Karoon Energy Ltd

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 Karun Energy Limited. I'm joined today by Ray Church, our Chief Financial Officer, and Anne Diamond, 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. So going through the slide number four and noting the disclaimer on slide two as we go, slide four presents the highlights of our interim results. So we can go through that. During the half year, we completed our first year as operator of the Ballooner 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 crude 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 US$204 million cash on hand at the half-year end, recording underlying NPAT of US$21.1 million and an underlying EBITDA of close to US$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 Boone 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 recognise 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 costs of $23.50 per barrel for the half. This is despite continuing additional preventive maintenance measures being undertaken on the FESO to ensure the longevity of our facilities. However, we can expect the unit production costs 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 MRSS 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 in the 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 Bona 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 to 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, and 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, and 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 tonnes of carbon emissions per year. If we move now to the next slide, 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 harvest year. Despite the global COVID pandemic, we were able to keep our FPSO operations COVID-free throughout calendar 2021, utilising 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. But 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 Bawuna. Project Humo, one of more than 10 Bawuna social and environmental projects, is our social education project regarding use of the maritime zone and coastal area of the Itajai Asu 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 organisation 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 Bowen 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 and 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. And 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. So, 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 results for the first half on slide 7 and then make some comparisons with the previous full year. So moving to slide 7. 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 bowowner field continued to produce strong revenue of $186.5 million for the half at an average realised crude price of $72.43 per barrel. This compares with $23.8 million and average realised price of $47.31 in the prior first half and a reflection of oil price tailwinds. OPEX for Bona was $23.50 per barrel in the six months from June to December 2012, 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 costs 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 rail-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 FY22 were 27% higher than the second half FY21, 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 FY21, which delivered underlying EBITDA of $58.6 million. This is given the improved revenues and gross margins. 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 was 17% higher than second half FY21 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 balance, 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 FPSO lease payments in this analysis. Stable production, five cargo listings and rising oil price generated $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 $70.9 million of cash before funding of $14.1 million in long-lead capex and a legacy settlement of $9.6 million. Prior to close of the half, we made a $30 million initial drawdown on a 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 plan developments this year. And 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 21. 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 the result of incorporating a higher oil price scenario than that used in the FY21 financial results. It's important to note that the uplift in contingent consideration is capped at US$70 per barrel rent, 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 Barcova and Patola development programs, we also finalised 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 a core inflexibility of a potential additional $50 million. Total liquidity at 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 21 to September 23, and combination of sold calls consisting of $87.50 strikes or a ceiling for the period from April 22 to September 22, reducing the $82.50 ceiling from October 22 to September 23. The hedge volumes of the put options cover approximately 40% of production to September 2022 and 30% from October 2022 to September 23, leaving good exposure to the upside on the unhedged volumes. With $204 million cash on hand at end December and this $160 million to $210 million debt facility, This provides career and adequate liquidity and headroom for the planned baron and 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 contingent consideration was removed from underlying results. The 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 US dollar currency held in Australian entities have also been removed. Adding these items back to underlying impact 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. And please note that scheduled maintenance and the 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 and $7 million through year end, while other cost guidance remains unchanged. And for clarity, I'd like to remind you that a deferred consideration of between $43 and $44 million is payable in May 2022. This is a cash flow item and an already reflected financial statement. Thank you. I'll now hand back to Julie.

Yeah, thanks very much, Ray. I think that summarises really well what for us I think is a really solid and reliable set of results for that half and I think really reflects well the reliability that we've put into our operations and obviously that's with the tailwinds of the oil price. If we can move now to slide number 14, please, to 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. So slide 14 shows the base businesses delivering this transformation and our sanctioned 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 and patola projects, as I've said before, have the potential to lift BMS 40 production to over 30,000 barrels a day by early calendar 23. On Neon Goya, the work continues on two fronts. Firstly, we shall continue to analyse the potential development options, including stand-alone and bowina tie-back options. Secondly, we are analysing 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 is a small and highly experienced team analysing opportunities that arise in the market. This is useful, of course, for looking at our own organic growth opportunities, enabling us to make comparisons around relative attractiveness, as well as keeping us current with market opportunities, so we're 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 Karun'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 Karun 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. And 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. And this is an area that we continue to strengthen as we move forward on the path to our strategic goal of being net zero for scope one and two emissions by 2035. Slide 16 provides more detail on our operating performance at Bona. 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% of 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% to 15% when we took on the asset. We do expect to see lower production in the second half of FY22 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 number 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 kilometers of mooring wires, 8 kilometers 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 in Bauna 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. Wellheads, subsea equipment, flowlines 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 and $130 million for the interventions and $175 to $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. And we expect to see that in the first quarter of calendar 2023. And as I've 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 to 4.6 million barrels for FY22, and our operating costs expected to come in at the lower end of the previous range, now $28 to $30 per barrel. With a largely fixed cost base, we expect to see our unit OPEX decline significantly below $20 a barrel during FY23. 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 Bo'una and that excellent uptime performance that I've already commented on. Slide number 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 Goya 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, but 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 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 centre, of course, of 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, but 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 recognise 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 Boy project 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 2 emissions. Lastly, we have entered into agreements to purchase carbon credits to offset Scope 1 and 2 emissions while we pursue the first two priorities. This has already rendered our 2021 operations carbon neutral and will neutralise 60% of our scope 1 and 2 emissions for 2022 to 2029. For the remaining of these 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. Karun 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 projectory 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 and those low operating costs will continue to go down as we bring in the growth projects. Finally, I'd like to emphasise that with our oil focus, our growth profile and exposure to the Brazilian upstream industry, we have created in Karuna 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 1 on your telephone and wait for your name to be announced. If you wish to cancel your request, please press star 2. If you are on a speakerphone, please pick up the handset to ask your question. Your first question comes from Adrian Prendergast from Morgan 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. It would just be great to build on that. And then second question would be for Julian. Great uptime from the FDSA, 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 FDSA.

Yeah, look, 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. and they're denominated in Brazilian real. So we have, for example, continued consideration for accounting is expensed, but for tax in Brazil is capitalized and then amortized on a similar to UOP type basis. So 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. And then, of course, they're Brazilian real denominated. And so all of those assets and liabilities that are in Brazilian real are revalued depending on what the FX rate is doing between Brazil and US dollars. That's the nature of it. And because it's the tax effect of those, of the deductibility of those costs, is a tax-related item and therefore flows through the tax expense. So 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 combination of FX and tax and accounting procedures. Anyway, so 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. And 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, and we certainly target uptimes that are at the upper end of that, sort of looking to get 97% or so. But 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 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. And all of that of course can impact how we operate. We have been very, very careful and mindful that we're likely to see some of these these things happening. And 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. But look, I wouldn't look at the team and say I would expect to see a 99% uptime going forward as the baseline. We would 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 belaboured 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 that work will continue because what we want to see is a high-quality asset with high levels of uptime, with a long period of good, rosy future ahead of us, especially in the current oil price environment. Thanks, Brad. That's really helpful.

No problem.

Thank you. Your next question comes from Mark Sampter from MSG. Please go ahead.

Yeah, morning. Quick one for you, Julie. 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 EMPs 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. So we continue to look at opportunities in the Brazilian market. Having said that, though, as you can imagine, quite a lot of opportunities come across my desk. And we do take a view that we should have a view on some of those as they come through. And at the moment, of course, focus is on Brazil. But as things move forward, it's always difficult to say how things may pan out. But we're certainly open to opportunities and we'll continue to screen those. We have a focus on oil, of course, and I wouldn't be trying to push us towards a big gas market. So an oil focus is certainly where we are. And with the presence in Australia, yeah, naturally we are aware of opportunities that arise in this market as well. But, yeah, we continue with our evaluations. Primary focus, of course, production. Second focus is getting our project up and running at the TOLA and the interventions. And the third priority is trying to move forward with NEON. Brilliant. Thank you, David. 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 Ramsey 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 production costs being managed quite well. My first question, I've just got a couple if I can. My first question is on the FPSO Charter O&M contract. The contract reduces in February, but also there's a small lift in 90% once production goes above 15,000 barrels a day. And 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, look, the contract's pretty clear about that, and we've, I think, been open in the results. Yeah, in February, yeah, we see that step down. That's to do with an anniversary on the FPSO. I think it's a 10-year anniversary that 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. And the second question relates around Neon. And you're obviously going to make a decision shortly on whether to drill there or not. I guess my question comes back to the Neon West prospect and what 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, it's great you raised that, Gordon. We see a number of additional opportunities around NEON and Goya, and any development would obviously take those into account. However, what is pretty fundamental for us is that we have a base. a strong, high-quality asset that will underpin a development there. And 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, very similar seismic response, a very similar signature. And yeah, we recognize that opportunity in the west. But 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 Goya and the related discoveries there. Ultimately, I think what this points to is something more of a hub concept. So whether it's a tieback of NEON into Bauna or whether it's a standalone development, in any of those cases, we would see NEON forming something of a hub to allow those tie-backs to be done or those tie-ins to be done to NEON itself in the most cost-effective manner. And we would program the timing of further appraisal or the near-field exploration according to those field development decisions.

Thank you very much.

Thank you. We have a follow-up question from Adrian Prendergast from Morgan Financial. Please go ahead.

Yeah, thanks, guys. I'll just sneak on for a couple more. Just interested, Joanne, in if you've seen much repeat business in the bidding on owner cargos at all?

Yes, we have. We've seen quite a number of repeat bidders. We've actually had a... I can't recall the number, 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 and we've sold now 13, 14 cargos so you can imagine that's quite a number of bidders but we've We've sold quite a number to bidders in China, to the west coast of the US, and to Europe, and also other parts of South America where we've had repeat bidders and repeat buyers. 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. So we do see quite a bit of appetite there for the bow and a croot and it continues to be really encouraging to be honest around the pricing that we're seeing and the appetite for that.

And just last question for me. Obviously, over here or globally, we've seen big pockets of inflation affecting resource projects and WA is extreme in mining. But just keen to get a better feel for how Brazil is going industry-wise and is there real constraints supply-wise or tension on labour? Just what kind of environment you're seeing there?

Yeah, it's a great point to raise, Adrian. And I think it's sort of, for Karun, it has two or three elements to reflect on. First of all, with the intervention in Patola Workstreams, when we put those projects together and we were out in the market to tender, that was really still during COVID days. And to some extent, we were doing that work prior to having closed the deal itself on Bauna, we were getting ready for what that work would look like. So that was really prior to seeing cost inflation and 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 programme and obviously with Technip FMC for the major work that's being done for the Patola programme I think all of those contracts are at a good price for Karun, but also fair for the contractors as well. But what's important, I think, from a second perspective is that we have definitely seen a tightening in supply in the market. But fortunately for Karun, pretty much all of our supplies are secured through those early contracts that we let. So although we're seeing some minor cost inflation around smaller contracts, That's not having any impact on our overall estimates of the cost of our project. 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. And I would expect to see certainly an uplift in pricing as we go into that.