Hello, everyone. Thank you for joining us today for Maran's first quarter 2026 results presentation.

My name is Shahin Amini and I'm Head of Investor Relations and Communications at Maran. 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 Maran 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 four, 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 a 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 two quarterly dividends year-to-date to a total of just over $50 million. 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 five and our production performance for the quarter.

In Q1, we delivered working interest production of 28.4 thousand 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 three 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 six.

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 two 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 seven 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 2/3 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 this 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 $36 million, driven mainly by $106 million working capital outflow.

This mainly reflects a higher underlift position and a build-up in trade receivables linked to the gas revenues. Debt service costs, including fees related to the RBL refinancing, also impacted the quarter.

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 $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 interesting 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 0.5 times, well below our target of 1.0 times. The key development in the quarter was the successful completion of our RBL refinancing, which materially enhanced our financial flexibility.

There are three 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 two times oversubscribed, which demonstrates the strength of our asset base and the continued support of our banking group.

Second, the terms. We extended the tenor to six years, including two-year grace period, and reduced our cost of borrowing, with the loan life average margin down by 12.5 basis points.

Third, the flexibility. The revolving structure allows 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, gives 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 Maran 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 six infill well campaign on the Agbami field through 2027 and into 2028, and that will start to deliver incremental production from early 2027.

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, Maran 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 two 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. 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 net debt to EBITDAX ratio of 0.5 times, 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.

With the business streamlined, the balance sheet strong, we have the optionality to pursue inorganic opportunities where they meet our strategic, financial, and operational criteria. To conclude on slide 12, Q1 has seen another quarter of strong performance and it's this consistent delivery that allows Maran 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 Maran 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.

Thank you.

Good afternoon. Can you hear me?

Yes, we can hear you.

Perfect. Thanks for taking my questions.

A few questions for me. First one is on lifting schedule.

You obviously lifted less than you produced in first quarter. What should we expect in terms of lifting compared to production in second quarter and third quarter?

Second question, that 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 1.0 times EBITDA.

How should we think around that? Will there be an extraordinary dividends or are you preparing to ramp up capex significantly?

My last question, that is on Venus development. I understand that Total is still working on that as you discussed, but I just wondered if you could provide some more color on what we know here in terms of first oil, potentially new resource report, etc.

Thanks.

Okay. Hi, Teodor.

Aldo here. I will cover the first two questions and then I'll pass on to Oliver to cover the question about Namibia and Venus.

In terms of liftings, the expectation for the full year 2026 is between 7 to 8 cargoes, with one cargo already being lifted in the first quarter. The reason why I give you an estimate is just that oil prices have an impact on entitlement production, as and therefore that can change the lifting schedule as oil price moves significantly, right?

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 Maran, we are in a pretty strong position to go through the year and the years ahead. The reason why we do that, as we want to protect our portfolio of organic growth opportunities, and as well, keep the company robust to continue with the dividend payments.

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.

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 distribution.

At this point, we're not in a position to comment on that. I'll pass on to Oliver to talk about Namibia.

Thanks, Aldo. I think on Venus, we point to the operator guidance really, which has been very clear in the public domain, which is their anticipated target for an FID of the first phase of Venus is July this year, so that's, of course, pretty imminent.

Then, typical for a kind of project like that, first oil is 3, 4 years, we kind of see that, somewhere 2030 for first oil. Look, I think what's behind that, the project development plan is submitted to the government, the contracting work for this kind of subsea, SURF, all of the critical path items, FPSO, is mature.

Really, it's about closing out key items and pushing hard for that July timeline. That's the marker that we're looking for as partner, if you like.

Thank you. Could you just remind us of expected plateau production for the first phase here?

Again, the easiest thing is to point to the public numbers from the operator, TotalEnergies. 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.

Then through our kind of holding and impact, which sits on the license net net, we're just under 4% of production there, call it circa 6,000. Again, as what we like to remind people, we're fully carried on the capex and the upfront costs there, so that's kind of 6, 6,000 barrels, but it's a very valuable 6,000 barrels that comes effectively risk-free to us.

Okay. Thank you.

That's all for me.

Thank you.

Thank you. Good morning.

Oliver, with respect to the drilling campaign in Nigeria, can you talk a little bit about reserve movement of proved or of reserves between categories that you might anticipate in 2027 and '8?

Hi, Jeff. I think, as we said on the call, we've got two rigs coming.

Again, just to remind people, one is in Agbami field and the other rig will go between Akpo and Egina fields. Look, I think with Agbami, it's a six-well campaign, the first well will actually be the Ikija appraisal well we mentioned on the presentation there.

After that well, late this year, rig moves into the field and those are six infill wells. Then on Akpo and Egina, the current plan is to drill this Akpo Far East exploration target upfront, so that would be the first well, and then through 20 late 2026, 2027, go in and drill a number of infill producers there.

I think 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 and probable in the field, 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.

The key maturation there is to prove up volumes on Ikija, for example, Egina South, right-size 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 in the borrowing base?

I don't think hugely so, because I think the fields are mature, the infrastructure's been there, it's all on stream, 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 at FID they become 2P, they become more relevant in that respect.

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

Look, 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. I think that does for anybody, in a 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 don't know what's coming next. We'll continue to be very outward-looking, let's say, on that front.

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 aboveground. That's a geographic kind of focus.

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. 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?

They've got to be as good as or better than what we've got internally, and again, that's a pretty tough bar, right? We see opportunities to do that, but they're select.

Thank you.

Great. Thanks, guys.

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.

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. 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 collars we just need to be aware of, please.

Thanks, David. Let me take the first one and then I'll hand over to Aldo around the hedging one.

Look, hey, I think as noted, the balance sheet came into the year strong, and clearly, it's 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 falls significantly in the near term, so that will help.

Again, you get into the nuance of what sort of transactions would you do. I think cash transactions today pretty difficult.

We have the capacity to do that, but I think how do you close up kind of buyer-seller gap in this environment is tough. That takes you into kind of more the 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, etc., before you do that?

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. 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. Look, it's a good problem to have, and 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 open up even more opportunity.

Okay.

On the hedges, I realize that we have in our MD&A the hedging position until the end of the quarter, and then I realized that the reference we make is in relation to what we call the post-tax net entitlement, but I think would be easier to say the percentage that would tie with total production, right, which is easier to compare with other companies. If you get our hedging book for the remaining of 2026, the remaining three quarters, in relation to total production, we are hedged a little bit below 40% of the remaining production.

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 liftings volumes, we would be more towards the low 30%, between 30% to 35% is what we have in the next 12 months. In 2027, what we are working, as you can see in the MD&A, is on placing more wide collars, which still provide us with a significant floor protection while keeping a substantial participation in the upside.

That's how we have been treating hedging in the current terms.

Okay. Makes sense.

Thanks, guys.

Thanks, David.

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

No, that's a great question. I think it's in the presentation, but Akpo Far East is actually within the license of the Akpo field.

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 nearest Akpo subsea infrastructure.

I think, as we see it today pre-drill, you would look to have one, two early producers possibly in two years hooked up back to that template for early production. 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 one year, 18 months following the first oil.

It'd really be staged 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.

There are two questions on Equatorial Guinea. First one on the license extensions: did these extensions come up with any additional commitments?

The second question is, if you are looking to farm these down, do you still want to retain operatorship and what is the overall philosophy in terms of farming this down?

On the license extensions, we've got we've got up to two years on on each block. There are, in short, no significant commitments there.

There's the regular kind of license holding costs, but there's no capital, firm capital work program associated with that. I think what's important to take from that is it reflects our 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 a very changing world where there's significantly agreed increased appetite for for West African assets and opportunities, and so it makes sense for us to 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 a good farm farm-down deal there on both blocks.

I think on on the latter question, I think, two different things there. EG-31 is an inboard block, it's shallow water kind of gas development, appraisal opportunity.

I think that's something that we'd be comfortable to operate as Maran. I think in the outboard, EG-18, that's a a different type of opportunity, that's a kind of very traditional deepwater, big exploration target.

I think, look, we'd be comfortable to to drill an exploration well there, but, that's something that a we'd we'd partner with a larger company to develop. I'd look at them in slightly different ways.

I think again, I would I would just reiterate what our aims are here is around capital allocation and discipline. For the big exploration opportunity, just as we've done in in South Africa 3B/4B, it's a matter of 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.

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 a specialist panel's been put in place, do you see tangible operational logistical synergies that can be shared between your South African assets and the Venus development project in Namibia, and considering that both sit in the Orange Basin ecosystem?

Let me, again, preface the answer with what's happening there more broadly. I think, as many people are aware, the Orange Basin, roughly two-thirds of it geologically is in South Africa and then one-third 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, prolific kind of basin emerging.

Not really any wells drilled yet in the South African side, which again is two-thirds. I think that 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.

To the question, it is now moving again, 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. 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.

In terms of moving from green light on the final permit appeals process through to drilling becomes an operational matter of rig availability and timing, but everything's kind of ready to go, let's say, which is good. Then to the actual question in terms of logistic, yeah, absolutely.

I think there's going to be a lot of rigs in Namibia, development drilling on Venus, etc., appraisal on Mopane, all the rest of it, several operators. 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. I think, yeah, 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. Look, huge interest in the block, unsurprisingly given its location in the Orange Basin.

Part of the rationale for partnering again with Total was the fact that 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. A

question for Aldo. 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.

It says, 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. I think now in the first quarter, as well as this cargo that we already mentioned in the second quarter that had the trigger price mechanism, they are based on these legacy instruments that we were using before the prime amalgamation back in March last year, right?

These one that we lifted in April was the last one, we don't have additional hedges using that type of structure. 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 instrument that we have been using. Now with a higher curve, we are able to place good protections for the downside, but while keeping material participation in the upside.

That's the only change. That's how we start doing it in Q1 2027.

You should expect for the reminder of 2026, prices, as you can see in our MD&A, more towards let's say pre-war price estimates. Coming into Q1 2027, you should start seeing the different collars and a better participation in the upside.

Sorry, and there was another question on working capital profiles for the rest of this year and the hedging. Aldo, you've 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.

Again, just reiterate what Aldo has already said on expected cargoes from Q2 till end of the year, we expect 7 to 8 cargoes. If anyone wants more detail, I encourage you to reach out to the IR team at Maran and we can help you if you need to go into further detail.

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

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

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