. I suppose if if that is going to take a few years, how many infill wells should we be assuming each year to to support production in the meantime?

If I actually, I'll I'll sneak just a follow-on to to that. You've got a '26 capex budget of $100 to $140 million, I think.

Are you able to just break that down for us, please, just in terms of, how many wells are are assumed in that? Is it all just long-lead items, please?

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

Yes. Okay.

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, there will be a few impacts that you're going to see through cash flow and P&L in the coming period.

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.

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. You should expect a larger impact in 2026 given to the resolution of the contract.

Let's say on an ongoing basis, we're talking maybe something about let's say, doubling the gas revenues that we have compared with the last 2 to 3 years. It should be meaningful, especially in the first year.

Okay.

I think on the second one, David, it's a good question on Nigeria. Maybe I'll just take a step back.

We're getting two rigs back end of this year, which we'll come onto on timing and your capex question. Actually, what has happened is we've had the longest drilling break across the three fields since kind of first oil.

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.

We turned to how do you firstly arrest that decline and then how do you grow from the base, if you like? I think in terms of arresting the decline, it's, as you said, the infill drilling.

When we look at that next program, if I start with Agbami, a rig will come somewhere at the end of this year, there's operational uncertainty on exactly what time the rig arrives, but nevertheless, it's firm, it's coming. There are six infill wells planned on Agbami through '27 across the year.

When you look at that, that's quite for a field of that age, it's quite positive, it's quite sustained. There's a relatively big infill drilling campaign there which will arrest natural decline.

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.

We're kind of guiding Q4, plus or minus operational kind of issues on where the rig's coming from. Again, interestingly, there's two two buckets of opportunity there.

One is the kind of Akpo Far East, 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, three wells there. That gives us in the kind of near term, if you like, end of this year, a kind of barrels that are coming on stream.

It'll be early '27, but barrels come back on stream, arrest the 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, we'd hope to get first oil from that in the success case in less than 2 years.

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-sized 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, kind of end of the decade.

Ikija, which we did mention, is a potential tieback to Agbami, and again, similar, the well that we will drill probably end of this year, early next year, that's an appraisal well, 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. I think I'd characterize it good campaign of infill drills 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.

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? I think there, look, we see two or three options at least in Egina and Akpo, potentially '28, '29.

In Agbami, a six-well campaign is pretty big anyway, but we're working there on is there another similar campaign a year or so later? 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.

That's really helpful, Oliver. Thank you.

Sorry, just the final one, just around capex for this year. Is that mostly long-lead items?

There's some long leads in there. I think the range that you see is really the timing of rigs arriving, it's a classic year-end issue.

We're planning on Q4, but those rigs could arrive just contractually, operationally, possibly Q3, and they could equally arrive late Q4. It gives us a bit of range on that number.

It's primarily, we're assuming the wells are drilling Q4, 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 2025 mainly.

Brilliant. Really helpful.

Thank you.

Thanks, David.

Hi there. Thanks, gents.

One on exploration, one on appraisal, one on scale, I suppose. First on exploration, you've got Akpo Far East Deep, you got Egina South Deep, you got Ikija Deep.

Is this in reference to deeper reservoirs or down-flank faults? Have you intercepted them?

What's the reservoir like? What's the kind of risk, both around volumes and deliverability in regards these prospects?

Secondly, appraisal, you pointed out your contingent resources on Preowei, on Ikija, on Egina 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?

Just lastly, in scale, it's quite kind of observable to any E&P analyst and the 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.

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. Thanks.

Yeah. No,

thanks for the questions. I think, look, we start with the first one, the exploration point.

I'd kind of split that up. Akpo Far East is exploration, so that is prospective resource, let's say, it's a 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 fiscal ring fence, if you like, the economics are extremely compelling.

It wouldn't take the huge volume there to reach commerciality, so that one is about geological chance of success. I think the others, just to segue that, Ikija, Egina South are appraisal, those are contingent resource for us today, they're 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.

Then Preowei is slightly different again because that is actually reserves for us. That's 2P reserves.

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 the final decision.

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 right-sizing, improving commercial volumes. I think the second question, the wider point on Gardenia and some of the other resources, I think there's a timing point to a lot of this stuff.

In two respects, one one, the projects themselves, and actually the second one, the market, which I'm sure come back to you because I think it also addresses your third point. 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 they're varying ages. They are in natural decline phase, which you see in the base production.

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? That's now, because you don't just want to be able to bring a small amount of resource in, of course, you want, for the economic development, you want to be able to maximum development of something like a Preowei.

I think the timing point is partly on the infrastructure then: 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. 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.

I think that timing is now, again, we'll make decisions on all of those through the coming period in terms of whether they're the right thing for capital allocation. Certainly, the project aspect has unlocked.

I think more broadly again, the second point on that, where is the industry? 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.

Lots of good opportunities, but what we're not going to do is overleverage the balance sheet, expose ourselves to capex overruns, etc. 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.

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. Yeah.

No. Just to dig down on Akpo Far East, what is the geological risk?

Sorry.

1 in 3,

1

in 4 geological. Oh, sorry.

Specifics. It's trap, really.

The reservoir is same as the Akpo field, we understand it well. It's a phenomenal, in the detail, kind of Darcy-type permeability reservoir, super good fluids.

The thing on Akpo Far East is the trap. Is there an updip trap that works?

Then I think there's a secondary more commercial risk on fluid. That's secondary in two senses: one, that we have a good handle on the seismic, we think we understand that fluid, and it's oily, and we can characterize that.

Actually, the second part of that, Akpo, of course, is very gassy field, and we export that gas. As Aldo just talked about earlier, we've got improved pricing on that gas as well.

I'd say that's a secondary risk, but the geological, fundamental geological risk is trap, yeah.

Oh, no. That's great on 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, cost overruns. Obviously, there's that argument that if you were twice as large as you are now,

you'd

have to be a lot less risk averse. Yeah.

No, I think it's a great question. I think, in terms of the strategic position of the company, again, I'll take a step back, 2.5 years ago, we were Africa Oil, as it was, completely different company, much, much smaller in scale.

You roll forward through that period, we've doubled reserves, production, etc., 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, 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, etc., absolutely. We see that.

I think when you come to execute around that, I think again, our message is discipline. Yes, the ultimate prize does all the things that you describe, again, agree with that.

For us, it's not so much that fundamental principle. It's the pathway to get there.

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 timeline. We go back into that mode.

I think, great, but what we're saying is, look, we protect that. That's always the number one job is to protect that business, make sure it's robust, but equally go and look at inorganic transactions that are accretive to that.

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 are accretive, and those are the things that we are kind of narrowing our focus to.

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.

Thanks, Oliver.

Thanks.

Thank you, operator, and thank you once again, everyone, for joining today and submitting your questions. I will I'll go straight into the questions.

I think one for you, Oliver, is given the transformative potential of the Venus discovery, we currently have 3.8% effective interest through us 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?

Is there potentially a pathway or a world where we increase that exposure?

Yeah. Look, I think it's an obvious question on Namibia and Impact, and again, I'll, for the third time on this call, take a step back.

If you go to where we were a few years ago with this, Impact had done a fantastic job over a decade of driving Venus as a target, that play, attracted TotalEnergies in, got the well drilled, made a great discovery. As co-owners of Impact, we were faced with a 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 or is a growth opportunity, adding barrels in 2029, 2030. I think that then takes you to a place that says, well, it looks great, we'd like to have more.

I think, with respect, we have another large shareholder in Impact, there's really the two of us own kind of 97%, 98% of that company now, and so we both see that. 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.

Yes is the short answer, but the execution path on those things is a bit trickier.

Thank you. 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 the in Agbami was not what we tried to explain throughout the materials that was not just related to one single item, right?

Was a combination of low oil price and increasing costs, mainly related to the life extension of the FPSO. In terms of oil prices, I think that's obvious, right, throughout 2025 in relation to the decline.

Then more specifically in relation to the Agbami FPSO life extension, Agbami will continue to produce beyond 2020 2044, which is currently our license, the next license renewal period. There is a significant amount of reserves already as 2P to be recovered from the field.

However, what the life extension allows to do not only to recover these additional reserves in a safe and reliable way, but at the same time allows to continue to invest or to develop or to plan for bringing contingent resources as 2P, right? And 2P the 2P numbers are the ones we use for the impairment calculation, the recoverable value, but the 2C numbers, the additional infill wells that Oliver mentioned beyond the container '27, '28, Ikija, which is a tie-in to the Agbami FPSO, as well as other nearby opportunities outside our blocks, those 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. I think it's just a reflection of that, and we know when we get to mature mid-life fields that we have to go through this exercise.

That's the detail behind the impairment on Agbami.

Thanks, Aldo. Just two more, I suppose, for you is, can you give us some thoughts on the percentage of total hedging for 2026?

I think the second from this investor was, can you just give us some color on our plans for the RBL going forward?

Yes. 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.

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? We first calculate the post-tax net entitlement, and out of that, we hedge between 70% to 100% on a rolling 12-month basis.

Now, we make a combination of either physical forward sales or swaps where we're locking a price that's close to the forward curve at the moment that we enter into the hedge, but we also have a mix of collar and put structures where we keep some participation on the upside as well for a certain percentage of this hedges. 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 2.3 million are on the first half of 2026, which those are primarily hedged through the physical forward sales, through the physical offtake agreement, with an average floor price of around $62 per barrel. In the second half of the year, we have 1.3 million barrels hedged using a mix of swaps and collar structures.

We provide good downside protection, but we also retain some exposure to the upside. That's in relation to the hedging part.

For the RBL, as we saw through the presentation, our numbers, it was very important for us in 2025 to pay down substantial amount of the RBL facility, right? 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 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.

We are now getting to that period where to keep a substantial headroom in the RBL facility, not necessarily 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. With that, we increase the RBL capability, but at the same time, we'll continue to be very disciplined of how much we draw from the facility to reduce financing costs.

Thanks, Aldo. Oliver, I'll put this one to you, and it's something you briefly touched on a little earlier.

How much risks do you see when it comes to securing the Nigeria drill rigs this year? If you could just give us some more color on that.

Yeah. No, I think we're not concerned about that.

I think we're very advanced, both joint ventures, in the rig contracting process, I think we're very confident those rigs will come this year, that we'll get back to drilling. 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.

Again, combination of infill drilling, short-term barrels, and getting back to testing some contingent resource and long-term growth and value. 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.

I think that's quite a positive view to the year overall.

Thanks, Oliver. Just keeping on Nigeria, there's a question: Our reserves have dropped from 2024 to 2025.

Of course, there's been a portion of production in that as well, but maybe you can give some color on that and how we're arresting that decline.

Yeah. Again, I think if you look at the shift in 2P, that is dominantly the produced resource.

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. You see that in the sense that you produced 2P reserves faster than you're replacing it in that context.

I think, again, two key points are, you look at our contingent resource, that has grown significantly through '25. Again, in terms of options for future value and growth of the business, that's good.

Secondly, again to the prior question, we're very confident that we're getting back to drilling here, not just with one rig, but with two, 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.

Thanks. Just two more before we close off.

When we speak about capital allocation, balance sheet strength and organic opportunities are the first few that we speak about. Just what should everyone read from this?

Then shareholder returns, of course, and M&A coming third, or inorganic opportunities, I should say.

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

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? 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?

There are a number of choices to do that, and we're always seeking to have those choices. 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. Thanks.

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 in a farm-in to a partner?

Definitely not going to give anything away, if I put my commercial hat on. Look, I think we're 100% in those licenses.

Our partner is GEPetrol, state national oil company, and so they have 20%, but they're carried in the early stages here, it's 100% funding. Look, 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 projects at all. It's a point of saying, again, it's 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. 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. Look, we wouldn't do it 100%, but equally, we want to hold a material position in the project, recognizing the potential value it can bring to us.

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.

Perfect. Thanks, Oliver.

That's all the questions we have for today. Operator, I hand back to you to bring us to a close.