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 would 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 two 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 0.5 times, 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 of dividends to our shareholders. 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 recover in realized pricing compared to the prior period.

We lifted two 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 two 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-month period.

Full details can be found in the MD&A. Post-quarter end, we lifted one 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 pick-up in cash generation. EBITDAX was $108 million in Q2, taking the first half to a total of $220 million, supported by two 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 expenditures was $15 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. 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. That 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 two liftings and a solid underlying performance. We invested $15 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 two 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 remains 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 0.5 times, comfortably inside our through-the-cycle target of 1.0 times. 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 to 27,000 barrels of oil equivalent a day, and entitlement production narrows to between 28.5 and 32.5 thousand. 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 to $360 million to between 390 and $430 million, and cash flow from operations to 235 to $260 million, raising the mid-point of these ranges by around 30% and 12% respectively.

We've 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 six infill wells across the field, following an appraisal well on the Ikija discovery. This Ikija well has the potential to de-risk further contingent resource, and if successful, will mature the discovery towards development planning as a subsea tie-back 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 three of our producing fields, 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 this 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 two-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. 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.

Good morning, thank you. Can you hear me?

Yes, go ahead.

[unclear]

Good afternoon and thanks for taking my question. Can you hear me?

Yes, we can. Go ahead.

Perfect, thanks. A few questions from me.

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 arrest decline, or should we model some production growth in 2027 versus 2026? That's the first question.

Second one is also related to that. Given that you step up drilling activity, I also assume that capex in 2027 maybe will be slightly higher than 2026.

Can you confirm that? Third and final question for now, that is a lifting schedule.

You mentioned that you had one lifting in July. How does the full H2 lifting schedule look like?

Thanks.

Thanks for the question. It's Oliver here.

I'll take the first two and then I'll hand over to Aldo for the lifting schedule. Look, I think on the activity in Nigeria, I think firstly, very happy to get back to activity across all three fields.

Again, as we said in the call, two rigs coming, intervention vessel ahead of that. I think important to characterize as a range of activity there.

Firstly, we're drilling a near-field exploration well off the side of Akpo, which is kind of super exciting catalyst, very low cost and could be quite a significant resource. There is a potential significant value-add from that activity.

Similar, adjacent to Agbami, we'll drill an Ikija appraisal well, which again is testing future resource, if you like, tie-back potential to existing infrastructure. Those are important in the longer-term, mid-term sense of significant value creation, value-adds to the portfolio.

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 that the vessel has done its activity. Then in the wells, it takes a couple of months to hook them up, of course.

What that will result then is longer-term value creation, growth in the resource base, which is important, and then in the short term, 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. Then depending on results, yeah, 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.

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. I'll cover the question about the lifting schedule.

I think just before I answer, reminding that lifting schedule is conditional on two things, right? One is 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.

It is a little bit fluid. With that disclaimer, we expect the second half, as you correctly pointed out, we already lifted one cargo in July, successfully, and we have expected for the rest of the semester, let's say, another three to four cargoes to be lifted throughout the second half of 2026 on top of the July cargo.

We had three cargoes in the first half, and it will be slightly more concentrated on the second half with something between four to five cargoes for the second half, yeah.

Okay. Could I just follow up on that?

Probably that implies that lifting will be more or less equal to production in the second half, we shouldn't expect any material over- or underlift?

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

Thanks. On the 2027 capex, are you in position to say anything about that?

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 that's really not change of activity or cost, it's really a deferral of some of that activity into '27.

Look, at this stage, I think a broad view on it, but it would be something similar to where we are this year, if not lower.

That's clear. Thank you.

Thank you.

Thank you, good morning. Oliver, 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?

Hi Jeff. Thanks for the question.

I think if you look at it, again, I kind of two buckets, if you like. Firstly, the series of activity around the field, the Akpo Far East is effectively exploration near-field, and then Ikija next to Agbami is appraisal, also.

Those are either adding to a contingent resource to kind of 2C in the case of Akpo Far East, and in the case of Ikija, that's again firming up a 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 and reserves? 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.

That would be a very short-cycle project. Again, you'd see it in the call here, but it could be kind of 12, 18 months to first oil from that in the success case.

Although the well would actually, it's an exploration well and would add to contingent resource, we would expect that very, very rapidly to move actually to reserves and 2P in the success case because of that cycle time. That whole bucket is a bit of 2C and then some success case incremental 2P in the next kind of 12 months on Akpo.

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.

It's really getting the most out of that 2P and moving some of it to 1P.

Thank you. 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?

I think what you're referring to, as we're going to have from the last quarter of this year, let's say, two rigs drilling in the different areas, right, one with Chevron and one with Total. 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're very concentrated on the last quarter of this year as well, right? In terms of the first half of the year, we spent $24 million only, and we expect the bulk of the expenditure to be in the last quarter of 2026.

I think let's look at 2026 second quarter and expect that the spend will be similar on a quarterly basis throughout 2027 as we keep drilling the wells on both blocks. 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 liftings, right?

That's how you should expect it to happen.

Of course, the other big factor is the oil price. Today's oil price, while it's...

It's why I said keeping everything else the same.

It would be

premature to

forward, I'm sure, we're nearer to the end of the year, so, and we'll obviously do our full-year 2027 management guidance in due course and we'll update you, Jeff.

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

Oliver, can you hear us?

I can, if I'm still live. Hello?

Hello, Ashley. Yes, can you hear us?

Yes, we can hear you. Apologies, we had a technical malfunction at our end.

If Jeff can hear us, can he please repeat his last question?

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

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

Yes, what do you expect an impact in

2027 production costs

from the 2027 drilling campaign?

Jeff, that sound unlucky perhaps at our end. 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?

It shouldn't impact production costs. Those costs will mostly be reflected in our capex requirement in 2027.

Production costs will be a function of what we're going to get from the operator's budget for next year. If you look at the last quarters, you can see that we have been spending consistently a little bit below $40 million per quarter, we do believe that remains our view for the short term, Jeff, and the drilling expenditures will be reflected in capex.

Thank you.

Apologies for that technical mishap at our end.

Thank you. Aldo, 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. 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 as a price risk. We do that consistently, and we have an internal policy which we follow, and we have explained that in our MD&A.

Roughly, we hedge between 30% to 50% of our gross production on a 12 months rolling basis. 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 when we step up the drilling operations in the next year. We will continue with following our hedging policy.

The only change is worth highlighting is that we have moved from doing the trigger price mechanism from the past, which was something, it 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 tensions 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.

Thank you for that, Aldo. Turning to the Preowei developments, Oliver, 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?

I think it's important to take a step back around the Nigeria production assets and the portfolio. We talked on this call, we're excited to drill the Akpo Far East well coming up, we've got an appraisal well on Ikija.

Again, testing and maturing significant resources there next to infrastructure, super kind of high-value stuff, short-cycle developments. More widely, of course, we have Preowei, which is, it's a tie-back project to the Egina FPSO.

As a reminder, Preowei in itself is a significant field. It's kind of expected to deliver peak production, gross, 65,000 barrels a day.

That's a big opportunity for us as a tie-back, that's maturing well. There are others.

There is Egina South discovery, which again, the name gives it away, but it's a tie-back potential development to the Egina field. It's actually across our block and it goes into a neighboring license area, Total are in the license area adjacent to our side, if you like, and they are planning an appraisal well on that forthright.

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 tie-back as well. Those are two big opportunities.

Then as we look more widely around the fields, 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. Actually, there's a good portfolio there of follow-on opportunities in terms of low-risk, near-field exploration, discovered resource, etc.

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 decades, significant and sustained cash flow, very, very secure cash flow again in a volatile world because of those low lifting costs.

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 and capacity as the core fields have matured. Of course, we're now quite aggressively looking with the partnership on, well, what are the prospects and volumes could be tied back into those fields.

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.

I think we'll see a series of both near-field exploration, contingent resource maturing to FID, tie-back projects through the next couple of years, and there'll be quite a lot of news flow on that, really.

Thank you, Oliver. 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 our assets in Nigeria?

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 always the above-ground.

You say, well, okay, how does that work in terms of the economics, the commercial, the stability, the wider landscape, if you like. Nigeria is in a very, very good place.

I think everyone could 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.

That industry landscape is fantastic from an investor perspective. It's the best it's been for a long time, and some really, really hard work has gone in there from the government side.

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.

Of course, we're in deepwater, and, like any deepwater project, you need terms that 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. What you see in Nigeria is a series of, I guess, executive orders there that are translated 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.

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. 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.

Thank you, Oliver. Couple of questions on shareholder returns policy, let's put this to Aldo.

Combining these two questions, with perhaps a more constructive oil price outlook, what is the company's thinking around capital allocation and shareholder returns?

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.

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 was just mentioning, right? Those are high returns, short-term payback, utilizing our existing partnership in a country that we understand well and is very supportive.

In case of Nigeria. Also, that's remain our priority number two after the balance sheet, so that wouldn't change.

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.

That remains, there is no change to the capital allocation policy.

Thank you, Aldo. There are a number of questions on Equatorial Guinea, again I'll combine them because they're common themes.

The questions are: what are our timing expectations? 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. There's a couple of questions on strategy and inorganic growth, Oliver.

Meren's 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?

I think it's a great question, and 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. M&A and inorganic growth, it's in there, but it's in there in a very disciplined way, right, where 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.

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. West Africa remains critical in that respect, and I think that will be the case for a 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.

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 Margin, Atlantic Basin, Atlantic Margins, because again, there are a lot of the thematics there in terms of the technical world, in terms of the fields, in terms of the developments, in terms of the kind of above-ground opportunities and risks.

That's a natural extension for us. Again, it's a wide lens, but we look with discipline and we look carefully.

When we evaluate these things, geography is an important component, but it's only one of those components in the mix of a decision.

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