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.