Thank you for standing by, and welcome to the Karoon Energy Limited Transition Year 2023 Results. All participants are in a listen-only mode. There will be a presentation, followed by a question and answer session. If you wish to ask a question via the phones, you will need to press the star key, followed by the number one on your telephone keypad. If you wish to ask a question via the webcast, please enter it into the Ask a Question box and click Submit. I would now like to hand the conference over to Mr. Julian Fowles, CEO and Managing Director. Please go ahead. Thank you very much, Ashley. And good morning, everyone. Thank you for joining our Transition Year 2023 Results Webcast. My name is Julian Fowles, and I'm the CEO at Karoon, and I have with me this morning Ray Church, our CFO, and Ann Diamant, our Head of IR. Earlier this morning, we released our TY23 Annual Report and presentation to the market, which we're now going to talk through. Noting the disclaimers on slide two, I'll start on slide three. Karoon has changed its reporting cycle from a year-end - a June year-end to a December year-end, and the second half of calendar 2023 was the period where we made this transition. So throughout this presentation, you will hear us refer to TY 2023, which reflects the six-month period from 1 July 2023 to 31 December 2023. Future annual reporting will be on a calendar year basis. Slide four provides an overview of the key metrics underpinning our operating performance and how this translated into our strong financial outcomes. In FY 2023, we achieved production volumes of 5.5 million barrels of oil equivalent, a record for Karoon. This includes 11 days of production from the Who Dat assets. The higher production underpinned the 129% increase in Karoon's underlying net profit after tax compared to the prior comparable period. We finished the year with a robust balance sheet, with net debt of just over $100 million and gearing at 10%. As you can see on Slide five, we are well progressed in integrating our new asset into Karoon. We have completed the recent infill development program, with gross production from Who Dat still ramping up, currently at 38,500 barrels of oil equivalent per day. We're building capabilities in our new U.S. office in Houston and have already appointed experienced staff into the key commercial, trading, financial, and technical roles. Slide six summarizes our safety and environmental performance. Safe and reliable operations remains Karoon's highest priority, and pleasingly, we had no recordable injuries in the last 12 months. Environmental performance has also been good, with no significant spills reported in calendar year 2023. I'll come back to our operational performance a little later in the presentation, but now I'll hand over to Ray to talk in more detail about our financial results. Thank you, Julian, and good morning, everyone. I'll speak to the financial highlights in the next few slides and try not to cover things that Julian will cover in later slides. As Julian said, this is a six-month transition year, and we're using the first half of 2023 for comparison purposes. And just a reminder that we report in US dollars, so all figures I talk to today are in that currency. Slide eight shows that the business continues to deliver strong production and sales growth over a relatively fixed cost base. Underlying EBITDA has increased by 94% against the prior six months to $283 million. After interest, taxes, and capitalized operating leases, our operations increased cash generation by 128% against the prior period to $284 million. Meanwhile, investing cash flow, excluding M&A, was $8.4 million. During FY 2023, we funded the acquisition of Who Dat with a new debt package, a well-supported equity raising, and the drawdown of available cash. After completing the transaction, the company's balance sheet remains robust, with gearing at 10%, as Julian mentioned. Moving to slide nine, I'll highlight just a few items on the income statement. $146 million of additional revenues were driven by higher production in Baúna, where we lifted 10 cargoes, compared with eight liftings in the first half, and higher realized oil prices, which were driven by sentiment from the Middle East conflict and OPEC+ production cuts through the second half. Additionally, $7.7 million of revenue increase reflected the commencement of ship-to-ship transfers and liftings from the Neon port at Santos in Brazil. There was a corresponding increase in costs for the ship-to-ship transportation, which appears in production cost. Revenue increases were partially offset by variable costs, such as royalties and depreciation, both increasing with production, while royalties were also affected by crude price. Note that royalties in the prior half also included $14.6 million associated with temporary export tax, which ended on 13th of June. Reported production costs include AASB 16 non-cash items related to the FPSO operating lease accounting. On a pre-AASB 16 basis, production costs increased by about $16 million. Aside from roughly $8 million of ship-to-ship transport costs that I mentioned earlier that were incurred this year in this period. Other operating costs also increased by about $8 million, as TY23 reflected a full period of uninterrupted production, as the extended shutdown in April and May 2023 impacted prior period costs. Other than these impacts, operating costs were broadly flat between periods. Finance and interest costs included $3.4 million of RBL facility costs, mostly related to establishment and facility fees, $2.5 million of interest costs, and $3.2 million unwinding of discounts in the Baúna restoration provision. So underlying NPAT improved by $81.6 million, or 129% on the prior six months, and the reconciliation between underlying NPAT and EBITDA to our statutory result is in appendix 2 on slide 25. Moving on to cash flow on slide 10. As you can see, Karoon generated $276 million of free cash in the period, due to the relatively fixed operating cost base and light sustaining CapEx requirements. This was supplemented by $236 million dollars drawn from the new revolving debt facility and the equity issue to fund the $720 million acquisition of the Who Dat assets in the Gulf of Mexico. At 31 December 2023, we had $170 million of cash to fund the $86 million contingent payment to Petrobras, which was paid in January, and our annual income tax payment in the Q1, which is expected to be around $20 million. Slide 11 provides some color to our historical CapEx investments and guidance for CY 2024. Sustaining CapEx, including fully 30%-owned Who Dat floating production system and infrastructure, is expected to remain modest at $15-$17 million in 2024. Neon concept select costs and the G-2, G-4 development wells at Who Dat bring committed CapEx to $50-$57 million of capital expenditure in 2024. There is also up to $100-$120 million of contingent CapEx relating to potential appraisal and exploration wells in the U.S. Gulf of Mexico, yet to be approved by the joint venture partners. Julian will provide more detail on these opportunities shortly. Moving to debt on Slide 12. This provides a summary of our refinance debt facility established in November. This facility was supported by increased commitments from all our lenders, Macquarie, Deutsche, ING, and Shell. As we incorporate our Who Dat reserves into the borrowing base in coming weeks, it should allow us to access the additional $66 million of the undrawn limit, if required. Moving to the application of cash, Slide 13 should be familiar, and it reflects our priorities for capital allocation. Our highest priority will remain with ensuring safe, reliable, and sustainable business operations, and this includes meeting our emissions reduction commitments and funding our sustaining CapEx needs and existing commitments. This is followed by debt service and management of the balance sheet health. Cash available after these priorities will then be allocated on economic merit. The board will continue to regularly consider capital management in the context of this framework, which includes ranking potential value accretive, organic, and inorganic growth investments with capital returns to shareholders. Thank you, everyone. I'll hand back to Julian for update on our assets. That's great. Thank you, Ray. Turning now to slide number 15, I want to provide some commentary on the operating performance of Baúna. Following the successful intervention program and the drilling and hookup of the Patola wells, Baúna production peaked at over 40,000 barrels of oil a day in March 2023, prior to the six-week unplanned shutdown. Production returned in May, and we had strong production performance in the September quarter. The December quarter was unfortunately impacted by topsides issues on the FPSO related to the gas lift dehydration unit. While remediation of the topsides and downhole hydrate issues was completed on the twentieth of January 2024, a deeper mechanical blockage was identified in the SPS-88 well, which will require a well intervention to replace the gas lift valve. It's good to say that we are making good progress identifying an appropriate vessel to perform the intervention, and we have commenced discussions with the relevant regulatory authorities. We have assumed that this work will take place in Q4 2024, with SPS-88 back online before the end of the year. Now to Neon on slide 16, where our technical and commercial feasibility studies for the potential Neon development are almost complete. We're on track to go through our first decision gate, DG-1, in coming weeks. At this stage, we're evaluating two concepts: a standalone FPSO development or a subsea tieback. If we decide to progress into the next stage, concept select, the aim will be to identify the optimal development concept to take forward into the next stage, which will be FEED, subject, of course, to it passing our technical and commercial hurdles. We're also considering how we might bring the currently undrilled Neon West into the potential Neon Foundation project. Now turning to the U.S. on Slide 17, where the Who Dat asset is continuing to perform in line with our expectations in terms of high overall uptime. Over the last few months, the joint venture has completed the development campaign that began in Q3 2023. It involved installing a subsea pump, as well as bringing four wells online. Pleasingly, the last two remaining wells in the development campaign, G-2 and G-4, have recently come online, and the gross production rate is currently 38,500 barrels of oil equivalent per day, with further ramp-up expected when the second zone in G-2 is brought on stream and some production, which is taken offline for the tie-in of the G wells, is also brought back on. The joint venture is currently reviewing opportunities to debottleneck the FPS and improve FPS reliability further. We expect this work to be ongoing for several months. We'll provide an update when these studies are finalized. On Slide 18, you can see a schematic depicting the reservoir intervals in Who Dat, including the 4 wells that were part of the recent campaign. The drilling results came in line with expectations. However, as well as the deeper target, the G2 sidetrack well encountered a shallower hydrocarbon-bearing reservoir called the 4200 zone. The joint venture was required to, and it has now negotiated rights to produce from this zone, which will be commingled with the original target, 4600 zone, which is currently producing. Data from the recent wells will be incorporated into the dynamic model to optimize the development plan in order to drain the reservoirs efficiently. Slide 19 is the indicative Who Dat exploration appraisal development plan for 2024. At this stage, we are going through the joint venture approvals process for an appraisal to exploration well in Who Dat East, which we expect will spud in the Q2 of this calendar year. Who Dat East will target the upper Miocene and will be drilled as a potential future producer. This will likely be followed by two exploration wells, one in Who Dat South and the other in Who Dat West, subject to final JV approvals. Total volumes targeted by these three wells on a gross basis are on the order of 142 million BOE at the 2U level, with chance of success ranging from over 60% at Who Dat East to 25% in Who Dat South. Slide 20 shows our reserves and resources, which have been confirmed by NSAI and AGR. We now have 77.5 million BOEs of 2P reserves, of which 85% is oil and condensate. We have a significant portfolio of 2C contingent and 2U prospective resources, with over 100 million BOEs in each category, that we will look to de-risk in 2024 and in the coming years. Slide 21. Our approach to sustainability remains unchanged. We're continuing to pursue opportunities to remove emissions from our operations in the first instance, and then look to offset the rest, importantly, in projects where we can see social co-benefits. In FY 2023, we entered into a binding agreement with Brazilian firm Carbon ext to purchase 340,000 verified carbon units over five years from the Hiwi REDD+ project. Through our activities, we contributed some $84 million to the Brazilian and Australian economies in FY 2023. Full details of our ESG goals and our progress in achieving those is summarized in our FY 2023 sustainability report, which was released alongside our other announcements to the market this morning. Slide 22 outlines our guidance for CY 2024, which is unchanged from what was provided to the market last month. We're expecting production for the full year of 11.2-13.5 million barrels. Our unit production cost is expected to be between $10.5-$15 per BOE, which is largely dependent on where production ends up, with the majority of our costs fixed. This compares to $11 per BOE in FY 2023. Our CapEx for FY, for 2024, sorry, is expected to be $50-$57 million. Neon will attract some capital as we progress the project through the concept evaluation stage, assuming success in DG-1. The $100 million-$120 million of contingent capital spend in Who Dat is related to the 3 exploration appraisal wells that we flagged at the time of the acquisition. This is a little higher than our expectations at that time, due to additional costs related to a significantly longer well design at Who Dat East, where the well will target 5 separate potential reservoir zones rather than the 2 zones previously contemplated. In addition, we have included a well containment fee, which is in some ways a type of insurance, and that's currently estimated at $8 million, and that was not included in the original estimates. A summary of FY 2023 is provided on Slide 23, covering the items we've discussed in this presentation. Karoon remains committed to safe and reliable operations as our first priority. We are in an enviable position as a midcap oil and gas producer, with well over 35,000 BOEs per day of net working interest production in two of the most prolific and prospective hydrocarbon basins in the world, a pipeline of new organic growth opportunities, and a robust balance sheet with low net debt. The strong cash flows from our two assets should provide Karoon balance sheet capacity to evaluate growth opportunities at the right time and potential returns to shareholders.... Finally, I would like to thank our team at Karoon and our contractor partners for their hard work and dedication in delivering our TY23 results and the work that continues in Karoon's transformation and growth. I should like to thank our shareholders for your continued support of the company as we enter this exciting next phase of production delivery for Karoon. Thank you for your attention, and I'll now hand back to Ashley for any questions. Thank you. If you wish to ask a question via the phones, you will need to press the star key, followed by the number one on your telephone keypad. If you wish to ask a question via the webcast, please type your question into the Ask a Question box. Your first question comes from Dale Koenders with Barrenjoey. Please go ahead. Morning all. Firstly, I just wanted to know, Julian, how are you thinking about in the success case for these three exploration appraisal wells in the Gulf of Mexico, what would be the forward case, in terms of, you know, number of wells incrementally drilled? Are these being drilled as production wells? And what needs to happen in the timing effectively to bring production on if you find reserves? Yeah, look, those are great, great questions, Dale. I, I don't have a firm joint venture approved plans at the moment for what will happen in the success case. We'll tackle those, those questions, once we have the well results. We do have some notional ideas of what might happen. All three of the exploration targets that we have are within tieback distance. So we'd be confident that we can bring them back into the FPS. And in the base case scenarios, we believe that there is certainly plenty of capacity on the FPS to be able to bring those, the additional production in. However, we will require to go through an FID process effectively in order to approve joint venture drilling of further wells, the pipelines that would be involved, and obviously, there will be regulator approvals involved with those as well. So I hesitate to put a time frame on exactly when we would expect to see the first production from these areas. As soon as we have that, as soon as we have something that's been discussed in more detail at the joint venture, we'll be in a good position to bring that to the market. Is there the potential to reuse the wells, though, Julian, as production well? So the well that we're drilling in Who Dat East is being drilled as a keeper. Who Dat South and Who Dat West, I suspect will be more pure exploration wells without a plan to drill those as keepers. And there's a good reason for that. They're slightly higher risk than Who Dat East. Who Dat East is really a very low risk appraisal well with some exploration targets as well, while the other wells are more out-and-out exploration, and generally, it doesn't pass the economic hurdle to try and drill those as keepers. We will continue, though, to discuss that in the joint venture, but the Who Dat East well is being drilled as a potential keeper. Obviously, it depends on the well results. Thanks, thanks. And then maybe just a final question. I don't know if, Julian, you want to take it or Ray, but as you look forward, there's a lot of exciting growth opportunity in the portfolio. How, how do you view what is the right sort of long-term level of debt or gearing or, or leverage when you think about where's, when's the potential to return capital to shareholders? I'll say a word or two about that, Dale, to start with, and then I'll hand it to Ray to get down into the meat of the question. I think it's important to recognize that Karoon is in many ways in a unique position from a debt perspective, in that at least currently, the asset we have just purchased is unlevered. We will bring it into the borrowing base. But what that means is that we're in a really strong position to be able to look at potential future acquisitions, for example, without necessarily needing to lever up those new assets that we would bring in. That's quite an unusual position for an oil and gas company. I'll hand over to Ray to answer the question properly. Yeah, Dale, thank you. Look, we have... I have a couple of perspectives on it. One is that our operating costs are lower relative to our peer group, so that gives us a lot of opportunity for minimal leverage. So, so that cash generation, as Julian talks about, as a result of low operating costs, gives us quite a lot of power for investment. Then, as you know, the balance sheet's relatively lightly geared. So given that we're an upstream production company, when we invest, we'd expect to invest and then pretty quickly see a return. So there isn't a maintained gearing on the balance sheet that we have as, I guess, a target. But there is, I guess, some high water marks that we'd like to keep. We'd like to keep our leverage at something up to 1x EBITDA, maybe 1.5x at a stretch. But I just don't think we've got many things out there that could get us there, given the operating costs. Does that make sense? Thank you for that, and I hope you're encouraged by Julian's comment of more M&A. That sounds exciting. At the moment, Dale, we're super focused, obviously, on ensuring the integration of Who Dat goes well. It's been fantastic interaction so far in the joint venture. I anticipate that that will continue. That's really our very strong focus at the moment, so I don't want to move the team's focus away from that until the right time. Your next question comes from Adrian Prendergast with Morgans Financial. Please go ahead. Yeah, well done on a good set of numbers, guys. Just a question on the FPS. Just interested in the debottlenecking work that is starting to be done by the joint venture. Is it more about creating room for future growth, or is it simply unlocking greater efficiencies? It's a bit of both at the moment, Adrian. That's a great question. It's exactly the question we've been discussing in the joint venture itself. The performance of the FPS has been pretty good. I think that there were some hiccups during November and December that we want to iron out. And we're working with the operator to understand how we can best do that. But yeah, certainly, we see potential should we get you know, upside surprises, for example, in Who Dat East, in Who Dat South, or even in Who Dat West. Then you know, we'll want to be able to bring that into the FPS as efficiently as possible. With an existing facility there, I want to make sure we can absolutely maximize the utilization of that facility. So we have a bit of time to do that work, given those wells are only being drilled this year, and then there will obviously be a planning period and all the rest of it. But yes, that work is ongoing at the moment in terms of opportunities to get higher performance and potentially more consistent performance. I mean, the performance has been very good, of course, at the FPS, but I think we can do better. Yep, perfect. And just a question on the joint venture itself and LLOG, and obviously early in that relationship, but going well from an active field perspective. But just in terms of long-term, when you talk about organic and inorganic and future growth, obviously, you're accumulating a lot of cash quickly in this business. And yeah, is it something where you see them, you know, commonly or regularly turning over bits of equity in different fields and maybe it becomes, you know, a long sort of multi-field sort of relationship? Or is it, there's plenty in here for a company of Karoon's size, and you probably just stay within Who Dat in this relationship? Yeah, so certainly the relationship is developing. As I said, I think we've had a great first few months in that relationship. I was down in Louisiana a couple of weeks ago, sat with the whole management team there. We spoke about Karoon's strategy, we spoke about LLOG's strategy as well. And yeah, I got to know quite a few of that team. Interestingly, their senior team have all been with the company for 25+ years in LLOG, so they're super experienced and know exactly what they're doing. Look, in terms of opportunities, without a doubt, LLOG likes to acquire and build and develop new assets, and they do turn over parts of their portfolio. They sort of don't like to grow, or they don't want to grow too large. They've been in business for 45 years. They do about 70,000 BOEs a day. I think they don't want to be much larger than that. So their owner has always been driving them to you know, if they're developing something new, to sell down something from something old. But they also they like to operate, and they like to have positions that are sort of between 30%-50% in their assets. It's a great question because it has other implications for Karoon. You know, should we look to be, for example, an operator if we're to look at another M&A transaction? You know, I think ultimately, in Karoon, we do like to operate. We've got a very strong operating team in Brazil. And I got to say, they're itching to get their hands on something in the Gulf of Mexico now we've entered that jurisdiction. So it's still lots of questions to ask around there, Adrian. We're currently building, I think, a very nice desktop competitive picture of what's happening in the Gulf of Mexico, who's doing what, where, and why. And I think that will help form the basis for future evaluations of opportunities in the Gulf of Mexico. But as I said before, we are super focused over this period, and probably for a few more months at least, on ensuring that integration of the Who Dat asset goes really well, and that we're getting into the right relationship to and fro with the joint venture partners. That's great, Caleb. Thanks, Julian, and well done again. Thank you. Your next question comes from Gordon Ramsay with RBC Capital Markets. Please go ahead. Well, thank you very much. Julian, I just want to focus on Who Dat. I just got a couple questions. The G-2, ST-2, and G-4 well came on stream this month. You said in the release that negotiations to acquire the shallower zone rights delayed the production ramp up. My understanding was prior guidance had been that they would IP at around 9,000-12,000 barrels of oil equivalent per day, gross, prior to decline. Is that still your expectation? And can you comment on what production is right now from those two wells? I haven't got on my fingertips exactly the production from those wells or the two separate zones in G-2, I'm afraid at the moment, Gordon. The number you're quoting sounds right. I'd have to go back and confirm that, but it does sound right. The G4 came in on expectations, and G-2, as I said, had that additional zone, which, I think once we commingle the two zones, which we now have approval for from the regulator, once we do that, we should see higher than the original perceived potential at the G-2 well. Certainly, that's our expectation. But as you know, these things, like, you know, they're often. It's often not just 1 + 1 = 2. So we, although we've tested the production potential in both those zones in the G-2, we haven't yet brought them, brought them in together, and I expect that to take probably a number of weeks before we're in a position to do that. We need to get the pressures stabilized and equalized in order to do that, so you don't end up, obviously, with a crossflow situation. And before I ask the second question, so your net revenue interest on that shallower zone is the same, then? You've negotiated the same level of interest, equity? Look, the commercial outcome of the negotiation is somewhat confidential. But the joint venture has retained an interest in something above 80% of that zone, and we have 30% of that. And then if you take off the relevant royalties, you'll get to our net revenue interest. Okay, and the second question just relates to the CapEx guidance. It sounds like you're clearly going to spend more than $50-$57 million, assuming joint venture approval. You've given guidance of $100-$120 million to continue to spend on the three appraisal wells. Should we assume it'll be at the higher end of that range, just because you've talked about Who Dat now drilling a longer well with five potential reservoir zones, and also you mentioned containment fees of $8 million, that you didn't anticipate before, so does $120 million sound like a reasonable figure now? Look, I would always go a little conservative on this, Gordon. It's drilling wells that are exploration appraisal that they have more levels of uncertainty with them than development wells, obviously. But I think the costing we put in there is pretty good. If you know, if you're in the middle of that range, I think I would be reasonably comfortable with that. We've got, I think, a pretty good handle on what Who Dat East will cost. Who Dat South, we're going through the discussions at the moment, and Who Dat West, we've just seen very preliminary numbers for that. So, but I don't expect West and South to change that range in any way. I think the range is good. So... But yeah, look, go on the conservative side. I'm also happy with that. All right, just while I got you, last one, just timing then. What are we looking at best, kind of, timing at the moment? I know you're saying- So Who Dat, I think there's a slide in the, let me just see if I can get to it, so I don't lead you astray. Who Dat East, I think we're hoping to spot in April. And Who Dat South will be in probably in June. I'm hoping that doesn't slip into July. And then Who Dat West will be probably in the second part of the Q3, and it'll probably go into the Q4. It depends on activities. There's two rigs that will do these, so it's not done with a single rig. There's two different rigs that will do this campaign. One of them is already on long-term contract with LLOG. It's been on contract for 10 years. It's currently off doing something else at the moment, so it depends on the finalization of that activity before it comes across. The same with the second rig, it depends on the finalization of its current activities. Got it. Thank you very much, Julian. That's right. Thanks, Gordon. Your next question comes from Adam Martin with E&P. Please go ahead. Yeah, morning, Julian and Ray. Just first question, just around those three sort of appraisal exploration wells. Are they sort of all independent? I mean, it sounds like the first one, pretty decent probability of success. Just wondering if there was problems, does that, you know, on a more bear case, would that, would that impact the other two, or are they all sort of independent, and they're all gonna basically happen? I'll give you a flippant answer to start with, Adam. I really wish they were dependent, 'cause that would mean that they were all joined up, and there's about 60 km between them. So that would be great news. But no, they'll more seriously, they are independent of each other. Who Dat East sits about 25-30 km to the east. Who Dat South is about 5-10 km to the south of the FPS. And Who Dat West is about half the distance that Who Dat East is, but obviously on the western side. So there's quite a big distance between them, and each one of them will be independent. They're all targeting proven Miocene plays. They all have very good amplitude support. Yeah, you know, I think we have a good chance with all of them. Obviously, that's why we're doing that. I I think Who Dat East, you're right, is drilling at, you know, something that's already discovered. So, you know, I think... Yeah, the question is, you know, will it find the right extension of that discovery, and will it find some additional zones? So, yeah. Yep, perfect. Okay, and then just second question, just the intervention vessel back on Baúna. What's the critical path there to get that done by Q4? Is it the regulatory piece of work, or is it the vessel? Where's the risk that this doesn't happen in the Q4? Please. Yeah, so you picked up the two elements, right? Obviously, the vessel. We do need to identify the right vessel and negotiate the timing and the terms. There are some suitable vessels available in Brazil. And the question is, when will those vessels—what's the timing of their availability? Obviously, they're with other operators, so that requires some discussions. And I mean, I've got to say that the groups, the companies that we're talking to, are all that, you know, they all seem comfortable that Karoon, at some stage during 2024, could take on the units that they have and go off and do our well. So I think from that point of view, the timing is probably okay. A little more uncertain is regulatory timing. IBAMA, currently, some aspects of the Environmental Agency, IBAMA, they've got quite a lot of backlog of work to do for Petrobras and other operators. This goes through a slightly different route in the agency to conventional drilling campaigns. And obviously, for Baúna, we already have a whole host of environmental approvals for previous work that's been done there. So there's quite a large range of uncertainty, depending on what IBAMA requires us to do for them and to see. That probably is the biggest uncertainty that we've got at the moment. We need to identify the vessel. We need to be confident that that's the right one. Then we can submit all the documents about that vessel to IBAMA. We're in negotiations with them over the vessels that we've been looking at, and so that's already kicked off. But I can't promise that it will be any sooner than we've already outlined to the market. Is it likely to be later? I'm really quite confident it will be done in 2024. So, yeah, hopefully that answers your questions about that. Yeah, no, it's good. And then just final quick question, just on the capital management. Will the company get to a point where you might put some targets down, like, you know, percentage of free cash or, you know, dividend as a percentage of profit, for example? Or are you gonna keep it pretty sort of broad the next couple of years while you're sort of thinking about other acquisitions or other growth opportunities? So I think we've achieved with the acquisition of Who Dat, I think we've achieved quite a substantial amount of de-risking from a portfolio perspective. We're not so vulnerable, should one asset stop working for a period, for example. And obviously, in April and May last year, when we were shut down at Baúna, you know, that hurt us quite substantially. We're very fortunate, and of course, that we had seen tremendously strong cash flow from that asset in the prior period. So we were very robust at that stage. We're obviously much more robust now with two assets, and two really good assets. The board hasn't really discussed setting down a table of metrics, if you like. I don't think that that's something we're likely to address in the immediate term. Perhaps there's a further acquisition the board would like to see to give us further portfolio breadth and depth before they would be prepared to do that. And we've already heard from Ray about, you know, some of the potential areas we might go with, with sort of net debt from a, you know, in terms of multiples. So as I said, we're still, I think, growing the portfolio at a rate that we could set a bunch of metrics out there, and we'd probably have to revise them after 12 or 18 months. So I expect we'll hang off from that for a little while yet. All right. No, that makes sense. Thank you. That's all for me. No problem. Your next question comes from Sarah Kerr with Morgan Stanley. Please go ahead. Hi, Julian and Ray. Congratulations on the results. Can I just start with production rates for Baúna and Who Dat? Are you still seeing 15% per annum decline at Baúna? And post the infill drilling, at Who Dat, when do you anticipate, peak production, and what kind of decline rate, do you think you'll see, once that kind of comes off? Yeah, so they're really interesting questions. For Baúna, we see absolutely no change to what we've already said to the market in terms of how we anticipate Baúna production overall declining. And on a daily basis, you'll see numbers that go up and down, of course, and you know, that obviously gets published at the ANP website with a bit of a lag. You'll see that stuff, you know, bounce up and down a little bit just with natural operations. So yeah, so I don't see anything different from a reservoir point of view. Our big focus at Baúna is to ensure continued integrity, which obviously plays to both safety and production on our FPSO. And together with the operator there, Altera Ocyan we're working really well with them now to ensure that that continues. Obviously, we had some tough discussions last April and May when we were shut down. And yeah, it's great to see that that relationship is really back on track. So I think that's where we'll be focusing to ensure that through 2024, 2025, 2026, we have near term to medium term the best integrity we can, and then looking to the longer term on that FPSO, we're likely to put in some form of life extension program that we've sort of touched upon with the market previously. In terms of Who Dat, it's much more complex at Who Dat, because if you go to that slide that shows the sort of schematic cross-section... And don't take that slide too literally. I I think it's slide 18. It shows all the wells. It shows a bunch of green and red colors of obviously gas and oil. And it shows where the wells are completed. Of course, the reservoirs don't look anything like that, really. And the configuration of the wells is a little bit different. But you can imagine with that many different zones and that many different wells, it's mapping the individual production performance on a zone-by-zone, well-by-well basis makes the overall picture look reasonably complicated. What I would say is, we've seen Who Dat now ramp up from where it was about twelve months ago, where I think it sat about maybe 20-25,000 BOE a day, to where it is today, at close to 40, and with further ramp-up to happen. I expect to see, probably over the next, 6-8 weeks, that we will, see the 4,200 and 4,600 zones achieve pressures that, that will allow, them to start being co-mingled. Yeah. So I think that'll be a good really positive indication. Also, there's some other elements of Who Dat that you'll see come back on stream. There, there's some parts of the production that we've we've ramped down in order to bring in the new production to make sure that we keep things stable and safe and reliable. We don't want to... Or the operator doesn't want to stress too many parts of the facility at once. So yeah, as I said, in a couple of months, I expect we will have seen that ramp up to where the full potential can get us. Then it'll be a question of the two elements, debottlenecking on the FPS, so that we've got the maximum capacity for future production to come in. Then obviously ensuring that we get the best reservoir management, which will involve, obviously, rebuilding those subsurface models, the 3D models, that allow us to map what that looks like. Great, that all makes sense. And just quickly, moving to Neon. When would you potentially drill Neon West? And would it be possible to complete it as a producer? And maybe just a side, quick side question for Ray: What funding options do you have for a Neon standalone FPSO or tieback development? Let me tackle the first bit while Ray contemplates the second part. So for the first part... Look, we haven't yet got through the DG-1 decision gate. Neon West, without a doubt, is something that we would see as being a low risk prospective resource. That doesn't mean that it's a slam dunk to go and drill a development well, first off in there, for example. But there, there's a number of potential options that I know the team has been looking at. One of those, for example, could be to drill an exploration well that you could potentially come back and reenter and sidetrack in the future for a development of that area. The question I think we need to address is, will de-risking Neon West provide us with any additional information to move forward with confidence into the FEED and obviously to FID ultimately? You know, are the thresholds that will get us over in terms of volumes, production rates and obviously feeding into the economics. So that's work that is ongoing and that will continue should we get through the DG-1 gate. And yeah, so I can't really give you an answer to that at the moment, I'm afraid to. I'll hand over to Ray, and- Just to add a few things here. I wanna talk to the, you know, the staging and the timing and the economic hurdles that we'll have to make competing with other investments. But assuming we get there, we probably have a few levers. We have, obviously, cash build-up. We have a farm out or farm in, depending on who you are. So we have a farm out option that Julian's talked about in the past, that- Yeah ... would materially carry a lot of our spend. And then, of course, by then, depending on the shape of our assets, there's new debt facilities that we could put in place. You know, there's a few years between here and I guess, significant investment in that. ... in that project. So, depending on what we do with organic and non-organic in the meantime, potential returns to shareholders, I think they're, you know, that it's probable that we would look to a different debt facility in the meantime. So, that's probably the main levers we'd have to pull. Great. Thanks so much, and congratulations on the results. Thanks, Sarah. Your next question comes from James Byrne with Citi. Please go ahead. Right. Good morning. Good cash results. So pretty extraordinary stock's trading a bit over 2x operating cash flow. And look, obviously, when I pick up the phones and talk to investors, there's no doubt that it screens cheaply. Where people, I think, get a little bit hung up is about buying the business that has a declining production profile, you know, from a reserve life perspective. Perhaps to help placate some of those fears, do you wanna talk to what you think Karoon's gonna look like in five or 10 years, and the kind of guardrails that you have in place that ensure that any volume growth indeed comes with value growth as well? Yeah, look, that's obviously something that we spend quite a bit of time contemplating, James. And one of the attractions of the Who Dat asset was that it has a long-term production sustainability profile, if you like. Obviously, with these three things we're drilling at the moment or hoping that we'll drill this year, you know, they bring quite a bit of potential into the facility and can certainly help sustain production longer term. What we see, the Who Dat asset producing well into the 2030s and, I'm even hopeful it will go longer than that. I think in terms of where we look at targeting the company over a long time period, such as five years, that's gonna be the topic of a strategic review that we will undertake this year. So, probably coming into the third or maybe early Q4, we'll probably be in a position at that stage to talk to the market about that. At this moment, though, we're super focused on where the strategy is taking us, which has always been in the near term to achieve rates of around about 50,000 BOEs a day, you know, within that sort of four-year period or so from when we bought the Baúna asset. And hence, that's been built around the intervention in Patola programs, and then, obviously more recently, the Who Dat program. So we're getting, you know, not far off achieving that in terms of a goal. So it's the right time, I think, to undertake that strategic review. But look, I mean, we see a lot of opportunities in the market, for assets which have longer-term growth profiles, longer-term production sustaining profiles than the Baúna asset. The Baúna asset was a fantastic thing for us to buy because it was priced at a very attractive acquisition. We knew it had very attractive potential for increasing production in the near term, with some cost attached to that, of course, but we had a lot of confidence around how to do that. But we recognized that it would be a declining asset, and potentially by the early 2030s, if we're not able to extend the FPSO as long as we would like, you know, that asset could be done by 2032, 2033 or so. So yeah, we're certainly focused on getting things going longer term and getting a broader asset base, I think, is what will get us there. Broader asset base with further potential. You would have seen in December, we moved to purchase two deepwater exploration blocks in the Southern Santos Basin close to where we currently operate. That's part of that longer-term potential story. And after we've signed those blocks, which we think will be a little later this year, we'll be in a position to talk a bit more about what we think we can do with those blocks. But yeah, I mean, that's really just an indication of how we're looking at things. And yeah, absolutely looking to get a sustaining production profile, which will have that longer-term confidence and value for shareholders. Yeah, I've got to - thanks, thanks, Julian. I've got to say, though, like, I'm probably a bit surprised about the talk on this call from yourself and from the line of questioning around the next deal, right? Because you've only just completed the acquisition of Who Dat, and, you know, I accept what you said a moment ago, in response to Dale's question about, you know, the focus of the organization still on integrating that. But, I mean, personally, I probably feel pretty uncomfortable if you were utilizing your dry powder too soon. So maybe could you just tell us about the human resourcing within the organization, your capacity to actually bolt on more assets in the next year or two? Yeah, look, it's a good point, and obviously, it's something that gets discussed at the board in terms of our capacities and capabilities. But what you got to remember is that we have a very strong operating team in Brazil, which has been operating the Baúna asset now for a number of years, and is continuing to get the best out of that asset, and to understand at a very detailed level what that asset looks like. Separate to that, we have a largely Melbourne-supported M&A team, of which there are also some elements in Brazil, of course. And that team is currently involved in the integration work with Who Dat. But Who Dat is a non-operated asset, so, you know, once we have the systems and the processes in place for, you know, ensuring we're getting the best marketing and sales for our crude and for our gas, ensuring that we've got the right accounting processes in place, and that we have the right forums and people to challenge and debate with the operator, I think that team will have time and capacity to look at further assets. And, you know, that's not necessarily what will happen in the next few months, but I think once we move into certainly that strategic review period, I think that there will be certainly capacity that comes free at that stage. Got it. Yes, very much looking forward to this strategic review. Just to finish up, quick one for Ray. As I mentioned earlier, good operating cash result versus market expectations. And perhaps I need to dig into the numbers a bit more, but easier if I ask you: Was there anything, timing-wise with regards to operating cash flow we ought to be aware of, whether it's timing of cargoes or tax payments or contingent payments that might have inflated that number, at all? Thanks. Good question. There's only one item, and it goes the other way. We were ship-to-ship offloading right on balance date, so we have about 500,000, I think it's about 400,000 barrels in inventory that actually sold in the first week of January. So that was a split cargo, and that revenue didn't come in. The cash really was attributed to that half period. So there's a little bit of about 400,000 barrels of inventory there that you know realistically should have shifted. But because we're doing ship-to-ship, you know we can split production and off takes right now, and that happened to span that those couple of days. So that's the only thing that really, I think you would say attributes to this half rather than the next one. Good to know. Thank you. Appreciate, appreciate it. Welcome. Your next question comes from Nik Burns with Jarden Australia. Please go ahead. Oh, thanks, Julian and Ray. Actually, I might just follow on from James's question around the operating cash flow, because I was, again, surprised with that, with the numbers coming through there. And then particularly on tax, you only paid $19.5 million of tax in the last six months. And on my numbers, I was expecting, you know, to have you paying a lot more tax than that, and therefore, at least was anticipating a large current tax liability on the balance sheet, but it only showed $16.8 million. Is that $16.8 million all that's owing from a tax perspective over from your earnings from the past 12 months, or is there more to come? I was really hoping someone would ask this question. So we have the... So we will have, you know, it's like a provisional tax system. So you pay on an estimate basis during the period and then true up in the Q1. So there's a, there's around $20 million payable for this half, well, actually for the financial year, for the calendar year, that will be paid in March. So that's, that's a cash flow that's attributed to that period. But also, there is a one-time tax incentive that's at a state level in Brazil. I'm going to oversimplify, but we developed Patola, and we receive a tax rebate or a tax offset for costs, the capital costs invested in Patola, that are incentives, I suppose, in the tax system for development of new assets. So there's the delta that you're chasing, I think, is that credit that we actually won't have to pay. It's a one-time benefit. So you can see it in the effective tax rate, that you can see that it's down to, I think, about 32%. Well, the tax expense is around 32%, and in the past, we'd be normally 35% with some change. So the delta is mainly that item, that incentive. Got it. Thanks for that, Ray. And just another question on Who Dat. Just on your reserve statement, the split between developed and undeveloped reserves looks like just over half of the 2P reserves, and Who Dat classified as developed. A couple of questions around this. I'm just wondering if the reserves targeted by the G-2 and G-4 wells were classified as developed or undeveloped at 31 December. And beyond that, have you had an opportunity to engage with the operator around their plans to develop the remaining undeveloped reserves? Any insights you can give us around what that would entail, more wells, artificial lift, something else, timing? Thank you. Yeah, good. I'll take that one on, Nick. So, what I would say is some of the stuff that was targeted by those wells, those four recent wells was undeveloped. Some of it was actually completely new, the 4200 zone in G-2, for example. And some of it was already classified as developed reserve. A good example also being the in G-2 the 4600 zone. So there was a bit of a mix in there. We haven't yet sat down with the operator in detail to look at the long-term infill plan for Who Dat. I got a bit of an overview of it a couple of weeks ago, of some preliminary thoughts when I was over there. And yeah, I was obviously very, very encouraged by that in terms of the potential to sustain our rates. We'll end up with a sawtooth pattern, right, for Who Dat. Production will decline one way or another, and then, you know, we'll tie in some new infill or potentially, you know, so some of the... If these new wells prove up new volumes, we can tie those in, too. So, yeah, look, I think that there's a bit of a mix of developed and undeveloped in those recent wells. Over the next 6-9 months, I expect we will work with the operator on the medium-term infill program for the asset. Got it. Thanks for that. Just one more question, more modeling, I guess. Last quarter's report included 11 days contribution from Who Dat, and in that, you commingled oil with condensate and gas with gas liquids. I guess, as we look ahead, will you split this, those four product streams out? And can you just remind us what price realizations relative to various benchmarks we should be modeling for, for, for those four streams? Thank you. Sure. So we probably will, we'll avoid splitting out items so that we just get it to low granularity. But our crude at in the U.S. trades to the Mars Pipeline index, which are very similar to WTI. So it has a close connection to WTI. So that's probably the reference point for the crude. The gas is Henry Hub pricing, which is a bit more volatile. So they're the two indexes that I'd suggest you tie to. The condensate goes out with the oil, and the NGLs obviously go with the gas. And we get, you know, we get paid for NGLs, but it's a pretty small- Mm-hmm. Small contribution. I don't know if that's a good question. Yeah. I'm just wondering if that would result in a premium to Henry Hub, including the gas liquids, in with the gas stream? Sure. Well, I can probably tackle that. That's... Yeah, we'll, we have seen historically, a modest premium on Henry Hub, especially the last few months. But, you know, that's on the order of, you know, perhaps $0.10. You know, and obviously frequently lower than that. The Mars index tends to bounce up and down, up, above and below WTI, so the oil and condensate can be higher or lower. At the moment, I believe it's a little higher. We also have a quality part to our crude because we're a little better quality than the general Mars index. And so that brings us, at least recently, has brought our pricing up above WTI. But again, we're only talking cents, tens of cents, you know, not, not, not $5 or something. I just want to add. So you're right, it's a small premium, WTI on the crude, and then typically a small premium to Henry Hub or NYMEX on the gas. But the pricing that you'll see in our results is net of royalties, just to be clear. Yep, and transportation costs, et cetera, et cetera. You'll, you know, you'll... Obviously, it takes money to transport our oil and our gas to the ultimate buyer, and we pay for that transportation. That's helpful. Thanks, guys. Cheers. Yep. The next question comes from Henry Meyer with Goldman Sachs. Please go ahead. Morning, Julian and Ray. Thanks for the updates. It's been a pretty long call, so I might try and keep this one punchy. Just on the strategic, strategic review you've mentioned. Through the call, you've talked about more on M&A, potential returns, explorations creeping back into the portfolio. You've got a bit of a product shift going into gas. Could you expand a bit on what outcomes you're working towards in the review? And perhaps what's driven the requirement to complete one, whether it's in your chair or observations through M&A or otherwise? Yeah. Henry, I'd love to go into detail about what we're doing, but we haven't yet scoped out the terms of reference for it. We're sort of about to do that, but once we've got through this latest round of engagements. So I'll be able to talk a bit more about that, you know, probably in terms of the scope, at, you know, at the next opportunity. But yeah, that, it, it's really... It's on the agenda for what we have to do this year. It's gonna be, I think, a pretty important piece of work. Either to establish, you know, that we are gonna continue with, continue with the knitting, if I can put it that way, or, you know, maybe we'll add an additional stream, or we'll add some additional opportunity evaluation work into that longer term. But yeah, at the moment, I haven't, I literally haven't got the sort of debatable material to be able to bring to you, Henry. Okay. All right. Thanks, Julian. And, and another quick one. Back on Neon, the commentary is fairly cautionary. Could you talk to a bit about what the board will be assessing in this review next month? What's what the skew of risk is in some of the concepts? Is it- is there actually a risk that you wouldn't move into concepts select for, for Neon? Look, I can't obviously predict what the board will decide. I think from my perspective, I think there's a very strong chance that we will move forward into the next phase, and that's because I think we see the feasibility of the project, you know, being reasonably robust at the mid-case volume level. I think the key questions that we'll need to address will be, how do we mitigate downside outcomes? And those downside outcomes are twofold, largely to do with the overall recoverable volume. And Sarah already asked a little bit about Neon West. Perhaps that's a way to mitigate that, if that is a key concern. But obviously, that's uncertain at the moment. And I think the second part is around what the production rates look like. Obviously, these things tend to be more profitable, the harder you can produce them. But that depends on, number one, how much CapEx you spend, how many wells you put in the ground, what's the configuration of the wells? But even more importantly, what really is the producibility of the reservoirs throughout this particular field? We have a test, obviously, from Echidna-1, which was pushing towards 5,000 barrels a day. It was very positive. But you know, I can imagine that the board will be asking questions around subsurface outcomes. They'll also, of course, be interested in what's our projections of future CapEx profiles. At the moment, there's still quite a bit of uncertainty around that. And what do we see in terms of, if we were to go standalone, what do we see in terms of the outlook for potential facilities that we could use on the field? So, yeah, still heaps of unknowns and, yeah, the key question at the moment is, what's the level of feasibility? And, you know, it would be a relatively modest CapEx going through 2024, should we take the decision to move forward in DG-1. Great. Thanks, Julian. That's, that's great detail. Yep. There are no further phone questions at this time. I'll now hand back to Ms. Ann Diamant to address any web written questions. Thank you, Ashley, for that. We have had a number of questions through the web. I think a number of them have already been answered, so I'll just focus on the ones which are still outstanding. Firstly, from Andrew Mouchacca at Flinders Partners. Hi, team. Can you provide an update on appointing an in-country general manager in Brazil? And maybe a comment on the expectation for what a team in the US will look like. Yeah, let me address that first of all. The recruitment for the country manager role in Brazil is going very well. We have some very strong candidates. And yeah, I would expect that over the next few weeks, we will be in a position to make an offer, and hopefully, if that offer is accepted, we can then move forward to tell the market about that. But we've got very strong candidates. It's been a process that has really looked at the depth and capability of Brazilian talent, and also international talent, to be honest, for a role like this. Yeah, I've been very impressed with the candidates that we've seen so far. Yeah, that is going well. In terms of the team in the US, we've set up an office in Houston. We've actually got a more permanent office that we're moving that team to. It's in downtown Houston. We have about five or six people there at the moment that consists of a very small team that does scheduling, commercial, and marketing. From the end of March onwards, we will be doing all of our own marketing of the liquids and the gas from Who Dat, and we're very well positioned to start that. The team we've brought in very experienced operators in that regard. We also have someone to do the finance for us, and to make sure that all the numbers add up properly. It's obviously a lot more than that. I'm not trying to downplay that role, but the importance of it is obviously large. And we're looking at a couple of technical people who will do a lot of the day-to-day joint venture liaison with our partners, LLOG and Westlawn, of course. And you know, the market for those types of roles, upstream experience roles in Houston is broad and deep. It's massively encouraging when you go and talk there. Having said that, of course, though, we will also utilize our capabilities from Brazil. And I'm looking forward to getting the Brazil team involved in our non-operated venture in the U.S. And, yeah, there's on a number of projects, we will bring the right people and the right capabilities to bear from Brazil as well. We have a reasonable amount of Gulf of Mexico experience in Brazil already in the team there, so that's also very good. We'll probably also at some point appoint a lawyer into the team. As you know, Andrew, and everyone else knows, the U.S. can be quite a litigious environment. And I think appointing a lawyer will be very good. We're very well served at the moment, though, with the legal counsels that we have that we're able to use on a contractual basis. So yeah, that's—it's not any problem for us at this stage. But yeah, so that's sort of six people, more or less. I think that's where we'll end up through the year. I don't see it being any bigger than that. Thank you. The next question is from David Birrell, from Croxon Capital. At Who Dat, is the gas oil split expected to be 40%-60% going forward with the new wells coming online? Yeah, look, I think the oil is 60%-65% from memory. I haven't got it exactly to hand. But in terms of a, you know, BOE basis, I think 60%-65% of that is oil, 35% or so is gas or gas and NGLs. So it's... So So yeah, that we don't see that necessarily changing in the near term. Obviously, it goes up and down a little bit, depending on what is actually producing from the field. And as you draw down pressures, you tend to liberate a little more gas from liquids. I think a lot of Who Dat has been through that phase. But yeah, so we don't see massive change in the near term. Thank you. The final question is from Jess Laseur, who's a shareholder. His first part of his question is about dividends, which I think we've already discussed, but the second part is: Would Karoon look at buying back into the Australian market if a good opportunity appears? Look, I think with our head office being in Melbourne, we do stay very close to what is happening in the Australian market. I'll be frank, we probably see a sovereign risk in Australia that wasn't like it- or it's not like it used to be. You know, there was a period when the majors and super majors couldn't get through the door into Australia fast enough, because it was such a good place to be. Now, I don't think we see quite so much of that. There are a number of attractive projects in Brazil. Getting access to those projects at a scale that would make sense for Karoon, I think is not necessarily simple. And doing it in a way that does not increase our long-term risk profile, especially from a sovereign point of view, I think is important. We've seen a lot of things in the last 12 or 18 months in Australia, which I think have been very surprising for the upstream oil and gas industry. Some of that maybe is backing off a little bit now, but yeah, I mean, it's harder to get approvals in Australia than it is in Brazil. You know, just as if you want to lay a benchmark down there, much harder. So I think we're still... You know, we will still look at Australia, but obviously through a lens of what the risk profile is like. Thank you, Julian. And then there are further questions online. So I'll hand back to you to wrap up. Thanks very much, Ann, and thank you, Ray, and the team. Thank you, Ashley, for helping us through the webcast as well. Yeah, just I want to thank our shareholders for their confidence and long-term support in Karoon. You know, we are continuing to go through a growth phase in the company, which is—it remains transformative for the organization, and for our asset base. The board is convinced it is the absolutely right strategy for us to be on. We continue to be focused on oil. Obviously, with Who Dat, we've taken on some gas. We are comfortable with that position. And I think with the strong cash flows that we're seeing, I'm hoping that through 2024, shareholders, you know, will have an opportunity to see and understand how that plays out with the two key assets that we now have. So thank you very much to everyone. Thank you, of course, to the team in Karoon, and to our board of directors, for the support and confidence that they've given to the team as we've gone through 2023. And I look forward to updating the markets in the next round of updates that we provide. Thank you very much. Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.