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Operator: Thank you for standing by, and welcome to the Karoon Energy Limited 2025 Full Year Results Briefing. [Operator Instructions] I would now like to hand the conference over to Ms. Carri Lockhart, CEO and Managing Director. Please go ahead.
Carri Lockhart: Thank you. Good morning, everyone, and thank you for joining our 2025 full year results webcast. My name is Carri Lockhart, CEO and Managing Director of Karoon. I have with me this morning, Ray Church, our CFO; and Ann Diamant, our SVP of Investor Relations. Earlier this morning, we released our 2025 full year results to the market. This presentation should be read in conjunction with the ASX announcement, and I draw your attention to the disclaimers on Slide 2 and notes and definitions on Slide 3. I will move directly to Slide 5, which provides an overview of 2025. We are pleased with Karoon's performance during 2025. We produced 10.3 million BOEs, which was nearly on par with last year despite well issues and natural decline. While our sale revenue and NPAT were lower in 2025, largely due to the softer oil prices, our low-cost, high-margin assets generated $231 million of operating cash flows, demonstrating the robustness of our business. These cash flows underpin the disciplined investment in our organic growth opportunities and healthy returns to shareholders. We paid shareholders $80 million, which includes $35 million in dividends and $45 million in buybacks. Since the second half of 2024, we have purchased and canceled 11% of shares on issue, delivering solid returns to our shareholders. I will share more about our operations, Reserves and Resource base and projects while Ray Church will discuss the 2025 results later in the presentation. Slide 6 summarizes our good safety record and sustainability initiatives. We achieved a year-on-year improvement in both personnel and process safety, which are core to how we run our business. We also reduced our flaring by 41% compared to 2024 as we improved operations and FPSO reliability. We do remain committed to being 100% carbon neutral for Scope 1 and 2 emissions, primarily by surrendering independently verified carbon offsets. This has been achieved since 2021. We will remain relentless in our aim of delivering 0 injuries every day, minimizing our environmental impact where practical and cost-effective and being a positive supporter to the communities in which we work and operate. Moving to Slide 7. We achieved a total shareholder return of 16% in 2025. Our share price appreciated 11%, closing the year at AUD 1.54 per share, and we paid AUD 0.074 per share of dividends unfranked during the year. Our positive share price performance was despite Brent crude price declining 19% and the ASX 200 Energy Index being down 2% over '25. The Board has declared a fully franked final dividend for 2025 of AUD 0.031 per share to be paid on March 31, 2026, bringing the total dividend declared for 2025 to AUD 0.055 per share. On the next slide, we show our capital allocation framework and our priorities to create value for shareholders, which remain unchanged. The on-market buyback program has been reviewed as we enter a period of higher capital-intensive work during the first part of this year as well as oil price volatility. We believe with the strong fundamentals from the base business and our current share price, which, in our view, remains undervalued by the market, it is prudent to continue with the on-market purchases as part of our disciplined approach to capital allocation. As we move to Slide 9, Reserves and Resource growth have been an ongoing thematic for Karoon over the years, and this year is no exception. Reserves increased 7% year-on-year, primarily due to conversion of Bauna 2C to 2P as acquiring the FPSO and reducing operating costs has given us the confidence in being able to produce to late 2030s. As a result, Reserves life has also increased to 7.1 years. Our 2C Contingent Resource saw an increase of 34%, driven by an upgrade in the Neon Resource with improved subsurface characterization and the acquisition of licenses containing the Piracuca field. On Slide 10, our business has a healthy and balanced pipeline of portfolio growth opportunities in different phases of maturity. The short term includes short-cycle project deliveries, primarily at Who Dat in the Gulf of America. The medium term includes Neon and potentially Piracuca, Goia and the Neon West in Brazil, which we are continuing to mature. In the long term, we have a sizable prospective exploration acreage position in the South Santos Basin. I will talk about each of these opportunities in more detail shortly. Now I'd like to hand over to Ray, our CFO, who will run through the financial highlights.
Raymond Kenneth Church: Thanks, Carri. Good morning, everyone. I'll move right into Slide 12 and open by saying that in 2025, the FPSO acquisition, oil price impacts on the Petrobras contingent consideration provision and expense treatment of the flotel campaign make it important to look through to the underlying results. Slide 29 in the appendix shows these items in a reconciliation of statutory to underlying results, and I'll now focus on those underlying numbers. With production of 10.3 million BOE marginally down from 2024, 15 offloads took place at Bauna in 2025 versus 16 last year. Revenue was also affected by oil price, resulting in sales of $628.6 million versus $776.5 million in 2024. With costs largely fixed, that revenue reduction flowed directly to underlying EBITDAX and operating cash flow, partly offset by royalty reductions and FPSO lease savings. As you can see, we drew cash to close the year with $143.9 million of net debt, primarily as we funded the FPSO acquisition. I'll say more about cash movements on later slides. Turning to underlying earnings on Slide 13 and to provide more detail, the revenue reduction comprised 2 parts. The first being $100.4 million from realized price as the average liquids price was 14% lower at Bauna and 17% lower at Who Dat and the second being $47.5 million from a sales volume reduction, mostly at Bauna. Production costs improved by a net $7 million through savings of $40 million in FPSO lease D&A and interest costs, offset by roughly $28 million of temporary FPSO transition support costs and $5 million of logistics and nonrecurring mooring line repair costs. Royalties reduced by $7 million in line with price and produced volumes and crude inventory movements were $26 million as a lifting occurred in January 2026. The majority of the increase in net finance and interest costs relates to the accounting treatment of $17.8 million of withholding tax on intra-group funds movements. This is fully offset in income tax expense. Of the remaining $52.4 million, the increase year-on-year is a result of $3.9 million of full year bond interest impacts plus $4.2 million of reduced interest received as we drew down cash. And as I mentioned, income tax expense includes $17.8 million credit for withholding tax, neutralizing the impact on NPAT in the year. Excluding this item from tax expense and profit before tax, the underlying tax expense rate is 33%. This all leads to an underlying NPAT of $107.5 million. Slide 14 provides a per BOE view of the 2024 and 2025 cost structure on a pre-AASB16 basis. Despite the oil price decline, the pretax cash margin remained above 65% per BOE. Unit production costs further reduced to $13.20 and breakeven realized price improved from $33 to $31 per BOE. This reflects the ongoing work to improve topside efficiency, replace natural decline and the emerging FPSO acquisition impacts, and it demonstrates Karoon's leverage to oil price. Moving to Slide 15. As I've already flagged, EBITDAX included the flotel costs and converted after taxes and net finance costs to $231.3 million of operating cash flow, including FPSO lease payments. This provided adequate funding for CapEx investments in the Who Dat sidetrack and SPS-88 as well as the last of the largest Petrobras contingent payments, leaving $57.8 million of free cash from operations. This, combined with our opening cash was then applied to the strategic FPSO acquisition and capital returns to shareholders, resulting in a net drawdown of cash of $135.1 million. This led to the change in net debt mentioned earlier. Moving to liquidity and the balance sheet. Slide 16 shows this cash reduction to close the year with $206.1 million of cash. As no further draw on debt was necessary in the year, the combination of the RBL debt facility and cash leaves us with $546.1 million of total liquidity at year-end. This positions Karoon's balance sheet for the second extended shutdown and flotel campaign and well works at Bauna and Who Dat with approximately 85% of this planned 2026 CapEx expected to be spent in the first half. It will also fund the much reduced contingent consideration and the announced capital returns. I'd like to finally note that the RBL facility amortizes with Reserves and is reassessed in April and October of each year. Thank you. And now I'll hand back over to Carri.
Carri Lockhart: Thank you, Ray. Looking forward to 2026, we see the year as having 2 distinct halves. This first half is a period of intense investment and the second half when we aim to realize the benefits of this work. Over the next few months, we will realize on performing essential inspections, maintenance, the annual turnaround, systems revitalization and upgrades on the Bauna FPSO, together with the production riser reinstatement work at Who Dat. Regarding wells, we have 1 well and 1 subsea intervention plan in Brazil aimed at restoring well production and a sidetrack plant at Who Dat. Assuming the operational programs in the first half go as planned and oil prices remain steady, we expect to realize increased facility uptime and production as well as operating cost reductions, in turn, delivering strong cash flow generation. Next slide. The Bauna FPSO acquisition was a very significant milestone for Karoon as it provided us with strategic control over arguably our most important asset. Acquiring the vessel has already led to improved safety, reliability and cost efficiencies. Production from Bauna in 2025 was higher than 2024 despite natural decline and was driven by improved FPSO efficiencies of 95% versus 84.5% in 2024. The acquisition also allowed us to extend field life by 7 years to 2039 and increase our 2P Reserves. As shown on Slide 20, our Brazil operations team are heavily focused on several major concurrent activities during the first half '26, as previously mentioned. Our FPSO revitalization campaign is currently planned over a 4-month window with an option of a 2-month extension if necessary. For most of this time, we will be producing as normal. The annual maintenance turnaround is planned to commence during March and will run for 28 days. Alongside this, we expect to conduct SPS-92 and PRA-2 well activities in late March to early May window. These concurrent offshore activities present both a challenge and an opportunity with safety remaining our highest priority throughout. Simultaneous operations and logistics are being managed via detailed planning and the use of a flotel, which is already on location. The drilling rig is expected to mobilize in the field in second quarter to undertake the SPS-92 ESP well workover. And at peak offshore workforce at Bauna is expected to exceed 700 personnel compared to a typical complement of around 90. On Slide 21, during 2025, our Neon team completed some excellent subsurface work further maturing the Neon development opportunity, resulting in Neon 2C Contingent Resources increasing by 50% to 90.3 million barrels. Additionally, we picked up the nearby Piracuca Resource, which allowed us to book a further $19.6 million of 2C Contingent Resource, while 2U Prospective Resource at the nearby Neon West exploration prospect increased 69% to 25 million barrels unrisked based on technical studies completed in the year. The Neon work was centered on a stand-alone redeployed FPSO development concept. Late last year, our preferred concept option went off the market. Since then, other available FPSO options have been identified, including the strategic ownership of the Bauna FPSO, which may present a more value creative development solution. Our focus over the next few months will be on further assessing and optimizing the Neon development concept in a disciplined project management process, including cost reductions and exploring potential synergies with Bauna and the future development of Piracuca and Goia discoveries as part of the greater Neon area development plan. We are also well into a competitive farm-down process, which is targeting a 30% to 50% interest sell-down in Neon and the surrounding areas. This cost reduction initiative, development concept review and equity farm-down will steer our defined and feed activities and schedule. On Slide 22, Karoon has built a substantial acreage position of over 7,300 square kilometers in recent Brazilian licensing round, all with no associated drilling commitments. We believe this area located in the South Santos Basin has a working petroleum system to support the potential post-salt tertiary play. Although it isn't tested and unproven, our work to date suggests this area and potential targets could potentially be significant if successful. Our leading drill candidate is currently the Eta Front prospect located in S-M-1482, which is supported by seismic direct hydrocarbon indicators. Extensive work remains in the surrounding acreage to assess additional prospectivity. We have begun a farm-down process and have secured a rig option to potentially drill in 2027. This is subject to farm-down results and technical and regulatory requirements. As we move to Slide 23, our non-operated Who Dat asset produced in line with our expectations in 2025. We saw an increase in liquids contribution as the year progressed, finishing with 74% liquids and 26% gas. Our production share on a net revenue interest NRI basis was 2.6 million BOE in 2025, with the natural reservoir decline rate mitigated to 10% relative to 2024. The E6 sidetrack well was successfully drilled and completed under budget with excellent rig performance. The well, which came online in fourth quarter '25 flowed within expectations at a rate of 1,050 BOEs per day on an NRI basis. In early February, a minor leak was detected on 1 of the 6 production risers at Who Dat data floating production system. The riser was immediately shut in and has since undergone inspection and seawater flushing to remove the hydrocarbons. The operator LLOG is currently working to reroute production if feasible and proceed with repairs and reinstatement of the riser. As a result, Who Dat first half production is estimated to be lower than planned. However, the 2026 Who Dat production is currently expected to be within our guidance range of 2.1 million to 2.5 million BOEs on an NRI basis, albeit at the lower end based on current plans for reinstating production from the riser and other activities such as the planned A1 sidetrack, which is estimated to start operations in early Q2. On the next slide, we have 2 potential Who Dat development opportunities in the U.S. Gulf of America. Both are short cycle and are proximal to the existing infrastructure. The joint venture is maturing the Who Dat East opportunity towards a potential final investment decision, which is subject to royalty relief and project commerciality. The preferred development concept is a single well tieback to infrastructure. We expect this could add 3,500 to 5,000 BOE per day of initial flow rate net to Karoon on an NRI basis. The Who Dat South has been undergoing further geologic and geo studies. We believe the Who Dat area has additional potential for value-creating opportunities that leverage the existing infrastructure. Karoon participated in the recent Gulf of America bid round, and we are a parent successful bidder of block Mississippi Canyon 587 near Who Dat South. We plan to purchase additional seismic to further mature the potential prospects on that block once it is rewarded. Our final slide showcases our focus on leveraging our competitive advantages to optimize total shareholder returns. We're doing this by maintaining safe and reliable operations of these high-quality assets and ensuring low-cost and high-margin barrels. Our strong balance sheet provides us with the flexibility to sustain business and balance capital returns with our organic value-accretive portfolio and growth opportunities. I would like to thank all of our staff and contractors for their hard work and dedication to Karoon and to thank our shareholders for their continued support of the company. Ray, Ann and I are now happy to take any questions, first from the telephone lines and then from the online facility. Now I will hand it back to the moderator.
Operator: [Operator Instructions] Your first question comes from Dale Koenders with Barrenjoey.
Dale Koenders: Carri, I was hoping you could provide a bit more color on the Neon optimization works. What are the cost-out opportunities that are currently being explored and considered?
Carri Lockhart: Thanks, Dale. So let me step back on what has changed. We were designing to a stand-alone FPSO concept. And of course, as I mentioned, the vessel went off the market late last year about the time that I arrived. And then at that time, we're also seeing the softer oil prices. And then prior to that, we acquired the Piracuca license, and we completed, of course, this very strategic acquisition of the Bauna. So when you put all these factors together, naturally me coming in, I'm going to ask the question of how do we continue to drive out cost in this project and get it across the finish line, which I firmly believe we can. So it was a good opportunity for us to revisit the concept with a focus on reducing cost and optimizing these plans. So where are we at now? We have 2 parallel processes running. The first is evaluating alternate developments and a disciplined project review that considers the strategic ownership of the Bauna vessel. And I think this can enhance economics. We also have the farm-down process, which has started last year. So the review is kicking off, and it's a very disciplined review. And I think both of these will run their path and the FID timing will logically follow. And we are going to be placed in the economic -- or the economics of the projects and the process of this review process over defined schedule. And I will say coming into this, my experience is that a schedule-driven process is not conducive to maximizing returns. And I do think that there are several different interesting concepts that we're exploring that will improve the project as you see other companies doing in lower oil prices and their projects always come out of the tail end much better.
Dale Koenders: I feel like you've preempted my second question by stating schedule-driven processes don't define the best outcome in a success case, what could be an FID date is end of '26 a more realistic outcome? Or how should we think about when the balance sheet might need to support such a project?
Carri Lockhart: Again, we'll come forward with more information over the next few months, but I need to get through this review process first. And then hopefully, midyear, we'll have more to share on this.
Raymond Kenneth Church: I'll just add Dale, on your balance sheet point, we have obviously run models on existing -- on the previous projections around the project with the plus/minus, I guess, contingent costs and timing. And we're already -- as you know, we're already slowing down the project, I guess, FID date. So it probably fits the balance sheet better, and it probably also supports -- could support if we go ahead, it could support the refi of some of the financing facilities. So it may actually be a little bit better for the balance sheet.
Dale Koenders: Yes. And then just final question. You booked Piracuca for the first time, just under 20 million barrels of oil. It was previously referenced could have been 500 million barrels of oil equivalent. Just sort of any comments on what assumptions have been made on that booking and how you think about that resource?
Carri Lockhart: Well, again, we're studying that. It's a new license, and we continue to study how this fits in with the broader hub potential concept. And that's one of the concepts that were under review. So we'll have more information in the coming months as this review concludes.
Operator: Your next question comes from Henry Meyer with Goldman Sachs.
Henry Meyer: Just the Who Dat on the riser leak, could you just share a bit more detail, please, on what scopes needed to repair that and if you see any opportunity to complete it earlier than the second half?
Carri Lockhart: Yes. Thanks, Henry. This is in early stages, and it's a very recent development. The operators preliminary plan at this stage is reinstating production. It involves actually 2 steps. The first would be to reroute wells within the next 1 or 2 months that restores the majority of the production with final riser repairs towards the end of the year. But keep in mind, we're still in the -- the operator LLOG is still in the assessment phase, and we'll know more here in I hope the coming weeks. But based on the preliminary information that we have, we still currently believe that we will be within guidance, albeit at the lower end, as I previously mentioned. And some of these losses are offset, of course, by the A1 sidetrack well that will be drilled as well as other activities and certainly contingencies that we already have factored into guidance.
Henry Meyer: Okay. And at Bauna, the flotel campaign has been underway for a few weeks, I think. Just any thoughts on how those initial repairs and inspections are comparing to the original expectations?
Carri Lockhart: So yes, you are correct. The flotel is currently on target. We do have detailed planning in place to manage the simultaneous operations, as you heard me state that we have potentially over 700 people at peak period going into that field working on this. Nothing out of the ordinary. Of course, it's early. And as we get into inspections, we'll have to continue to assess if there's any other remediation work that comes into play. We do have the contingency that we have an additional 2-month option for the flotel if needed. So I think we have the planning well in place. I think everything is looking as though it should based on our knowledge to date. But we still have an awful lot of work to do, including the turnaround, which is in conjunction with the transition that we're undertaking at this point. On the tail end, some of this work that we're doing is to ensure that the critical systems that we need in place to ensure production reliability and safety will be replaced and upgraded. So I'm very comfortable with the progress that's being made.
Operator: Your next question comes from Nik Burns with Jarden Australia.
Nik Burns: I had a couple of additional questions around the riser leak at Who Dat. First, can you confirm how much production is coming through the riser that's been impacted here? And secondly, probably a more general question. I guess, riser leak is relatively unusual. If you put your petroleum engineering hat on, Carri, you've been able to gain any confidence in the integrity works undertaken on the Who Dat infrastructure in recent times. I'm conscious there was an issue with the flash gas compressor a couple of years ago or 18 months ago, which also impacted production. And you're about -- as you mentioned, you're about to go through a large campaign to address production and integrity issues in Brazil. I'm just [indiscernible] just after your views on whether there may be a need for increased maintenance on Who Dat going forward as well?
Carri Lockhart: Yes. So thank you for those questions. A couple of things. Right now, the riser production, it's somewhere in the range of 30-ish percent. And of course, reinstatement is going to be within 2 different phases where the majority of it should be reinstated hopefully in the next few months and then the rest of the year-end. So again, I want to reinforce that we're not changing our guidance and that we still believe that we're within the lower end. In terms of putting my production engineering hat on and managing mid- and late-life assets, operators, including LLOG [indiscernible], we do have annual periodic shutdowns that we take turnarounds where we're constantly upgrading equipment, and we're constantly making sure that our critical defeat systems are in order. And this isn't going to change. Whether or not you are doing the right amount, I do believe that the operator is a very prudent operator, and we're a prudent JV, and we are doing the right amount. But some of these things are very hard to predict. You can't necessarily see when you're going to have failures a lot of times. And in the case of the riser, it's too early to even understand, at least based on inspection, we don't have the root cause analysis in hand to even understand what actually happened. So was this mechanical or was this more deterioration related. So let's table that. But am I confident that we have integrity on that kit? Yes. Is there always work to do? Yes. And this is just the nature of offshore.
Nik Burns: I appreciate the answer there, Carri. And my other question, just on Who Dat more broadly. Harbour Energy announced the completion of the acquisition of Who Dat operator, LLOG a couple of weeks ago. Have you had an opportunity to sit down with Harbour management to discuss their plans and intentions for Who Dat and how the change in ownership could impact or influence future development and investment strategy here? Is there any risk that they want to slow down investment in Who Dat to prioritize other assets within the LLOG portfolio? Or I guess, on the flip side, could -- is there a chance they might want to go harder on investment here?
Carri Lockhart: Thank you for that question. No, we engage with the management team all the time on LLOG, and that's not changing with the acquisition with Harbour Energy. I think whether or not they slow down or speed up, those are going to be questions that Harbour will have to answer at the corporate level. That's not just something that I can dictate. So I think it's early. Best I can tell from what I know on this year's plans, we are -- actually see from what we have in our plan a slight acceleration on the A1 sidetrack. So that gives me comfort that our plans are intact, and we're well engaged with the operator. And until there's a different opinion from Harbour, we're going to continue to march forward with what we have in our plans.
Operator: [Operator Instructions] Your next question comes from Gordon Ramsay with RBC Capital Markets.
Gordon Ramsay: Just had a question on Who Dat East, Carri. You said FID is subject to royalty -- a royalty relief decision. Is that kind of normal practice? Or is this something that is different in terms of moving forward with the project and there's some risk on that?
Carri Lockhart: Well, let me start by -- and I'm going to turn this over to Ray for a minute. But let me start with, yes, this is normal practice when you apply for royalty relief, and we are still waiting for the decision. And then once the decision comes in based on what those parameters are for the royalty relief, the JV will reconvene and then run our process through the final commerciality and have a decision at that point. But let me turn this over to Ray.
Raymond Kenneth Church: Gordon, just I'd only add that even the Who Dat field itself has royalty relief on it. So the standard rate is commonly reduced on fields. So we're -- it's not an unusual request to make this up to request it. And then if successful, it will be something similar to the royalties we see on Who Dat as well.
Gordon Ramsay: Okay. And my second question, I'm very intrigued about the post-salt tertiary oil play in the South Santos Basin. And you've mentioned that a farm-out process is underway. I fully recognize that you're not committed to a well with that acreage, but I would assume that whoever you do bring in, if you do, will end up drilling a well on the block. Is that a fair assumption? And can you give us a feel for the intended timing on that possibly?
Carri Lockhart: Yes. So we view this as being actually an exciting play. It is exploration and exploration is complex and sometimes it's a bit of an art form, but we're excited about the area, and we do believe that it has an active working petroleum system. So for the next phase, we do have a farm-down process, as I mentioned, that has just initiated. It's going to take quite some time for companies to come in and assess what we have because this is a very, very sizable acreage position that we have. And in terms of drilling a well, once you have a prospect and you've derisked it, you almost have to drill a well to prove it up because it is exploration, and it is a bit of science and a bit of art. But we don't intend to drill this 100%. And we look to have a more firmer date once we finish the data room and once we finish the geologic assessment that is ongoing to prove up any kind of volumetrics or to assess the volume metrics. Does that answer your question?
Gordon Ramsay: Got it. Sounds pretty exciting. And the ideal partner, again, one with strong technical skills and operating capability? Or are you looking for a financial partner? Can you just comment on that?
Carri Lockhart: No. Ultimately, it's always beneficial in these cases to have a partner that can offer technical skills because every company has their view and every company has quality engineers and geoscience staff and bringing those together just comes up with a more robust project. So ultimately, we would be looking for a partner that can contribute to the technology piece as well, especially not so much for drilling the well. It's more for if this is a discovery on what this potentially means given the scale of this area if it's play opening.
Gordon Ramsay: So early days, but looks pretty exciting to me.
Operator: That is all of our audio questions at the moment. I'll now hand over to Ann Diamant for any webcast questions.
Ann Diamant: Thank you. There's just one webcast question that's from Derek Becker, who's a shareholder. He asks, if the company's share price is so cheap that we do share buybacks, then why aren't current management showing confidence by also buying shares on market?
Carri Lockhart: I'll go ahead and answer this. Management directors do have shareholder requirements in the company. I can refer you to the rem report, but the prior CEO was a significant shareholder. I know Ray sitting here has shares. I just joined the company, and so been in largely a period of blackout. But rest assured, the management does have significant equity stake even via the performance rights. So some of this is personal decisions of individuals. But again, management and directors do have shareholding requirements.
Ann Diamant: Thank you. No further questions from the webcast.
Operator: Thank you. That does conclude our question-and-answer session today. I'll now hand back the conference to Ms. Lockhart.
Carri Lockhart: I want to thank you all for joining today's annual report with Karoon Energy and look forward to further engagements. Thank you.
Operator: That does conclude our conference for today. Thank you for participating. You may now disconnect.