Karoon Energy Ltd

Thank you very much, Darcy. And good morning, everyone. Thank you for joining our 2025 Half-Year Results webcast. My name is Julian Fowles, the CEO at Karun, and I have with me this morning Ray Church, our CFO, and Anne Diamond, our head of IR. Earlier this morning, we released our 2025 Half-Year Results to the market, and we're now going to talk through those. Noting the disclaimers on slide two, I'll move to slide four, which provides an overview of the first half of 2025. Karun's main areas of focus during this period have been to ensure safe and reliable operations at our assets, to complete the Bona FPSO transaction, and to progress our organic growth projects at Neon and Houdat, while maintaining strong capital discipline to allow us to continue to provide returns to shareholders. As a result of our efforts over the past year, our safety performance is gradually improving, and the Bowen at FPSO is now operating at significantly higher levels of uptime than it did in 2024, providing an uplift to our production relative to the first half of 24, although I would note the partial failure in August of the electrical submersible pump at SPS 92, which I shall return to later. At Houdat, the assets are performing in line with expectations. Underlying impact for the half was US$45 million, 61% lower than the prior corresponding period, largely due to weaker global oil prices and lower sales volumes as a cargo of Bona oil was loading at the end of June. We ended the half with net debt of US$238 million and our liquidity remained strong at US$452 million. During the half, we acquired the Bauna FPSO. This was a strategic transaction. It is expected to lower Bauna's cost base over time and extend its economic life out to 2039, leading to a significant increase in our remaining Bauna project reserves base to 52.7 million barrels. And this was published in parallel with our half-year report this morning. We are working towards taking full operatorship of the FPSO by the end of the first half of 2026. During the half, we completed key operational activities, including the SPS 88 well intervention, a two-month Flotel-supported maintenance campaign, and a three-week planned shutdown. In addition, we made the final major contingent payment of $88 million to Petrobras, although two further payments do remain. The first half saw us return $53 million to shareholders through dividends and the on-market buyback. Importantly, we achieved this while ending the half with leverage at just 0.6 times. Looking ahead, with net debt expected to decrease through the second half of 2025, we are continuing the previously announced buyback and the Board has determined an unfranked dividend of 2.4 Australian cents per share. This represents a 25% payout of 1H25 underlying NPAT and complements the US$75 million on-market buyback announced earlier this year. During the half, we advanced several organic growth opportunities. In the U.S. Gulf, the Houdat E6 sidetrack is scheduled to be drilled later this quarter and expected online in Q4. Meanwhile, Houdat East has entered the defined phase and remains on track for a final investment decision in late 25 or early 26. In Brazil, we entered a three-stage phase three, including feed, for Neon and have commenced the farm down process. A potential final investment decision is targeted for the second half of 2026. The next milestone for NEON is in 1Q26 when we will decide whether it will progress to the second of the three sub-stages defined for this phase. And I'll go through these growth opportunities in a bit more detail shortly. Slide 5 summarises our safety and environmental performance during the first half of 2025. As the graphs show, our performance has improved despite higher levels of activity at Bauna. There were 710,000 workers recorded in the first half of 2025, 47% higher than at the same time last year, as we completed an extended maintenance campaign with up to 200 additional workers accommodated on a flotel beside the FPSO. There were no LTIs and a single restricted work case. Having said that, we reported four high potential incidents and we are focused on ensuring the safety of our staff and contractors as we transition to full operatorship of the FPSO. We recently completed a 100-day safety improvement plan on the FPSO to reinforce our safety culture. On the environmental side, no spills were reported in the first half, and our Scopes 1 and 2 emissions intensity continues to fall, reflecting higher production spread over a largely fixed operational base. I'll come back to operational performance and the status of the growth opportunities shortly, but now I'll hand over to Ray to address our financial results.

Thanks, Julian. Good morning, everyone. I'll go to slide seven and cover a few highlights of the 2025 first half results. And after that, I'll slip through earnings, cash flow and balance sheet before finishing with our revised 2025 guidance. Production in the first half of 2025 was about 200,000 barrels of oil equivalent higher than first half of 2024, which is due to a stronger performance at the Bona project. However, as our balloon lifting was in progress at 30 June, sales volumes did not include that cargo, and accompanied by lower oil prices, we saw reduced revenue of $308 million down from $409 million in the first half of 2024. This flowed through to lower earnings with EBITDAX down proportionally, or $66.2 million on first half 2024. This EVITDAX result reflects a combination of Karoon's operating leverage to oil price and improved FPSO efficiency in this period. We saw EVITDAX margin at Houdat hold steady, while Bauna project margin improved despite decline in sales volumes. Moving to the balance sheet at the bottom of the slide, this half called on our combined strong EBITDAX margin and balance sheet for the strategic acquisition of the Bowina FPSO. After also funding the Bowina project flotel costs, SPS88 well intervention and other CAPEX, contingent consideration as well as taxes and debt service, The business then funded capital returns and continued buyback to close the half with net debt of $237.9 million. Moving to slide eight and underlying earnings, we offloaded seven Boehner project cargoes in first half 2025, compared with eight cargoes in first half 2024. So that $53 million of revenue reduction related to volume and $48 million related to lower average realised price. The Bowen cargo loading at 30 June deferred $34 million of revenue into the second half of 2025 and is reflected in inventory movements. Transportation costs fell slightly to $10.2 million in line with sales volumes and production costs increased by $3 million to $71.8 million. While FPSO lease charges ceased on 30 April 2025 when we acquired the FPSO, Savings were temporarily offset by transitional ops and maintenance service costs with Altira and Ocean for their continuing support until Karoon assumes full operatorship in mid-2026. The remaining increase in production costs was driven by $1 million of higher O&M service costs through April as FBSO efficiency incentives applied, and $2 million increase in logistics spend as contracts set in 2020 roll off and current rates take effect. Royalties and other government take are down against first half 2024 due to lower commodity prices. I'd note that royalties also apply to produced volumes at Bowen and Project rather than sold volumes. Corporate and other costs were stable at around $20 million. Meanwhile, exploration costs rose to 4.7 million as Karun advanced studies on new deep water blocks in Brazil. Depreciation increased in line with higher production and higher net debt translated to higher finance costs. Underlying income tax expense in first half 2025 was lower than in first half 2024, reflecting lower underlying pre-tax profit. However, I'd like to point out that while the reported underlying tax expense rate increased from 29% to 42%, This is due to the weakening USD against the BRL across the period, and accounting rules require recognition of this foreign exchange impact within income tax expense. Karun minimises this cash tax impact by converting USD funds to BRL each month for our estimated year-end tax obligation, which is then paid at close of the year in BRL. This minimises the realised FX exposure despite the variability in this reported expense, and the normalised cash tax rate is approximately 32%. The overall result was an underlying NPAT of $45 million, and a reconciliation between underlying and statutory NPAT and EBITDA is on slide 24. I'd like to mention that the non-cash accounting adjustments related to closure of the capitalised FPSO lease and a reduction in fair value of contingent consideration based on current oil price have also been reported and removed from underlying results on slide 24. Slide 9 provides a reconciliation from statutory unit operating costs to pre-AASB 16 unit OPEX, which are mentioned in the rest of this material. Unit cost of $13.10 per BOE is a blend of $14.95 at Bowina Project and $8.84 at HUDAT, and increased in total by $1 per BOE from first half 2024. This is due to the $3 million increase in production costs on reduced sales volumes. Slide 10 covers funds generated and applied and movements in our net debt and leverage position. Operating cash flow was $62 million, which is after $21 million for the Flotel cost. We also funded various capex and contingent payments that I mentioned on slide 7. As a reminder, these continued payments to Petrobras will fall sharply in 26 and 27 with the last of the larger payments already made in January, 2025. In addition, we returned $53 million to shareholders via dividends and buyback. While net debt has increased in the period, leverage remains well below our maximum leverage range of 1 to 1.5 times. underlying EBITDAX, and looking ahead with lower capital demands, we expect net debt to fall in the second half of 2025. That positions us well to fund upcoming FID decisions over the next 12 to 18 months, while also continuing to return capital to shareholders under our policy, all strictly according to our capital allocation framework on slide 11. Our capital allocation framework remains unchanged since last presentation. So moving on to guidance in slide 12, we have upgraded our production outlook for Biona, reflecting strong first half performance and also recognising the electrical fault at the SPS 92 well. Meanwhile, HUDAP production range has been narrowed as the asset continues to perform in line with expectations. With much of our cost base fixed, the revised higher production translates to lower unit production cost, and we have reduced that cost by 10% at the midpoint of guidance, which is now $12 to $15 per BOE. All other guidance items remain unchanged as we anticipate RIG intervention for SPS 92 to be completed in 2026. I'd like to finally note that there are several costs that will be incurred in 2025, but are excluded from underlying earnings and therefore not reflected in guidance. This includes FPSO transition costs of up to $5 to $7 million, which Julian will speak in more detail a little later, and $3 to $5 million in corporate relocation costs. Thank you, everyone. I'll now hand back to Julian to talk about operations.

Yeah, thank you, Ray. Turning to slide 14, talking about operating performance of Bowna. The benefits from the work completed on the Bowna project in the last 12 months to address the FPSO maintenance backlog and the SPS88 well intervention have started to come through. Bauna production in the first half of 25 was 3.9 million barrels of oil, ahead of expectations as SPS 88 resumed production earlier than expected, and FPSO efficiency for the first half was 94.5%, against a forecast of 88 to 92%. This uptime is particularly encouraging as it lies towards the upper end of our medium-term target of 90 to 95%. Bona project production has remained strong during July and much of August, and we have increased our 2025 production guidance for Bona to 7.3 to 7.8 million barrels of oil. However, as announced on Monday, we have seen a partial failure of the ESP at SPS 92, one of the project's key producers. And as a result, current rates of production from this well are reduced to around 2,500 to 3,000 barrels of oil per day. We believe we should be able to potentially double this rate as the flow rates are expected to stabilise over the next few weeks and we optimise the pump itself. In order to return the well to full production, however, we shall require a heavy workover using a drilling rig. We have a replacement ESP in stock and are in the process of investigating rig options in the market. The regulatory approval period is expected to take a minimum of six months, and we do not expect to return SPS 92 to full production until the second quarter of 2026 at the earliest. And just to clarify, that full production rate is expected to be around 8,500 barrels per day. Since purchasing the FPSO on the 30th of April, we've been going through the process of planning and integrating the operations into Karoon's business. After a successful outcome from the 25 Flotel campaign, we are now planning a second Flotel supported maintenance campaign of up to four months in the first half of 2026, alongside the planned 2026 two to three week annual maintenance shutdown. Now moving to slide 15, I'll provide an update on the progress of Karun taking ownership of the FPSO. Since completing the acquisition in April, we have reviewed several FPSO operating models. After careful consideration, we concluded the optimal approach is for Karun to directly control and operate the vessel with support from service providers for routine operations, maintenance, and for major works as required. This model will take a little longer to implement than our prior assumptions, and we are working towards taking full operatorship by the end of the first half of 26. To ensure continuity of operations, we have signed a transition services agreement with Altera and Océane, which will support a safe and efficient handover during this period. While the timeline has been extended, the economics of the acquisition remain compelling. Now, turning to slide 16, I'll step through those changes to the economics for the acquisition. Most of the assumptions remain unchanged. We remain confident on achieving annual savings of $30 to $40 million once we assume operatorship and embed a number of cost efficiency initiatives. However, with the transition taking longer, we do expect $5 to $7 million in additional transition expenses through the balance of 2025. Looking further out, we now expect to invest $55 to $60 million of capex in 2026, and then a further $80 to $90 million in the early 2030s to extend the life of the FPSO out until the end of the license in the late 2030s. We can confirm our expected returns from the acquisition remain well above our mid-teens post-tax hurdle rate. Now moving to slide 17. One of the drivers in the value of the FPSO acquisition was converting owner contingent resources into reserves. And this slide provides a breakdown of Karun's success in replacing reserves since acquiring the asset in November 2020. Bauna reservoirs have continued to outperform expectations, and following a comprehensive review, we have confirmed that, based on the new cost structure and implementation of life extension plans, there is an additional 17.6 million barrels of tupi reserves at the Bauna project, This is a 45% increase on our 31 December 2024 figure and results in 2p reserves at 30 June 2025 of 52.7 million barrels after accounting for production. The results are well ahead of our business case at the time of the FPSO acquisition. To summarise, the acquisition of the FPSO is enabling a structural change in our operating cost structure, leading to a longer economic production life for the project, deferral of decommissioning costs and booking of significantly more reserves. Now turning our attention to NEON on slide 18, and starting with the NEON resource upgrade. The team re-evaluated the NEON resource, leading to a 44% increase in 2C contingent resources to 86.5 million barrels of oil, which has increased our confidence that NEON is an attractive, robust, and value accretive growth project. In April, we moved the project into the defined phase. Slide 19 outlines the current expected timeline for the defined phase of NEON. This phase has been split into three sub-stages to limit capital exposure and allow the team the opportunity to reconfirm the economic merits of the project in light of current oil price volatility at each sub-stage gate. The first stage of the farm down process involving engagement with potentially interested third parties and targeting the sale of a 30% to 50% interest in NEON and surrounding licenses has commenced. The next milestone for NEON is expected to take place in Q126 when we will decide whether the development should progress to the second sub-stage of the defined phase. This stage gate is some three months later than previously planned as we continue to refine the field development plan and the detailed basis of design, and as we progress the contracting and procurement strategy, and also, of course, as we seek a farm in A. The second stage will also involve environmental and seabed surveys, as well as issuing tenders to refine the cost estimates for the development. A farm down and continued positive results from the staged decision-making process are prerequisites to achieving a potential neon final investment decision in the second half of 2026. Now turning to the U.S. on slide 20. HUDAT performed in line with our expectations, delivering 5.6 million barrels gross of oil equivalent in the first half. This is 1.4 million barrels of oil equivalent net revenue interest to Karun. Production benefited from improved facility uptime towards the end of the period following routine maintenance and oil treater replacement. Houdat is tracking to plan with full 2025 production guidance narrowed to 2.4 to 2.7 million barrels of oil equivalent. We expect second half volumes to be somewhat lower than the first half due to natural decline and anticipated potential hurricane related downtime during August to October. Houdat is a midlife asset and to help mitigate natural decline, the joint venture has identified several attractive infield targets. Drilling of the first of these, the E6 sidetrack is expected to commence in late third quarter 25 and is expected to add an initial 3,000 to 5,000 barrels per day gross of liquids from mid fourth quarter 25 prior to natural decline. There is a second sidetrack opportunity that is being progressed with the activity now expected to take place in Q1 2026. The operator log also completed de-bottlemaking studies during the first half. The studies identified opportunities to improve reliability and confirmed minimal work on the FPS would be required to develop our next project there, which is Houdat East. Moving to slide 21, The joint venture continues to progress the development planning for Houdat East and for the Houdat South discovery. Houdat East is currently the more advanced of these two. Following detailed technical and economic assessments, the preferred development concept for Houdat East is a tieback via the A Manifold to the Houdat FPS. Alternative options were ruled out due to higher costs, flow assurance challenges, and less favorable likely commercial outcomes. Work is now focused on finalising engineering, on flow assurance, subsea routing and topsides design, with FID targeted for late 2025 or early 2026. For HUDAT South, efforts are underway to reduce subsurface uncertainty and refine our resource estimates. The team is assessing whether a potential development of Houdat South could include completing the existing well as a producer or drilling a sidetrack, supported by ongoing seismic reprocessing and dynamic reservoir modelling. Now, lastly, moving to the summary on slide 22, we have a very clear set of deliverables for 2025 and beyond, and the team has made good progress in moving each of these forward. Our top priority is to maintain safe, reliable, and low-cost operations marked by capital discipline while maturing our value-accretive organic growth opportunities at NEON and at Houdat. Our robust cash flow, even with some tempering of production expectations due to the electrical fault at SPS 92, in combination with our liquidity and low leverage, allows us the opportunity to continue returning capital to shareholders while also progressing our attractive organic growth pipeline. Lastly, as we have indicated at the 2025 AGM, Karun is in the process of relocating several corporate head office roles from Melbourne to Houston and to Rio de Janeiro. The transition is aimed at simplifying our structure, increasing efficiency and facilitating collaboration, and will take place in a very controlled and orderly fashion over the next 12 months. I would like to thank all of our staff and contractors for their hard work and dedication to Karoon, and to also thank our shareholders for their continued support of the company. Ray, Anne, and I would now be very happy to take any questions, first from the telephone lines, and then if there are any calls into the online facility. I'll now hand back to our moderator, Darcy.

Thank you. If you would like to ask a question via the phones, you need to press the star key followed by the number one on your telephone keypad. If you would like to cancel your request, please press star two. If you are on a speakerphone, please pick up the handset to ask your question. For the sake of time today, we kindly ask that you please limit yourself to two questions at a time, after which you're more than welcome to rejoin the queue. If you would like to ask a question via the webcast, please type it into the ask a question box and click submit. Your first question today from the phone comes from Dale Coenders from Baron Joey. Please go ahead.

Morning, Julian, Ray, Ann and team. Julian, I was just hoping you could share a little bit of colour on how you're thinking about Bayoona production outlook now. The reserve upgrades are a fantastic result, but given limited life, this doesn't produce for forever, so it almost looks like you're assuming a recovery back to the mid-20s post-workover in 26 and then a much shallower decline than the circa 15% discussed previously.

Yeah, thanks. Thanks, Dale. And thanks for joining the call. Look, what we're seeing at Bona in terms of decline rates is now something a lot more similar to what we experienced shortly after we took over Bona operations from Petrobras in 2020 and 2021. At that point, before we undertook the interventions and the Patola project, we observed a decline rate, which was originally around 13% to 15% per annum, but then that decreased to a sort of 10%-ish type range. And that's more of what we're seeing now with our production having stabilized significantly following the 22 campaign, when obviously we saw flush production not only from that intervention work, but also from the patola field. We now think that that has stabilized in terms of the pressure front moving through the aquifer and that we're seeing longer term decline rates that are around about that 10% mark. That's what leads us to obviously book about 4 million barrels of the reserves increase that we're seeing. But then also a substantial part of the reserves increase is coming from a reduced operating cost and extended economic life at the FPSO itself. And that takes us now, we think, out to the end of the current production license in the late 2030s, giving us that significant increase in reserves.

Okay, thank you. And then the second question maybe is for Ray. How are we thinking now around DNA for Bayouna going forward given reserve step-up and higher abandonment forecasts at the extended end of life?

Sure, thanks Dale, hi. So when you look at abandonment Overall provision for abandonment, the total cost has gone up a little, but because it's moved out in time, I guess the trajectory is shallower. And that will be similar in DNA. So as we restate the unit DNA rates, that will take account of that, I guess, prolonged reserve life. So it will be a shallower run on DNA. Um, but it'll still be on a unit of production basis. So I think you can still take the, the reserves to be produced and, and then, you know, and then project the, um, the production at those decline rates that Julian spoke about into the future.

That meaningful stepped out in DNA should be seen in the second half of this calendar year.

Yeah. Well, I don't think it's, it's, it's already, we've put it in the, we've put it into guidance. It's not a, it's not a large, um, rate decline. Um, partly because we have to factor in the workovers that are required to extend the life of that field. So we have to forecast the ESP replacements, two more of those, through the end of the life, if that makes sense. So it's not purely on what's been spent to date. So it does have a decline, but it's not material in the next half.

Okay, perfect. Thank you.

Thank you. Your next question comes from Henry Meyer from Goldman Sachs. Please go ahead.

Good morning, team, and congratulations, Julian, on your time leading Karoon. If I can just follow up on the reserves upgrade and production outlook, would you expect any step changes beyond that 10% decline as well, just considering we'd have a number of wells with different artificial lift systems that would eventually decline and fail under different mechanisms?

Yeah, it's a great question, Henry, around the long-term plans for Boone. Obviously, we'll continue to monitor the field in great detail and continue to monitor where the decline rates go. Typically on fields of this type, which have what we call a piston-type displacement mechanism, we do see high rates of recovery long term. And that's certainly what we are seeing already at Bowen and what we anticipate we'll continue to see. You're right in that some of the planning will involve looking at future ESP replacements. And of course, we'll monitor very carefully the performance of the gas lift wells. We currently project that we will need to replace ESPs about every three to four years. SPS 92 obviously is a little bit disappointing in seeing that partial failure a little earlier than we would have liked. But three to four years is about the average timeframe that we see across the industry for these types of pumps. So, yeah, I do anticipate that we'll see a couple more campaigns through the life of the field. And those will be assessed at the time for the economic merits of, obviously, mobilization and intervention activities. So, yeah, doubtless there will be future campaigns. And that is already factored into our view of future reserves bookings at Bellinor.

Great. Okay. Thanks, Julian. And a bit further north, Neon's making good progress with the potential tieback of Kurokuka. I'm probably pronouncing that wrong. Just any details you could share on how that development concept's shaping up and perhaps a ballpark range on CapEx for what you're seeing so far?

So the overall range of CapEx that we see for Neon still sits in that $0.9 to $1.2 billion. We are going through a phase now, obviously, of starting to engage more heavily with contractors ahead of a decision around the end of this year or in the first quarter of next year to go into the next sub-stage when we'll be doing that engagement in force. But that CapEx range at the moment seems to be... about where we think we'll end up, and we haven't seen any indications yet to alter that. In terms of Pirikuka, yeah, that obviously is new for Karun. It has a resource that has been identified there already. through an earlier Petrobras drilling campaign. We anticipate that towards the end of this year, we will have worked that resource into a potential future tie-in to the potential NEON development, and that we should be in a position to book some contingent resource at that discovery at that point. So that'll be end of the year, going into our early 26 normal annual contingent resource and reserves bookings. At this stage, it's too early to say what we believe those numbers are likely to be, but obviously we acquired the licenses because we feel that there is good upside potential there for for a neon development.

Excellent. Thank you.

Thank you. Your next question comes from Nick Burns from Jarden, Australia. Please go ahead.

Hi everyone. Look, first question from me just on the ESP repair at SPS 92. Can we just talk a bit about the scope? My understanding is I think you have two ESPs in operation at the moment and one at PRA 2 as well. Will you take the opportunity to repair or replace PRA 2 at the same time? Thank you.

Nick, that's a great question. It's a $64 million question, to be honest. We will assess that and continue to assess PRA2 over the coming six-plus months as we prepare for the SPS92 replacement. We do have ESPs in stock available, so we don't have any issues around the lead time to replace the second pump, should we need to do that. But we'll look very carefully at that pump, and also at our drilling program as we go through the next few months. Obviously, it would be ideal to be able to have more than just a pump replacement, and so we'll be seeking other opportunities for things we can do with the drilling rig in that timeframe. At the moment, the team is very focused on ensuring we have the best plan for the SPS-92 replacement, but I believe it's very likely we will also look very, very carefully at perhaps preemptively replacing the PRA-2 pump replacement. with a rig mobilized and in the field. And by that stage, that pump being about four years in place and operating, it might be a wise choice to make. Having said that, there is an old saying I'm sure you'll be aware of, if it ain't broke, don't fix it. So the team will need to weigh that up against the risks, of course, at the time. At the moment, we haven't made a decision, but that'll be one of the key things we analyse over the coming months.

And do you have an approximate cost to repair SPS92 and how much additional cost you would incur if you did go after PRA2 at the same time?

So we're in the market at the moment looking at potential drilling units, looking at things like mobilization day rates, whether we can use a DP type rig, so a dynamically positioned rig, or whether we need a moored rig that would also require anchor handling tugs as well. All of those will feed into our final cost estimates for drilling. the intervention work. Doing a second intervention obviously will incur additional day rates, but it won't really incur any significant additional mobilization or demobilization costs. So there will be some relative cost savings for doing a second intervention should we choose to do that. At this stage, we're still at a very early point in analyzing what the numbers are likely to look like, Nick. As soon as we have that type of number available, we'll be able to communicate it to the market. But it's a little early at the moment. I would say that we have replaced these pumps. Karun has experience in replacing these pumps in the past. When we bought the field, we knew that was one of the first things we wanted to do. So we replaced pumps in PRA2 and in SPS92. So we do know the downhole conditions. Whereas when we did this three or four years ago, we were unsure of what those downhole conditions were like. So we should have a much clearer idea of the operational timeframe that would be required to replace the pumps. But these are not simple operations. We need a big, heavy workover unit that can lift the wellhead. So we take the wellhead off. before we re-enter the hole. And the pumps themselves are part of a string which is about 70 meters long. So they're not the sort of thing you put on your pool pump. These are big, big pieces of kit and require extensive planning and flawless execution. Pleasingly, the previous times that we did these pub replacements, the execution was excellent. So I am confident that we can do that in a similar way this time around.

That's great. Thanks for the extra colour there, Julian. Appreciate it. Cheers.

Thank you. Once again, if you would like to ask a question, please press star 1 on your telephone and wait for your name to be announced. Your next question comes from Rob Coe from Morgan Stanley. Please go ahead.

Good morning. Congratulations on the announcements, and on a personal note, all the best to you, Dr. Fowles, going forward. Thank you very much. Just a question from me. I guess we'll be looking to extend the DCF for Bayona, and I know it's a little tricky to give us forecasts out to 2039, but can you give us firstly some colour on if there's any ability to extend the concession, any process there. And then secondly, perhaps a question for Mr Church on the abandonment estimate change. If you could give us some colour on the, like bridging the change in the cost there, I guess adding the FPSO in there is the big activity and scope change, but any additional colour would be helpful, thank you.

Yeah, good morning, Rob, and thanks for that question. I think when we look at At the long-term or longer-term production for Bona, obviously we will need to assess as we get to the end of concession life, the economics and the operational, continued operational viability of the FPSO and of the Bona field overall. There are certainly examples offshore Brazil of concessions being extended. And although it's a long way away, I would be optimistic and very hopeful that we would be able to be persuasive with the regulator and with the Brazilian government that continued production through Bona would make strong economic sense for the government in terms of tax revenues, royalty revenues, continued employment, et cetera. And I would think that that should be quite a strong case to make. Obviously, it's a long way in the future, and there will be maybe not even my successor, but my successor's successor perhaps will be the one who addresses that. So, yeah, but there's plenty of examples in Brazil, and I'd be very, very hopeful that we could be persuasive with the government around that. I'll hand it over to Ray to address the abandonment cost questions.

Yeah. So we've taken the, I guess, the NPV on the Bowen and Potola abandonment has gone up to around 194 million from mid-140s. So we've gone up about 50 million on an NPV basis. That's discounted at the Fed 10-year rate. So and that also means that it's the abandonment is I think it's around 240 million, which includes the FPSO. That's now, of course, moved out to 2039 where it used to be at 2032. So if you take that effectively NPV of 50 million and then unwind that over the, I guess, an extended period of another seven years. Does that help, Rob?

Yep, that's great.

Thank you very much. Thank you.

Thank you. The next question comes from Gordon Ramsey from RBC Capital Markets. Please go ahead.

Thank you. Julian, just on your reserve increase at the unit, the 2p level, just trying to get a feel if there's any risk there. You've mentioned a substantial amount of it has come from reduced operating costs. If I'm looking at the 17.6 million barrels, that looks like around 75% of the increase. You mentioned 4 million barrels. I'm looking at decline. I'm assuming that's decline curve analysis. Have you made any change to the recovery factor in the field?

Yeah. Morning, Gordon. The recovery factor, of course, on a reserves basis improves as you move contingent into reserves. And what we see with the field, as I mentioned previously, is that we have a... a piston type of displacement mechanism where the relative mobility of the water in the aquifer and the relative mobility of the oil are very, very similar, which means that our wells tend to get to a relatively steady water cut that then doesn't appear to increase at a significant rate over time. We see that at SPS 92 and in a number of the other wells. And I believe that that reflects that that displacement mechanism in the reservoir. So, yes, we do see improving recovery factors for the field. Having said that, you can solve the sort of recoveries that we're seeing, you can solve that in more than one way, not just by effectively having higher recovery factors or a lower level of residual saturation of oil. But you can also do it by recovering more oil than we perhaps see at the moment. And that could be sub-seismic scale areas, pockets, pools of oil, that we're connected to that we don't necessarily identify on the existing subsurface data set. So there is more than one way to solve for those uncertainties. But certainly over time, we anticipate that we'll see higher recovery factors than we have previously anticipated for subsurface for each of the fields. So remember, there's three fields, Bona, Piracaba, and Patola. We'll see higher recovery factors in those over time.

Sorry, Julian. So my comment that 75% of the increase is from lower operating costs, is that right?

Yeah, a substantial part is because we've purchased the FPSO, we are now able to drive lower costs through the operating mechanism, and that allows us then to look at longer life for the field. However, I have to say that is also in combination with higher, longer-term production rates, which also contribute to the economics. So it's not just the – it's a lower decline rate giving us longer, higher production rates combined with a lower operating cost, and those combined just pushes over the threshold, the economic thresholds, to allow us then to extend the life out to the end of the production license.

Okay, just one more from me. You mentioned earlier that there are several areas of FBSO reliability and vulnerability that remain. Can you just run through what those key areas are?

Yeah, so there's a few areas I would point to. First of all, we still have a substantial amount of maintenance to do on pipework on the FPSO, pipework which obviously holds back hydrocarbons, holds them inside the pipes. We've replaced a number of pipe sections and spool sections on the FPSO, many, many kilometres, in fact, over the last couple of years. But we also have a number of areas with temporary repairs. And part of what we'll be doing during the Flotel campaign next year is to make those temporary repairs permanent. So there are vulnerabilities around that. Temporary repairs are obviously not as robust as permanent repairs. Secondly, I would point to the gas compression capability on the FPSO. We have a number of gas compressors, and those are large pieces of rotating equipment. And as with any rotating equipment, as you get later in field life, that becomes more vulnerable to breakdown. We have seen that over the last six months. We've seen that one of the key areas of vulnerability is gas compression on the FPSO. We have in place a significant amount of work ongoing right now which is upgrading and maintaining two of those key compressors. And the compressors are really important for our production because they allow gas lift to be maintained at a number of our wells. And if one of our gas compressors falls over, we can still maintain production. But if a second one falls over, we then are prone to more gas flaring. And there are very stringent gas flaring limits in Brazil, which obviously we adhere to. So although we can continue producing with two compressors out, we would reduce our production rates somewhat to stay within gas flaring limits. And we've seen that a number of times through this year. With one gas compressor out, we can continue to operate at full rates. So there's vulnerability there, as I said, in a couple of areas that are being addressed and for which we have plans to address over the coming months.

Thanks, Julian, and all the best.

Thanks, Gordon.

Thank you. There are no further phone questions. I'll now hand back over for any webcast questions to be addressed.

Thank you, Darcy. There are a couple of questions on the web, some of which I think we've already answered, so I'll just ask those which are outstanding. The first one is from Anthony Correa. He says, Houdat now seems to be delivering on growth with the E6 well expected to flow at 3,000 to 5,000 barrels a day. What is the expected flow rates at Houdat East, and what else can we expect from Houdat's natural gas deep reserves?

Yeah, Anthony, thanks for that question. And yeah, it's a great, it's a couple of really good points there. Huda at East is obviously not yet, hasn't yet reached a final investment decision. We expect that to take place towards the end of this year or early in 2026. And at this stage, we don't have yet firm numbers that work towards what that is. FID will look like in terms of capex or in terms of likely production rates. However, I would anticipate that it'll be many thousands of BOEs a day. Remember, it's a gas condensate reservoir at Houdat East. has about 50-50 gas versus or BOEs of gas versus barrels of liquid. And it is a highly attractive development for us. But we're still going through the process with the operator and our joint venture partners of delineating exactly what that field can deliver. And we'll be in a much better position towards the end of this year to highlight that. Your second question or second point was, Anne, remind me.

About the natural deep reserves.

The deep reserves. Underneath Houdat East, we have identified a large gas prospect, which we saw at the time that we farmed into the acreage. That is quite a bit deeper than any penetrations in that area to date, and it does cover quite a large area. There is a seismic anomaly in that area. These seismic anomalies don't always indicate the presence of hydrocarbons, but they can. And there's quite a bit more further work to do in that area in order to de-risk that prospect to make it viable for drilling. It's not, at the moment, sufficiently mature to be put on a drilling sequence. However, looking at where gas prices are going and where they're likely to go over the next few years in the U.S. Gulf, we do feel that should that be de-risked sufficiently, it would be a very attractive area for us to deepen a well or to drill a new well into. But that work is still ongoing, Anthony, and is quite an area of focus for the future. Thank you.

Anthony also has a question about the Pirukukaa blocks. Are they included in the farming process at Neon, farm down process?

So the Pirukukaa, there's two blocks at Pirukukaa, shallow water to the north of Neon. We touched on these earlier on. They do have some resources already delineated by... five or six wells that were drilled by Petrobras many years ago. Not sufficient volume there for Petrobras to be able to develop that as a standalone development. But obviously with NEON potentially approaching an FID in 2026, these could be attractive tiebacks. The licenses, although we won the licenses in the bid round in June, they have not yet been formally awarded, so we have to go through a formal award process. At that point, those licenses can then be formally attributed to Karun and to Karun's resource base. However, we have advised participants who are currently having a look at the NEON area with a view to farming in, we have advised those participants that we expect to put the Pirikuka area into the farm down process and would expect a farm in E to participate in that as well. That's likely to be, as I said, towards the end of this year and will obviously come ahead of any potential resource bookings that Karun will make in that area.

Thank you, Julian. The next question is from Hazmi Hazin from Foster Stockbroking. SPS 88 was only recently restarted after downtime, and now SPS 92 is also experiencing problems. Should we expect these well issues to become a recurring theme, or are there measures in place to prevent further occurrences?

Yeah, look, it's a good question. You know, when you're dealing with midlife operating assets where you have secondary recovery mechanisms in place downhole, you're very much reliant on that equipment itself. So SPS-88 has gas lift installed and the gas lift valve encountered issues Yeah, I guess about not quite two years ago, but 18 months ago or so. And that's why we had to go in and replace the gas lift valve and mandrel in SPS-88. That is a failure mechanism that we in the industry have seen elsewhere around the world. And it's certainly a possibility that we could encounter a gas lift valve or a mandrel in issue at some point in the future. Having said that, we replaced the SPS88 valve with the most recent technical components, which have shown themselves to be much more reliable than the components installed some 10 or 15 years ago into that well. In terms of pumps and pump replacement, we anticipate that we will have to have multiple campaigns of pump replacement. We have always flagged that since the acquisition of Bauna back in 2020. So these things don't last forever. They are down-haul, so they are complex pieces of equipment to replace that cost capital. Part of our reserves booking this morning has taken into account future pump replacement economics, but that still allows us, we believe, to extend the life of production at Bona out to the end of the licence period.

Julian, can I just add that I think SPS92 is within a week or two of three years of its installation, which is not unreasonably out of its life.

Yeah, look, as I said in my presentation, we anticipate three to four years to be the average lifetime of these types of pumps. There's actually an industry range which is something less than two years up to about 10 years at the very, very maximum end of the range. So yeah, three to four years is about what we anticipate and looking forward, that's likely if we replace these pumps in 2026, that likely means at some time, 2029, 2030, we would undergo a further period of pump replacement. Having said that, Each of these wells with pumps in them, so PRA2 and SPS92, can be operated with gas lift, just not at such high production rates. And so that is something towards the end of field life that will likely be the type of production mechanism that we use in these wells if we're no longer economically justified in going in with a heavy workover to replace pumps.

Thanks, Julian. The last question is also from Hasby, and he asks, what is your outlook for the oil price in the second half of 2025?

Oil prices have been very volatile through 2025. We sort of seem to have stabilized around that $65 mark, maybe somewhere between $60 and $70 a barrel is a sort of worthy guess of where that may end up. But there's currently lots and lots of... around competing factors in the market, around demand, but also around supply. It's interesting to observe that the Permian in the US, the operators there have been, I think, very conservative in their approach to looking at how they increase or do not increase oil production from those fields. So it's a really interesting time in the oil markets. We at Karun look at the futures curve in terms of looking at how we manage future investment plans as we look at the futures curve over the next 18 months or so. And then beyond that, we look at where broker estimates and where those averages lie. And we tend to sit around the middle of the range on those, so we're not particularly bullish or particularly bearish either way on our future projections of oil price. Personally, I feel oil prices will continue to be quite volatile over the next two to three years. But beyond that, that we're likely to see quite a strongly constructive period for oil prices as demand continues to be strong and as supply becomes a little more challenged towards the end of this decade. Remember that over the last decade, Five years, we have seen quite significantly reduced capital expenditure on field developments, and that has to have a long-term impact on supply.

Thank you. There are no further questions.

Thank you very much, Anne. With no further questions, I'd like to call a close to the proceedings. Thank you very much once again to everyone who has participated in the call and for all of your questions. And thank you very much once again to our shareholders and to our staff for their phenomenal contribution over the last 12 months. in getting Bona back on track and setting Karun up for what promises to be a very interesting and beneficial future. Thank you very much to all.

That does conclude our conference for today. Thank you for participating. You may now disconnect.