Thank you very much and good morning, everyone. Thanks for joining the call. As Harmony said, my name is Julian Fowles. I'm the CEO and MD at Karoon Energy Limited. I'm joined today by Ray Church, our Chief Financial Officer and Ann Diamant, our Head of IR. Earlier this morning, we released to the market our interim results covering the first half of financial year 2022. There's a slide pack with those results which we shall run through in this call. Going through to slide number four and noting the disclaimer on slide two as we go. Slide four presents the highlights of our interim results. If we can go through that. During the half year, we completed our first year as operator of the Baúna concession, during which time we focused on establishing safe and reliable operations as our highest priority and you've heard me talk about that a lot. Although we had an overall very good safety performance, there was an LTI in the galley of the FPSO after over 1,400 days incident-free and that served as a really salient reminder that we must be very wary of complacency. Our oil production of 2.5 million barrels for the half year reflected an outstanding uptime performance of over 99% and I'd like to commend our workforce and our FPSO operator, Altera, for achieving such an excellent result. Our realized average oil price of over $72 a barrel U.S. Reflected the ongoing strengthening market for our crudes during the second half of calendar 2021 as the world continued to rebound from the COVID-induced downturn. We continue to see multiple bids for each of our crude cargos from markets as diverse as the West Coast of the U.S., the Gulf Coast, Europe, China and other parts of South America. The high price and the strong production performance have boosted our cash reserves and put us in a strong financial position with over $204 million cash on hand at the half-year end, recording underlying NPAT of $21.1 million and an underlying EBITDA of close to $90 million. One of the knock-on effects of the high oil prices has been a significant upward revaluation of our Petrobras contingent consideration. This was part of the purchase of the Baúna asset and of course, that impacts our statutory profit for the half year and Ray will discuss this in more detail shortly. However, it is absolutely vital to recognize that any increase in the amounts forecast to be paid to Petrobras reflect oil prices that are a net positive for Karoon at our target production levels. We continue to keep a close eye on cost control with unit production cost of $23.50 per barrel for the half. This is despite continuing additional preventive maintenance measures being undertaken on the FPSO to ensure the longevity of our facilities. However, we can expect the unit production cost to step up in the second half as our production continues to decline and we carry out a scheduled maintenance shutdown next month. Our growth projects are progressing on track with the Maersk Developer drilling rig due to arrive between mid-April and mid-May. Almost all major contracts have now been let and regulatory approvals are being progressed. The arrival of the rig will allow us to undertake the interventions and Patola development projects, targeting a production uplift to 30,000 barrels per day by early calendar 2023. The Neon engineering work continues to be progressed as planned and we remain on track to take a decision on potential Neon control drilling in the next month or so. We also continue to screen and investigate further oil investment opportunities offshore Brazil. We move forward decisively also on our strategic commitments to become carbon neutral on our Scope 1 and Scope 2 carbon emissions at Baúna and the future Patola development, entering into agreements to purchase high-quality verified carbon offsets with additional social benefits for the entirety of our 2021 operations and for 60% of our 2022 - 2029 operations. For the remaining 40%, we are seeking direct involvement in projects. Of course, our first priority is to remove and reduce carbon emissions wherever we can. The first half saw the completion of two important projects in this regard. The first, replacing the low-pressure flare on the FPSO, improving its efficiency. The second, installing a mooring buoy close to the FPSO for vessels to tie up to in order to reduce their fuel use. The mooring buoy project itself is expected to remove around 2,000 tons of carbon emissions per year. If we move now to the next slide five, this goes into our HSSE performance in more detail. Our performance in this area, of course, is essential to ensuring our operations remain reliable. I've already mentioned the slip in the FPSO galley. The worker received an injury to their shoulder but it's good to know that they are recovering well. From a process safety perspective, we kept all of our hydrocarbons inside the pipes where they belong and we had no material environmental incidents during the half year. Despite the global COVID pandemic, we were able to keep our FPSO operations COVID-free throughout calendar 2021, utilizing strict screening, testing and quarantine protocols. Early this year, in January, we did have a number of cases on the FPSO due to the highly infectious Omicron variant. By going to the next level of our COVID management contingency plans and implementing strict operational continuity protocols, we were able to stop the infection from spreading and there was no impact on production. Related to our operations, we are also moving forward with our socio-environmental projects for Baúna. Projecto RUMO, one of more than 10 Baúna social and environmental projects, is our social education project regarding use of the maritime zone and coastal area of the Itajaí-Açu River estuary. It has continued to progress through engagement with various users of the river and monitoring of the vessel traffic to help develop practical solutions to improve the organization of the traffic in the river and reduce potential conflicts. We have also advanced the Sun Coral Project, sponsoring research into exotic species to try and protect the biodiversity of the areas around Baúna operations by preventing the invasion of this highly aggressive exotic coral species by shipping vessels. The carbon offsets we have purchased are also part of our consideration of social and environmental projects in Brazil. They all have Climate, Community & Biodiversity Standard certification, focusing on a number of benefits such as income creation for local communities and the protection of local flora and fauna habitats. These are really important projects for us as we continue to move forward with our operations in Brazil and expand our footprint there. What I'd like to do now is to hand over to Ray to talk in more detail about our financial results. Ray, over to you. Thank you, Julian. Good morning, everybody. I'd like to now give you an overview of results for the first half of the year and show the effects of strong oil price, stable production, controlled fixed costs, good rates of cash conversion and some non-cash accounting items that are included in the result. I'll first talk to the underlying result for the first half on slide seven and then make some comparisons with the previous full year. Moving to slide seven. As Julian mentioned, production was 2.5 million barrels for the half, compared with 816,000 barrels in the comparable period last year, a result of stable operations and a full six months of production. The Baúna field continued to produce strong revenue of $186.5 million for the half at an average realized crude price of $72.43 per barrel. This compares with $23.8 million and average realized price of $47.31 in the prior first half and a reflection of current oil price tailwinds. OpEx for Baúna was $23.50 per barrel in the six months from June to December 2021, up from $22.10 in prior year first half which was a little better than expectations due to higher than forecast production, a deferral of some activities in the second half and a weaker Brazilian real. Royalties of $19.1 million reflected a full six-month production and an increasing oil price. We closed the period with inventory of 143,000 barrels compared with 251,000 at end June, due to timing of cargoes relative to end of period. Corporate exploration and other costs totaling $13.9 million include exploration and business development cost of $2.6 million with the remainder related to corporate and staff costs. Underlying income tax expense includes a $13.3 million non-cash expense related to FX movement of Brazilian real-based future net tax benefits, as well as $2.4 million of permanent differences and $1 million of timing differences. The resulting underlying profit was $21.1 million for the half. As the comparative half on this slide reflects a short period of operation, I'd like to compare the results with the full second half of January to June 2021 on the next slide. This slide shows key financial metrics for the three most recent halves, including the partial period of initial operations. Total oil sales of $186.5 million for first half FY 2022 were 27% higher than the second half FY 2021, driven by sustained production and higher oil prices. Production costs were slightly lower, a result of stable operations and cost management. The resulting underlying EBITDA was $89.5 million and 51% higher than the second half FY 2021, which delivered underlying EBITDA of $58.6 million. This is given the improved revenues and gross margin. Regarding underlying NPAT, I'd like to point out that after adjusting for non-cash FX movements in tax expense mentioned earlier and applying that to both current and prior periods, underlying NPAT for this half was $34.4 million while the prior period delivered an adjusted underlying NPAT of $16.6 million. Operating cash flows of $83.9 million were seventeen percent higher than second half FY 2021 and reflects a high rate of cash conversion. Lastly, during this half, in light of current high oil prices, we recorded an increase in the Petrobras contingent consideration of $183.8 million. The amount ultimately payable is dependent on the average oil price in each calendar year from 2022 to 2026 inclusive. However, accounting standards dictate this probable change is assessed and expensed and it's not considered reflective of ongoing performance and rather the additional amount the company expects to pay as consideration for. We have removed this non-cash item from underlying result. Moving to cash flow on slide nine. I'd like to now explain the highlights of cash flow and point out this is a non-accounting view, in order to more clearly show the cash flows from the operating business before non-OpEx expenditures, CapEx, a legacy legal settlement and financing impact. I've included FPS lease payments, FPSO lease payments in this analysis. The stable production, five cargo listings and rising oil price generate $184 million of oil sales receipts as the foundation for strong operating cash flows. This met $62.3 million of operating costs, including FPSO lease payments, $19.1 million of royalty payments and $9.8 million of corporate and exploration costs, followed by $9.8 million of hedge premiums and finally $11.7 million of income tax payments. This generated $79 million of cash before $14.1 million in long lead CapEx and a legacy settlement of $9.6 million. Prior to close of the half, at a $30 million initial drawdown on the new loan facility, less $6 million of borrowing costs in order to activate the facility. This all resulted in growth in closing cash in hand from $133 million to $204 million through the half. The combined strong cash generation ability of operations and available loan facilities will provide cash supply for the planned developments this year. Now moving on to the balance sheet and credit facilities on slide 10. As already mentioned, cash on hand totaled $204 million compared with $133 million at June 2021. There was minor movement in non-cash working capital, reducing the net credit balance by $3.7 million to $76 million, primarily due to receivables growth driven by rising oil price and cargo timing. Cash growth drove an overall increase in total assets to $1.1 billion and the recognition of additional contingent liability to Petrobras offset the cash improvement, reducing net assets by $99.9 million. The total contingent consideration liability now stands at $260 million with a present value of $255 million recorded on the balance sheet. This represents 82% of the maximum contingent consideration, including interest payable out to 2026 with the increase a result of incorporating a higher oil price scenario than that used in the FY 2021 financial results. It's important to note that the uplift in contingent consideration is capped at $70 per barrel Brent, with no incremental consideration payable above this level. I'd also like to point out that the first payment for contingent consideration would be due in January 2023. This is in addition to the deferred consideration payment due in May this year, reflected in guidance on the coming slide. Given the current oil price strength and market fundamentals, we anticipate paying the maximum annual amount or approximately $85 million per annum over the 2022 and 2023 periods. While contingent consideration is a result of higher oil price which flows through operating margin and cash flow, to ensure adequate liquidity during the workover and Patola development programs, we also finalized the committed reserve-based lending facility during the half. This facility is supported by finance partners Macquarie, Deutsche, ING, and Shell, and capacity set at $160 million, of which we've drawn down $30 million, with accordion flexibility of a potential additional $50 million. Total liquidity at 30-31 December was consequently $334 million. In addition, we entered into a hedge that supports the new credit facilities and will provide some protection on cash flows from low oil prices. This hedge takes the form of a collar consisting of a bought put option with a per barrel strike price or floor of $65 for the period December 2021 to September 2023, and combination of sold calls consisting of $87, $87.50 strikes or a ceiling for the period from April 2022 to September 2022, reducing to $82.50 ceiling from October 2022 to September 2023. The hedge volumes of the put options cover approximately 40% of production to September 2022 and 30% from October 2022 to September 2023, leaving good exposure to the upside on the unhedged volumes. With $204 million cash on hand at end December and this $160 million-$210 million debt facility, this provides current adequate liquidity and headroom for the planned Baúna-Patola expansion programs without the need for further equity. On slide 11, we provide a reconciliation from underlying NPAT to statutory NPAT. As already mentioned, the increase in fair value of continuing consideration was removed from underlying results. Associated tax effect at the Brazilian tax rate of 34% has also been removed. Additionally, restructure costs of $900,000 associated with former executive departures and FX gains from restatement of U.S. dollar currency held in Australian entities have also been removed. Adding these items back to underlying NPAT produces the statutory net loss after tax of $97.7 million. Looking ahead to guidance for the full year on slide 12. Production guidance has been narrowed to the higher end of previous guidance. Please note that scheduled maintenance and the ESP intervention program will mean second half production is lower than first half which will also increase average full-year unit production costs above first half performance of $23.50 per barrel. Nevertheless, the full year guidance range has been reduced to between $28 and $30 per barrel. Finance and interest costs are expected between $6 million and $7 million through year-end, while other cost guidance remains unchanged. For clarity, I'd like to remind you that Baúna deferred consideration of between $43 million and $44 million is payable in May 2022. This is a cash flow item and already reflected in financial statements. Thank you. I'll now hand back to Julian Fowles. Yeah, thanks very much, Ray. I think that summarizes really well what for us I think is a really solid and reliable set of results for that half. I think it really reflects well the reliability that we put into our operations. Obviously, that's with the tailwinds of the oil price. If we can move now to slide number 14, please. Skip forward two slides to 14. In October last year, we presented our refresh strategy to the market, introducing key members of our top team. Now this team is tasked with delivering our transformation into a safe, reliable and significant oil operator offshore Brazil. Slide 14 shows the base business is delivering this transformation and our sanction projects are progressing on track. We still have to deliver these projects, of course, and their safe and effective execution is a major operational focus for the project teams in calendar 2022. The combined interventions in Patola project, as I've said before, have the potential to lift BM-S-40 production to over 30,000 barrels a day by early calendar 2023. On Neon Goiá, the work continues on two fronts. Firstly, we shall continue to analyze the potential development options, including standalone and Baúna tieback options. Secondly, we're analyzing the potential drilling of a control well or wells at Neon to assist with constraining those development options. Work on both fronts has been going to plan and we hope to be in a position to make a decision on Neon control well drilling in the next month or so. In parallel with this work on organic growth opportunities, there's a small and highly experienced team analyzing opportunities that arise in the market. This is useful, of course, while looking at our own organic growth opportunities, enabling us to make comparisons around relative attractiveness, as well as keeping us current with market opportunities who are ready to move forward to assess any potential M&A transactions should they arise. On slide 15 now. In October, we highlighted a number of focus areas that are enabling the execution of our strategy and I'm pleased to report that these are moving forward well. We've already discussed with the market the new appointments we made in Q4 last year and it's been great to see both Ray and Antonio really get down to business with our people and our assets and engage with our key stakeholders. Securing Karoon's first debt facility was a major milestone and has significantly bolstered our access to cash, as Ray has pointed out. That is already strong. As Karoon develops our credentials as a borrower, we're working on a ready-to-go debt plan to fund our potential growth opportunities while balancing any capital allocation into high value growth with returns to shareholders. We have, of course, potential access to the accordion facility discussed by Ray a little earlier. I've already talked about building our sustainability position and taking a responsible approach to the challenges of climate change. This is an area that we continue to strengthen as we move forward on the path to a strategic goal of being net zero for Scope 1 and Scope 2 emissions by 2035. Slide 16 provides more detail on our operating performance at Baúna. This has really been a standout for the half year and a real credit to our operations team, delivering uptime very close to 100% in the second quarter. In December itself, we did achieve 100% uptime, in fact. Production decline for our first full year of production sits at around 10% and that's at the right end of our prediction of 10%-15% when we took on the asset. We do expect to see lower production in the second half of FY 2022 as production continues on its decline and we have a planned 11-day outage in March for annual maintenance. If I can go to slide 17 now. The Maersk Developer drilling rig is currently in the Caribbean, undergoing routine maintenance prior to setting sail for Brazil. Regulatory approvals are being progressed and we expect the rig to arrive between the 15th of April and the 15th of May and the intervention program should start immediately thereafter. Rig mooring equipment, including more than 11 km of mooring wires, 8 km of chains, and 17 truck-sized anchors have already arrived in Brazil for the rig campaign. Tools for the interventions have started to be delivered, along with the electric submersible pumps for the two wells at Patola where these will be installed. Sorry, for the two wells in Baúna, where these will be installed. This program will take some four months or so to complete and the rig will then move to execute the two-well Patola drilling program as planned. Wellhead subsea equipment, flow lines and umbilicals manufacture is well underway and will be progressively delivered to meet our schedule. Costs for these programs remain on track in the ranges previously advised between $110 million and $130 million for the interventions and $175 million-$195 million for Patola. We should see production step down and then step up again as each intervention is undertaken in sequence. For Patola, we'll see the wells come on stream together once they have been tied into the existing slots on the FPSO and commissioned. We expect to see that in the first quarter of calendar 2023. As I said before, total production is expected to reach 30,000 barrels per day once all of the work has been completed. If we can go to slide number 18 now. This provides an update on our production and cost guidance, with the expected production range tightened to 4.4-4.6 million barrels for FY 2022 and our operating costs expected to come in at the lower end of the previous range, now $28-$30 per barrel. With a largely fixed cost base, we expect to see our unit OpEx decline significantly below $20 a barrel during FY 2023. Of course, these numbers and the tightening of these numbers has been due to the good performance that we've seen through the first half in Baúna and that excellent uptime performance that I've already commented on. Slide 19 provides an update on progress with Neon. Our view here has not changed, in that we believe there's an attractive 2C contingent resource of over 80 million barrels combined with Goiá with strong development potential. Careful planning is underway to ensure we are able to maximize recovery as cost effectively as possible and control well drilling is likely to be able to help with this and we'll be in a position, as I've said, to make a decision in the next month or so to enable that drilling to take place at the end of the Maersk Developer Patola drilling sequence. Slide 20. This talks about Neon. It's one growth option that we have that sits in our pipeline. One of the advantages of operating in Brazil at this time is that we don't have to look too far to see other opportunities as well. We maintain a strict process based on clear criteria with a small, highly experienced team screening and evaluating oil opportunities as they come to market. This enables us to compare and contrast organic with inorganic growth options and in some instances, we're able to do that prior to the opportunities coming to the market. Our capital allocation process incorporates assessing high value growth investments while also considering returns to shareholders, which remain front and center, of course, at board discussions. On slide 21, we then talk about our ability to fund growth through looking at our investments in reducing our carbon footprint and how we're managing our obligations with respect to climate change. We've set ourselves on a good path with our inaugural debt facility for funding our growth future. As we grow, we'll continue to come under more and more detailed scrutiny in the investment and debt funding communities. We must continue to ensure we have the best credentials around safe and reliable operations. We also recognize the importance of facing the global challenges posed by climate change and our first priority in this area is to avoid and reduce carbon emissions. I've mentioned our low pressure flare and the mooring buoy projects already. As a further priority, we're seeking direct and indirect investments in high quality projects with positive social impact to offset our remaining Scope 1 and Scope 2 emissions. Lastly, we have entered into agreements to purchase carbon credits to offset Scope 1 and Scope 2 emissions while we pursue the first two priorities. This has already rendered our 2021 operations carbon neutral and will neutralize 60% of our Scope 1 and 2 emissions for 2022 to 2029. For the remaining of the Scope 1 and 2 emissions, we're pursuing direct investments in carbon offsetting projects. If we can move to slide number 22. This summarizes where we are. Karoon is well positioned to deliver shareholder value through our safe and reliable operations and our clear and sustainable growth path. We have an experienced and capable board and management with knowledgeable and highly experienced operations and development teams on the ground in Brazil. We are building a reputation for reliable and safe operations and we take our ESG responsibilities very seriously and are taking action, as you can see, in this area. We have a clear growth trajectory with high value near-term production growth potential, taking us from 13,000 barrels of oil per day today to 30,000 barrels plus. Longer term, we continue to seek attractive value-accretive, organic and inorganic growth opportunities. We have a strong liquidity position to fund our growth projects and we're generating strong cash flow at relatively low operating cost. Those low operating costs will continue to go down as we bring in the growth projects. Finally, I'd like to emphasize that with our oil focus, our growth profile and exposure to the Brazilian upstream industry, we have created in Karoon a unique and compelling value proposition for market participants. I'd like to thank you all for your attention today and I would like to hand back now for any questions that we may have. Thank you. If you wish to ask a question, please press star one on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star two. If you are on a speakerphone, please pick up the handset to ask your question. Your first question comes from Adrian Prendergast from Morgans Financial. Please go ahead. Yeah, thanks, Julian and Ray and great result. Very encouraging to see. Just a question for each of you. I guess the first one's for Ray. Just keen to get a bit more of an understanding around how those FX rates impact the P&L tax. So it'd just be great to build on that understanding. Then second question would be for Julian. Yeah, great uptime from the FPSO. Obviously, as you covered, field performance has been really encouraging as well, very generally. Yeah, with your time as an operator quickly accumulating, just keen to check back in on your view of the health of the wells and pipes from a risk perspective and the remaining life of the FPSO. Yeah. Look, thanks. Thanks, Adrian. I'll hand it to Ray, first of all, to address your question on FX and tax. Happy to do that. The FX component of tax obviously is going to oscillate but the driver is that at the heart of it is that in Brazil, the balance sheet, if you like, the depreciable assets are not the same as the accounting depreciable value. They're denominated in Brazilian real. We have, for example, continuing consideration for accounting is expense but for tax in Brazil, it's capitalized and then amortized on a similar to UOP-type basis. We're already seeing some of those differences appear over time. The result is that we have a deviation, if you like, in the balance, the sort of value of balance sheet in tax purposes over time. Of course, they're denominated in Brazilian real. All of those assets and liabilities that are in Brazilian real are revalued depending on what the FX rate is doing between Brazil and U.S. dollars. That's the nature of it and because it's, you know, the tax effect of those of the deductibility of those costs is a tax-related item and therefore flows through the tax expense. That's about as simple as I can make that explanation. Does that make sense? Yeah. That's great, Ray. I look forward to building it in. Okay. Yeah. Thanks, Ray. I'm glad you're explaining that and not me. It's the combinations of FX and tax and accounting procedures. Anyway. Adrian, your second question on the operations really on our uptime. We sort of look at our uptime through the lens of what we see globally for FPSO uptimes. Typically, operators manage something around the low to mid 90% in terms of their uptimes for FPSOs. We have reasonably high expectations of our team, of course. We certainly target uptimes that are at the upper end of that, sort of looking to get 97% or so. There's a range between 92% and 97% that we would sort of forecast, I guess, for any particular budget period. Having said that, achieving uptimes of 99% or even 100% for any period is truly an outstanding performance. The FPSO and the facilities, of course, are, you know, seven or eight years old. They've been producing well through that time. We find with some of the wells that they're very sensitive to back pressures. They can undergo some slugging of liquids from time to time. All of that of course can impact how we operate. We have been very careful and mindful that we're likely to see some of these things happening. That's what led us to make sure that we could commission and have available the second production train through the FPSO last year. That obviously was a key piece of work for us. Look, I wouldn't look at the team and say I would expect to see a 99% uptime going forward as the baseline. We'd still be targeting somewhere between 92 and 97 and probably a 95% uptime as a sort of average as we go forward. Even 95%, to be honest, would be still an outstanding performance compared to the FPSOs that we see operating around the world. The facilities, as I've said, we spend a lot of time and you know I've really belabored this point. The preventive maintenance work that we've been doing on the high pressure systems, the low pressure systems, the compressor systems and all of our water handling, gas handling and oil handling facilities on the FPSO, that has really been of paramount importance for us. I would expect to see that work will continue because what we wanna see is a high quality asset with high levels of uptime with a long period of a good rosy future ahead of us, especially in the current oil price environment. Thanks, Ray. That's really helpful. No problem. Thank you. Your next question comes from Mark Samter from MST. Please go ahead. Yeah, morning, guys. Quick one for you, Julian. Just on the M&A and I wouldn't be stupid enough to ask you on a specific asset but I guess I can see listed Australian E&Ps that probably own stakes in great projects that they haven't got a hope in hell of funding and you bring a large level of funding capacity and obviously expertise to these kind of projects. Do we infer from the presentation today that the sole focus of- Potential M&A is only Brazil or is there any logic to the geographical diversification and obviously playing to your strengths when opportunities exist? Yeah. Thanks, Mark. It's a great question and I would never say never. Our primary focus, of course, is Brazil. I think that's where we see synergies with our existing operations. We see potential for that. Of course, we've got a very good knowledge of the market there now and we're starting to build some credentials as a good production operator. We continue to look at opportunities in the Brazilian market. Having said that, though, I, as you can imagine, quite a lot of opportunities come across my desk. We do take a view that we should have a view on some of those as they come through. At the moment, of course, focus is on Brazil. You know, as things move forward, it's always difficult to say how things may pan out. We're certainly open to opportunities. We'll continue to screen those. We have a focus on oil, of course. I wouldn't be trying to push us towards the big gas market. An oil focus is certainly where we are. With a presence in Australia, yeah, naturally, we are aware of opportunities that arise in this market as well. Yeah, we continue with our evaluations. Primary focus, of course, production. Second focus is getting our project up and running at Patola and the interventions. The third priority is trying to move forward with Neon. Okay. Brilliant. Thank you. No problem. Thank you. Once again, if you wish to ask a question, please press star one on your telephone. Your next question comes from Gordon Ramsay from RBC Capital Markets. Please go ahead. Sorry, I was just on mute. Thanks, Julian. Great result and nice to see your guidance tightened and costs, production costs being managed quite well. My first question. I just got a couple, if I can. My first question is on the FPSO charter O&M contract. The contract renews in February but also there's a small lift in 90% once production goes above 15,000 barrels a day. I guess the question is: Are there any other cost changes in the contract at higher levels of production above 15,000 barrels a day? Yeah. Thanks for the question, Gordon. No, the contract's pretty clear about that and we've, I think, been open in the results. Yeah, in February, we see that step down. That's to do with an anniversary on the FPSO. I think it's a 10-year anniversary, that contract steps down. And yes, at the point where we get back up to 15,000 barrels a day plus, we'll see that step back up slightly to 90% of current rates. There's no additional step-ups with higher rates, in that contract. Excellent. The second question relates around Neon. You're obviously gonna make a decision shortly on whether to drill there or not. I guess my question comes back to the Neon West prospect and what kind of status that's at right now, and whether there's any consideration of drilling that in support of a standalone, or is it still just an infill well at this point in time in the field? Yeah. Look, that's great you raised that, Gordon. We see a number of additional opportunities around Neon and Goiá. Any development would obviously take those into account. However, what is pretty fundamental for us is that we have a base strong, high quality asset that will underpin a development there. Neon is clearly the target for what that core asset needs to be. The western side of the salt dome, we do see a very similar seismic response, a very similar signature. We recognize that opportunity in the west. As well as that, there are of course other discoveries that sit around Neon that would also be targets for potential tieback, not least of which of course is Goiá and the related discoveries there. Ultimately, I think what this points to is something more of a hub concept. Whether it's a tieback of Neon into Baúna or whether it's a standalone development, in any of those cases, we would see Neon forming something of a hub to allow those tiebacks to be done or those tie-ins to be done to Neon itself in the most cost-effective manner. We would program the timing of further appraisal or the near field exploration according to those field development decisions. Okay. Thank you very much. Yep. Thank you. You have a follow-up question from Adrian Prendergast from Morgans Financial. Please go ahead. Yeah. Thanks, guys. I'll just sneak on for a couple more. Just interested, Julian, in if you've seen much repeat business in the bidding on Bona Cargo at all? Yes, we have. We've seen quite a number of repeat bidders. We've actually had a number I can't recall but there's a very wide spread of bidders that we've had. We typically get three or four high quality bidders on each cargo. You know, we've sold now 13, 14 cargoes. You know, you can imagine that's quite a number of bidders. We've sold quite a number to bidders in China, to the West Coast of the U.S., and to Europe, and also other parts of South America where we've had repeat bidders and repeat buyers. They've come in, one or two have come in with bids sometimes where they haven't quite managed to be the chosen one and they've come back for the next cargo with a stronger bid. We do see quite a bit of appetite there for the Baúna crude. It continues to be really encouraging, to be honest around the pricing that we're seeing and the appetite for that. Just last question for me. You know, obviously over here or globally, we're seeing, you know, big pockets of inflation affecting resource projects and you know, WA is extreme in mining. Just keen to get a better feel for how Brazil is going industry-wise and, you know, is there real constraints, supply-wise or tension on labor? Just what kind of environment you're seeing there? Yeah. It's a great point to raise, Adrian. I think it's sort of, for Karoon, it has two or three elements to reflect on. First of all, with the intervention in Patola work streams, when we put those projects together and we were out in the market to tender, that was really still during COVID days. To some extent, you know, we were doing that work prior to having closed the deal itself on Baúna. We were getting ready for what that work would look like. So that was really prior to seeing cost inflation. I think we managed to secure good pricing. I would say it's pricing which is fair for things like the rig contract and for other elements of the intervention program and obviously with TechnipFMC for the major work that's being done for the Patola program. I think all of those contracts are at a good price for Karoon but also fair for the contractors as well. What's important, I think from a second perspective, is that we have definitely seen a tightening in supply in the market. Fortunately for Karoon, pretty much all of our suppliers are secured through those early contracts that we let. Although we're seeing some minor cost inflation around smaller contracts, that's not having any impact on our overall estimate of the cost of our projects. As I said, the impact is tending to be on the smaller end of our project piece. I think as we look forward and if we look to further growth opportunities such as Neon, certainly those will be impacted by cost inflation. I would expect to see certainly uplift in pricing as we go into that. I think that would