Karoon Energy Ltd (KAR) Earnings Call Transcript & Summary

Thank you for standing by, and welcome to the Karoon Energy Ltd 2021 Full Year Results. [Operator Instructions]. I would now like to hand the conference over to Mr. Julian Fowles, Managing Director and CEO. Please go ahead.

Yes. Thanks, Harmony, and good morning, everyone, and thank you very much for joining the call. As Harmony said, I'm Julian Fowles, I am the CEO and Managing Director of Karoon Energy. I'm joined today by Scott Hosking, our Chief Financial Officer. Today, we'll run through a number of slides that describe our 2021 annual results, which were released to the market earlier this morning. Harmony, if you wouldn't mind moving to slide number 3, please. noting the usual disclaimer on slide 3. So the map on slide 3 outlines Karoon's area of operations in Brazil, and that's the main focus for our presentation today. It is Karoon's first annual results announcement as an oil producer and reflects a year, which has really been transformational in many ways for the company. We've delivered on all of our key strategic objectives, and we'll cover those as we go through the presentation. The results were nearly 8 months of production from the Bauna concession in the offshore Santos basin of Brazil. So if we can move to the slide 4, please. The slide 4 highlights the key strategic goals that we've achieved during the year. Our transformation into a safe and reliable oil producer, the sanctioning of 2 key growth projects and the strength of our balance sheet and liquidity as we go into the new financial year. I'll just go through those briefly one at a time. We completed the Bauna transaction, as we've covered in detail, in November 2020, and that has been our production focus since that. We've produced over 3 million barrels in the financial year of 2021, which covered nearly 8 months of production. We had an average realized oil price a little under $60 a barrel and that developed sales revenue for us of over $170 million on a unit production cost of just over $25 a barrel, which is where we had guided the market during that $23 to $27 range. Our reported NPAT of $4.4 million reflects an underlying net profit after tax of $33.4 million and operating cash flow that sits just under $30 million. Really importantly for our operations, though we have had an excellent safety record since we've started up production as the operator. We've sanctioned a couple of growth projects during the year. We've contracted the Maersk Developer drilling rig for the Bauna intervention program. That will commence in the second quarter of calendar '22. The timing specifically dependent on the rig arrival itself. We took FID on the Patola field development, and that's expected to come on stream early in calendar '23. Together, the intervention program and the Patola development make up a relatively low-risk pathway to more than doubling our production. We've also been undertaking a strategic refresh during this year, which is examining potential future growth opportunities and importantly, also looking at our sustainability strategy. So we get to the end of June 2021, we're in a cash position of $133 million. Our interventions will be funded from cash and from the Bauna cash flow. We have a new $160 million debt facility, which is secured for the Patola development, and that provides us flexibility for our balance sheet. We also are moving to hedge some of our production and that will protect us on the downside from oil price movements. If we can go to slide number 5, please. So in order to affect Karoon's transformation, we've also just been a refreshed board and management with heightened capabilities and experience that will enable us to deliver our production and growth. The details of our Board refresh and the management refresh has been in the market for some time, obviously. And I'd like to focus on the third bullet point on this, which is the appointment of our new President of Karoon Brazil, Antonio Guimaraes. Antonio will start on the 1st of October, and we're really looking forward to getting Antonio on board. He's an oil and gas professional with over 30 years of experience working at Shell and the IBP in Brazil as well. We've also appointed Mr. Ray Church as the CFO, and we'll be conducting a handover with Ray over this week with Scott and Ray will start, starting formally in the CFO position next week. So really good appointments there, and really great to have these guys on board. In terms of what else we've been doing, the change to a producer has necessitated a number of enhancements to our structure and to the way that we manage performance, providing clarity to our staff around what's expected and expected as a production company and also really focusing on our culture of openness, honesty and respect people in the environment. The company I am pleased to say it has maintained its nimbleness and its entrepreneurial nature through the transformation and I'd like to commend all of our teams in Rio, Melbourne and in Peru for the way these changes are being embraced. An important element of our restructure has been to ensure that new assets can also be brought into the company simply and efficiently, and that reflects that nimbleness I've talked about. We've also been undertaking a major refresh of strategy that I've mentioned and a significant focus of that has been on sustainability and especially carbon management. This work is currently being finalized and we plan to share the outcomes with the market, including our goals for emissions management and carbon abatement in detail in late October and I really look forward to being able to do that. We can move now to the sixth slide. This slide summarizes our main metrics across 6 main categories. The first and highest priority for us, of course, is the safety and integrity of our operations. And since we took over Bauna, our record in these areas has been excellent, noting that we did have 1 lost time incident on a supply vessel prior to taking over operatorship and that occurred during training. The other main highlights here have covered production and sales that I talked about, our unit production costs, the revenue that we've mentioned, year-end cash position, as I said, is very, very strong. And our operating cash flow, the underlying impact and our reported net profit, of course. I'll leave you to take a look at those as you need to. If we can move to slide number 7, please. So slide 7 addresses our HSSE performance in a bit more detail, emphasizing our key focus of ensuring a strong HSSE culture is instilled in our operations and fully aligned with Altera & Ocyan to operate the FPSO. I would highlight that our COVID trade practices have been very effective in keeping staffing contractors healthy and our operational worksite COVID-free, and pleased to report that most of our office and operational staff have had at least one shot of COVID vaccine, and we expect everyone onshore and offshore, including our rotational contracts to have been fully vaccinated in the first quarter of next year, providing further confidence around how we manage our operations and the health of our staff. A couple of other bullet points that are worth highlighting on this. We have a diverse workforce at many nationalities working for us with 50% female across the Karoon Group. And we have also a number of socio environmental projects that are already underway related to our operations. And as I said, we'll talk more about those towards the end of October when we roll-out the strategic refresh. That strategic refresh is looking at environmental, social and government practices, including our approach to communities and climate change, and it includes setting goals and targets as well as management accountability for those targets. If we could now move to slide number 8, please. Slide 8 covers our financial results in more detail, and I'll ask Scott to address this slide and the next one. So over to you, Scott.

Thanks, Julian, and welcome to everyone, and thanks for attending the call today. We're pleased you could get on in here our first set of results here. So all figures presented today will be in US dollars. I won't be referring to them as US dollars, but they're all in US dollars. During the financial year or more accurately, the period from 7 November 2020 to June '21. So first 8 months of operations, Karoon produced 3.1 million barrels and sold 2.9 million barrels through 6 cargoes of oil to 3 separate buyers in Asia, Europe and South America. We were quite pleased actually to have been able to attract a very diverse range of refiners and buyers from really all over the world, and we were only expecting to be able to sell oil into Asia. So that was quite a good result, giving us some diversity in order for future sales. Karoon -- as Julian said, Karoon netted $170 million revenue or $59 a barrel for sold oil, selling 2.9 million barrels. Our unit production cost of $25 or $25.11 were, I think, around expectations that are in line with guidance. We'll discuss the forecast production costs shortly in guidance towards the end of the presentation. One thing I would just draw people's attention to is we've added some learning here around other costs. So the other cost number that you'll see there is quite a large number. It's a grouping of FX results, corporate costs, adjustment to fair value for contingent consideration and the recently announced Pitkin settlement on our Peruvian asset. As you can see, this figure is substantial and will likely be lower in future financial years as many of these extraordinary items will be reduced or eliminated as we go forward and really are just part of our transition of our first year of operations and setting up there. So Karoon produced net profit after tax of $4 million with an underlying net profit after tax of $33 million. The underlying net profit after tax figure has been generated to provide a better clarity and set out those costs, which will vary or be eliminated in future years. So within that underlying number, we add back tax losses of $20 million. So these were losses that didn't relate to this financial year, but rather losses that we had in Brazil that we bring forward, and it's now become realized losses. So the reason we take them out has been actually from this year from prior years. We also had FX losses that we generated primarily from the variance in Karoon's US dollar holdings pre-financial year. And when we came into this financial year, we settled Bauna, we had to realize a large amount of our US dollar holdings. Those U.S. dollar holdings were in our Australian U.S. dollar accounts and had actually been deposited in those accounts at around AUD 0.90. So we did have quite a large realized gain. So that's where a lot of those FX gains came in. We also had $15 million of transition costs, which we incurred to enact and mobilize operational contracts during the transition and prepare Karoon to take over operatorship. So that figure largely represents us mobilizing and bringing things like service boats, various equipment and people into Brazil to prepare for operatorship. They were costs that were incurred before financial close. So they can't be capitalized into the asset. They're actually an expense that we had to write-off. So then we also include a $9.6 million settlement with Pitkin Petroleum, which was recently announced and also changes to the $6 million of fair value changes to our contingent payments to Petrobras. That just results from a slight increase in the internal oil price assumption, triggering a potential for slightly more contingent payments to be made. So we just used our internal oil price forecast for that. If we could just move to slide 9, please. So the intention here of slide 9 is to assist the market to understand the cash movements during the year. As I'm sure you all recognize this year was lots of tos and fros and lots of one-off and nonrecurring costs for the year as we settle into our first operating asset. As with the results, the graph includes some costs that will be nonrecurring during financial year '22. As you can see, the effect of the acquisition on the current cash balance was this taking us from $296 million down to $130 million in cash at bank. So I'll just start from there. Karoon received oil proceeds of $137 million with a further $34 million of oil sales receivables at 30 June. So that's the differential between the $170 million that we equate for revenue and $137 million of actual proceeds that were received during the financial year. Karoon incurred a $78 million cash cost production on Bauna. This is the all-in FPSO cost and related services to produce 3.1 million barrels. Karoon spent $21 million on its Portola and intervention costs. The majority of this was for long lead items and progress payments to suppliers. So we would expect to incur the remaining portion of our quoted development and intervention costs during this financial year. Exploration evaluation expenditure of $17 million, this number includes $11 million of Marina 1 drilling costs, which were invoiced but remained as payable at the beginning of this financial year. And then we had $6 million of various internal time rating on exploration and work program costs in our 482 permit in Western Australia, remaining costs in Peru and then some costs on Clorita in Brazil. Karoon had $7 million of other costs, which is a grouping of several items, including corporate costs, business development. It does also include some refunds of that payments in Peru and the refund of some security deposits in Peru. So when you see some of the numbers that we had a corporate cost or a forecast corporate costs of $15 million in the coming year, but you may see $7 million of corporate cost here because we received that refund and those security deposits back of about $7 million. That's where that difference is. And then we also had $11 million tax that we paid -- in total taxes that we paid. That's split between Australia, where we had an actual income tax payable on realization of foreign exchange gains, again, on those US dollars that we were holding in Australia. And also there's income tax installments in Brazil that we paid, which is just where we have seen tax regime where you pay your income tax, those installments ahead. So that makes up the $11 million. I'll now hand back to Julian to discuss further detail on our operational results.

Yes. Thank you, Scott. That's great. So if we could move to slide 10, please. So slide 10 addresses our production highlights and the strong performance in our Bauna operations. We had an average production rate between November and June of over 13,300 barrels of oil per day, and that reflected a 97% uptime excluding the scheduled maintenance, a 10-day scheduled maintenance on the FPSO. So 97% uptime, that's towards the high-end of the sort of range that we had been anticipating and reflects very good performance from the Bauna field. We've looked at this also from the point of view of the annualized decline rate in the 8 months of our operations, and that's around about 10% versus probably a little higher than we anticipated maybe between 10% and 15% and that's been achieved largely through some very careful reservoir management by the operations team and optimization of our gas. We are aiming to try and maintain a decline rate, which is at around about that 10% to 15% level, obviously, depending on reservoir response. And I would caution that we've so far only got about 10 months of production experience on the Bauna field. We're not seeing any surprises. As I said, I think our decline rate has been very good and very well managed. But I'd like to come out with more definite comments about the expected decline rate once we've really got through that first 12 months and possibly a little bit beyond that. So I'll talk a little bit more about that shortly. We have had a very, very strong focus on preventive maintenance to ensure that our operational uptime and our production rates remain reliable through into the future. We want to make sure that any backlog in maintenance is covered. And so we have taken a few extra days of downtime here and there, and we'll continue to do that through the rest of this year, as I said, to make sure that we've got long-term integrity on the FPSO. Scott has mentioned the marketing share already, and I will not address on that. We can move now to slide number 11. So the next 3 slides address our near-term growth portfolio in Bauna as well as our progress at Neon. So we took the decision in April to contract the Maersk Developer drilling rig to undertake the Bauna well intervention campaign. We expect the rig to arrive in the first half of calendar 2022 and the campaign should take around 4 months to execute. We anticipate an additional 5,000 to 10,000 barrels of oil per day production once the 4 wells that we're going to work over are brought back online and our cost estimates for this program sits at $110 million to $130 million, as we've mentioned before, that hasn't changed and that will be funded from existing cash and the ongoing Bauna cash flows. The planning work is going well. Our long leads, the first of those are expected to start being delivered towards the end of this year, but that is already going well. If we could now move to the next slide, number 12, please. So I've outlined the major decision that we took here in June, which was to sanction the Patola development program. That's drilling and completing and tying back to the FPSO 2 wells that will fit in the Patola discovery. That already sits, of course, inside the Bauna concession, and it sits only a couple of kilometers from the FPSO. The FPSO already has spare slots that we can tie these wells into. Our estimated cost for this program sits at $175 million to $195 million. That remains on track, and the program will be executed immediately following the Bauna well interventions. We expect the combined benefit of this program and the interventions to increase our production to over 30,000 barrels of oil per day by early '23 before natural decline starts to kick back in again. The facility has got plenty of capacity for the increased production. It's currently around 50% utilized on a total fluid throughput of about 35,000 to 40,000 barrels a foot per day. That includes oil plus water. And Patola, of course, will be funded from a new $160 million debt facility, and we'll talk more about that in just a minute. We can go to slide number 13, please. So slide 13 describes how we've initiated a further piece of work to reexamine the Neon area discovery. And our point there is to try and simplify the development concept and increase the resources, the resources that we can recover from that development. Together with that, obviously, looking at optimizing the cost profile of that development. The reservoir at Neon is reasonably well imaged on existing seismic, but it is structurally more complex than Bauna. And that's because of the nature of the salt and the way that, that salt creates the trap. The work that we've been doing, however, has been going very, very well. We're considering 2 alternative concepts at the moment. There's a stand-alone FPSO concept and there's a potential tieback to Bauna. Both of these concepts look to be feasible. And despite the fact that Bauna sits 50 to 60 kilometers to the southwest of Neon, we are seeing initial results there that suggest a tie-in could be technically feasible. We expect to make a decision on whether to drill a control well in Neon in the next quarter and that control well would be drilled at the end of the Patola program. We have an option with Maersk and that allows us to do that. So I think it's actually been growing extremely well, perhaps a little better than I anticipated to work on Neon. And I'm very hopeful that we'll get to a decision in the next quarter that says we will actually go ahead and drill that control well, but that's still subject to the ongoing work, as I mentioned. I'll now ask Scott to talk to slide number 14, which is about our new debt facility. Through with you again, Scott.

Thanks, Julian. So during the financial year, Karoon was successful in bringing a group of lenders together to support a new $160 million reserve-based non-recourse debt facility. The facility has originally been envisioned as part of an acquisition of Bauna and part development financing for Patola actually in interventions. The revised arrangement with Petrobras allowed Karoon to use its existing cash and avoid putting a larger facility in place and going through what would have been quite a complex completion going into the renegotiation of Bauna. Karoon managed to bring 3 of its original lenders together and attracting quarry to this new Patola development facility. We'll be using this facility for contingent payments for the intervention campaign for Patola. So it's effectively a nice ring-fenced facility, which can help support the future work we're doing around Bauna generally. We were very, very pleased to get the continued support of a group of high-quality global lenders and to have retained market competitive terms given the recent turmoil globally, particularly in oil markets and some lenders reducing exposure to the oil industry. The financing has a hedging regime, but 40% of [bank case] production in the first rolling 12-month period and 30% of bank case production in the second rolling 12-month period. Every quarter, we effectively refill that hedging facility. Now the conditions precedent of the debt are just being wrapped up now. So we expect in the next couple of weeks or the next few weeks, satisfied all the conditions precedent and put the hedging in place. So that debt facility will be completely wrapped up in the next few weeks. So we're pretty happy about that. I'll hand back to Julian now to go on with reserves and resources.

Yes. Thanks very much, Scott. As Scott emphasized there, it's a really good group of lenders, great to have some those big banks and Shell on board with our debt and looking forward to working closely with them. So if we could move to slide number 15, please. that outlines our reserves and resources statement as at 30 June 2021. A couple of things to note here. We've had a small positive boost in terms of reserves from the good well performance that we're seeing. And as I said, that well performance has really been due to very careful reservoir and gas lift management and hopefully will continue. The other main thing to note is the movement, obviously, due to the total sanction decision, and that's 14.7 million barrels at the 2P level, which moves from contingent resources to undeveloped reserves. Obviously, once we've drilled the petrol wells, those reserves will become develop, and we'll move forwardingly. So that's reflecting those movements. If we could move to slide number 16, please. So slide 16 outlines the progress that we're making on the strategic refresh that was initiated IP this year. Currently, that's nearing completion. We've had many engagements with the Board on this, and we have some elements still to finalize. It updates the corporate strategy that was put in place a couple of years ago and looks at our key objectives over the next few years following, obviously, taking on the operatorship of Bauna. Our goal with this really is to create a longer-term sustainable oil business, taking into current market. And based on our Brazilian producing assets and projects under development, obviously, with a focus we'll deliver very strong returns to our shareholders. The refresh is considering key operational and financial objectives, including operational excellence, and I can't emphasize enough our safe and reliable production is core to that, but also a very strict capital management as well as organic and potential inorganic growth options and there's a number of key focus areas that we're looking at. Sustainability, obviously, is a major component of that refresh, particularly our approach to communities and managing our carbon emissions. And the key outcomes will be shared with the markets in our market data will hold in late October '21. If we could now go to slide number 17, please. So slide 17 summarizes guidance for financial '22 -- financial year 2022 based on production of between 4.2 million and 4.6 million barrels and that equates to 11,500 to 12,500 barrels of oil per day, continuing, of course, the decline on our 2021 production. Our 2021 production that we saw, we estimated a decline rate of around about 10%. And looking ahead to 2022, we're probably looking at a decline rate or forecasting a decline rate that might be a little higher than that. And that's, as I said, because we're still getting used to the reservoir. We're still getting used to our production facilities. And I want to make sure that what we're targeting is something that we're confident that we can reach for that range of 4.2 million to 4.6 million reflects that range. Since our operating costs are largely fixed, and we're planning to continue, as I said, with the remedial maintenance program on the FPSO, this leads us to a unit OpEx of between $28 and $32 a barrel. That's a little higher than $25 a barrel we achieved during 2021 and obviously largely reflecting that decline in production. The other key highlight is that our CapEx largely to be spent on the production growth projects in the Bauna concession and you'll see that CapEx fits for those projects between $100 million and $135 million, that's quite a wide range in CapEx. And it's because the precise timing of the start of those operations is uncertain at this time since it is dependent on the arrival of the drilling rig. We do expect that in the second quarter of calendar 2022 and we'll be able to narrow that arrival window during Q4 of this calendar year once the current operators confirm their options or otherwise, that their intent is in rig. The rig currently sits in [indiscernible] and be mobilized by Maersk from there. As soon as we have that net narrowed window, we'll obviously come back to the market and inform you of what that looks like. If we could move to slide 18 now. Slide 18 provides a summary of the pack, and I'll just highlight a couple of those elements before finishing. So Karoon has undergone a fundamental transformation over the last 12 months. It's now a fully fledged oil producers. It's got a first-class team and a first class set of assets in Brazil. Our crude has seen an excellent entry to the global market, with sales across 3 different regions of the world, selling in the gross premium to Brent and attracting multiple bids for each cargo. We expect that demand for the Bauna crude to continue. Our growth projects are on-track for delivery during 2022 and into '23 with an expected doubling of our production to more than 30,000 barrels of oil per day by early 2023. Our cash and funding position is strong. We have a new debt facility that will see first draw in the next few weeks and we have continued strong free cash flows at current prices. Our refreshed strategy will be released at the end of October, and that will address the key areas of growth and how to continue to attract funding under the new exacting demands of investors for emissions abatement. Finally, I'd like to emphasize that Karoon offers the only pure oil production play exposure on ASX, which combined with a strong growth profile through our sanctioned projects, the potential of Neon and as well as inorganic opportunities in the Brazilian oil sector, we believe we create a unique and very compelling investment proposition. So I'd now like to finish with that. We have a couple of additional slides that sit at the end, 19 and 20. However, the reconciliation of our statutory impact to the underlying impact on slide 20, which covers the impact of the AASB 16 leases and provide a bit more detail around that. I'll let you peruse those at your leisure. And I'll hand back to Harmony for any questions, please.

[Operator Instructions] Your first question comes from Adam Martin from Morgan Stanley.

Just first question, just on the extra cost around the preventive maintenance. Can you just talk through what you're doing there, please?

Yes, no problem, Adam. We're doing a number of things on the FPSO. We've got some outstanding corrosion on pipes and pipes are the things that includes our hydrocarbons and I'm very, very keen that we do any remedial work we need to on those. So that's one of the key areas to go around the FPSO and ensure that, especially anything which is under pressure is looked at and replaced where necessary. As is true, you can appreciate the FPSO is quite a large vessel and it has multiple layers in that vessel that we need to go through. And we want to be very careful with that. We want to make sure we don't miss any hidden part. A lot of the pipes fit underneath cladding. So we have to remove some of that cladding in order to inspect the pipe work. And although we haven't got any issues at the moment, we want to continue that work, continue the inspections and where we find areas that need further remediation, we will do that work as we need to. We're also doing some other work, which is looking at our compressors. We've got a number of large compressors on the FPSO, which are Siemens compressors. And we're going through a piece of work at the moment to refresh that whole compressor fleet that we have and that will roll-through the first few months of this financial year. The work is currently ongoing. And I said, that will take a little bit of time to play-out. The FPSO at the moment is 7 or 8 years old, that it's been on Bauna. It's operating extremely well. We want to make sure that that operational performance can continue and that will require a little bit of extra maintenance. We took on the FPSO probably after 2 or 3 years when Petrobras had been trying to sell the asset and going through that process. So they haven't been as fully focused on the maintenance of it as we are -- which means that there are some of these remedial areas that we continue to need to address, but that's essentially what that comprises.

Okay. And just second question, just production impacts thinking about FY '23 when you bring in the intervention work. Is there sort of weeks where production is offline for some of these wells. Can you just talk through how that works, please?

Yes. So the intervention program will take about 4 months in total, we've got 4 wells that we're drilling, 2 of them were replacing the pumps and another one we are installing gas lift and there's a fourth one that we're opening up in New Zealand. So some of those periods that we're working on each well are on the order of 35-plus days. And during that period, the well production for that individual well will be down. So we expect to see the wells going progressively offline and then progressively coming back online through that period. When they come back online, it will take a few days to get them back up to full potential. And yes, so that has an impact on our overall production. And you can see that in the production forecast that we've got -- the range there it's quite a reasonable range, and it reflects an early mobilization to a late mobilization of the Maersk Developer rig. So in earlier mobilization, we see more of that well downtime, but we also get more of the benefit of those wells as they come back in, whereas a laser mobilization of the rig towards the end of the window, really, what we see is just the natural decline of the field through that period. So yes, that's what we expect to see.

Okay. And then probably just final question. Just can you perhaps talk through pros and cons. You talked about the 2 FPSOs for Neon. So one stand-alone or one time back in just maybe high level, you could talk through that. And then also, can you just remind us that 100% you're at and are you still looking to farm down or what should we assume if you go ahead at the 100% level.

Yes. The work on Neon has been really fascinating this year, I'm going to say, as you know, Karoon is trying to farm down this asset in the past and hasn't been successful. I was very keen taking a close look at Neon to analyze what the reasons were for some of that lack of farming success. And yes, the team has been looking at this. We've been looking at the subsurface as well as what the potential developments looks like. And the subsurface, it's got some uncertainty, some of those uncertainties still need to be resolved and they'll be resolved with a control well. And if we get to that positive recommendation to the Board later this year, primarily addressing the recoverable resource and also the outline of where and how we will need to drill wells into Neon. The surface part that's going on looking at the surface side of the development, and there will be a subsea development similar to Bauna, of course. But the key question there then is, are we able to tie back that crude to an extended pipeline to the Bauna asset? And if we're not, then what does stand-alone FPSO look like on really what on the reconfigured development plan, if you like. That work is still going ahead, but it's very encouraging on both sides. Both the standalone FPSO looks to be a very viable solution and very encouraging is the initial analysis, initial engineering work that is currently going on to take a look at potential to tie back. I'd really like to tie back because it helps with a number of things. It probably reduces some of the CapEx upfront, although you've got to spend money on a long pipeline and some pumping, et cetera. It does help to reduce some of that upfront CapEx. It reduces the dependence on further FPSO, and it overall reduces our operating costs. Our operating expense will be a little lower and not having an independent FPSO. And it will also help to lengthen the life of the Bauna field, we believe as well because you'll have more oil coming in, more oil for longer, that means we can produce through the FPSO for a bit longer. So it potentially has quite a lot of knock-on effect. It's still quite early days with that, but I find it really encouraging that we're able to look at these different scenarios, different concepts and take a view on taking those forward. We haven't -- I mean there's really just concept at the moment. We haven't taken any firm decisions on them. The first decision will be based on strong encouragement. If we feel that encouragement is still there, the decision there will be a recommendation that comes to drill that control well. And as I said, that will address a number of the key uncertainties we've got. At the moment, we are 100% in the Neon licenses, Neon and Goia. And in terms of farming that down, we'll take that decision about a control well, obviously, whether we want to farm down prior to drilling a control well or whether we want to farm on post control well. I think it is likely that we would look to bound that down at some stage, but it could be either before or after the control well as I've said. So there'll be more on that coming out in the next quarter. We'll provide a lot more details at the market on where that engineering work is pointing us.

Your next question comes from Gordon Ramsay from RBC Capital Markets.

Just a quick question on unit production costs. Clearly, going up next year as production declines and from some maintenance. I think the company has previously said the goal is to drop unit production costs below $20 a barrel in FY '23 once the Bauna intervention and Patola work is completed. Is that still the company's goal or target?

Yes, we expect those unit OpEx to drop well over $20 a barrel. We certainly, I believe, are on track to do that. And yes, with the Patola and interventions, additional production coming on in FY '23, yes, we should certainly see that. So look forward to that.

And then in terms of the FY '23 production costs or impacts, just to follow-on from Adam's question, the ESPs that are going to be replaced, are those wells actually producing right now? Are they shut in?

No, the wells are currently producing.

Yes. So we'll shut the wells in, obviously, when we do the replacement work. So there will be a drop in production from those wells for that period of 4 weeks or so for each well. And then obviously, we'll see the boost as they come back in.

Can you give a feel for the volume impact? I mean, obviously, FPSOs aren't working on those wells, they're producing less than the other wells that have ESPs in place. So can you just give us a feel for what might be the well impact from doing that?

Look, we've got ESPs in a number of wells, and they are still producing in the thousands of barrels per day, but we would expect to see a significant boost in that production with putting in an ESP for an individual well using a couple of thousand barrels a day. We'll see a significant production boost of several times that you want to bring the ESPs on stream. So yes, they have a significant impact. And the reason of course is because they improved the pressure profile through the well relative to the reservoir.

Got it. And just lastly, just on the hedging. I understand you need to complete the debt facility and it will be a condition precedent. Is there a goal just to put a floor in place or will there be a floor and ceiling on the oil price?

There'll be a flooring and ceiling, but I'll hand it to Scott to talk about that in a bit more detail, Gordon.

So yes, look, there is a floor, it's our intent to minimize the downside. That's the intention of the hedge. In order to pay for that floor, we will sell off the ceiling. Now I can't give you the number on the floor, we're in the middle of kind of discussing it. But on our bank case, we have a $50 oil curve, which is actually just getting raised at the moment as part of the redetermination. So it's more like sort of $52 to $55. So we want to protect that level, which means we'll try and put the floor around the $55, maybe a little bit. And then the ceiling that we sell needs to be at a level where we can take most advantage of the oil price for the contingent payments to Petrobras. So the level that we target for the ceiling is above $70. So that's kind of gives you a little bit of a range sort of in the $50s for the floor and hopefully, the higher $50s and also, hopefully, the higher $70s for the ceiling. Recent movements in the oil price are helpful for that, of course. And hopefully, we'll get the final CPs wrapped up in the next week or 2, and then we'll be in a position to put that hedge in place and protect those levels.

[Operator Instructions] Your next question comes from Adrian Prendergast from Morgans Financial.

Two of my questions have already been asked. But just maybe one more just on the outlook for that decline profile in '22. And Julian, you commented that you still want to get to beyond 12 months and you're obviously still building on that operatorship understanding of the field. But is it really still studying the reservoir well performance or is it more you just want to get confidence past that preventative management program?

Adrian, look, there really are a couple of things. You're right. One of the elements is certainly the preventive maintenance program and understanding some of the impact of that. But what we've seen on the FPSO is there's quite a fine control around some of the wells and we've been able to optimize that quite well during FY '21. I want to feel confident that we're still able to do that as we continue with production. I sort of feel that 8 months isn't quite enough to make a big 12-months forecast, which should be very bullish. And so we're comfortable with that range of 4.2 million to 4.6 million. It is based on uptime, which I feel is very reasonable between 92% and 97% uptime. Those ranges across FPSO fleets around the world would already be quite strong uptimes compared with a number of different areas. So although we've managed to achieve something around 97% for our first 8 months as a producer, yes we've been a tad more conservative than with using that range looking at the future.

Your next question comes from [ Fred Willard ] from [ Samuel Terry Asset Management ].

Two questions from me. The first is, can you explain the relationship you've seen so far between the prices that you have achieved, which you said have been at a premium to Brent between the prices you've achieved and the Brent actual price that we can see on Bloomberg. Second question, can you talk us through the provision for restoration. What you expect to end up having to spend? I can say the numbers you've got in the accounts there. Just talk us more through those numbers because they are pretty material liability in the fullness of time and how the discount rate is working. And yes, just talk us through what cash you expect to pay and how you're working through that process.

I'll actually hand both of those to Scott. Scott, is that okay?

Yes, no worries. Fred, so the first question, what's the relationship between the oil price that we receive and Brent. So maybe the best way to explain that is that when we sell oil, the process starts about 6 weeks out and effectively a refiner comes to us and may bid Brent and ICE Brent plus price. So for Karoon, the best price that we've achieved is about $2 premium and a refiner or a buyer just looks at the delivery month. So they forecast, so for now we might be selling a November cargo or it's lifted in October but delivered in November. They will simply say we will pay ICE Brent plus x dollars or x cents. So the range of that is between, I think $0.30 and $2 for us. And effectively, we look at the shipping costs. We look at the time to shift because it does move with the forward curve. There's a backwardation as a result of the forward curve, and we look at the premium. So for example, if you sell something to Asia, the Asian price needs to be ICE Brent plus $1 more than selling to somewhere like Europe because Europe, you're shipping between sort of 15 and 22 days, where Asia can be 45 days of shipping. So the end answer is simply that a refiner will beat ICE Brent plus or they will beat date to Brent plus, which we then convert to ICE Brent based on the relative values on each of the forward curves. So it's basically as simple as that. It really is just a premium to data or ICE Brent. We just look at those. We convert everything back to ICE Brent for our calculation and then we include logistics and time costs, and that's how we work out who wins each bid effectively. Now in terms of the forecast restoration costs. So those numbers are really calculated. There's 2 numbers. There's the number that we keep internally, which is calculated from using a slightly discounted forward costs, which could be anywhere from -- we have independent experts, which have assessed that range could be between, I think, $120 million and $204 million, I think, is the sort of rough range. In terms of the submissions that we make for the government in Brazil, they use higher end of that range for their assessment. Internally, we effectively use like a [indiscernible]. We use a mid-case of where we think that restoration cost will be. We have used 2 sets of independent experts as well as our own internal cost analysis to come up with what we see as a reasonable range. And I think the number we're carrying $164 million, I think that's a reasonable mid case. It probably comes down to an operational question more than anything else. But based on all of the information that we have and the assessment of the average cost of abandoning an individual well as well as government regulation around which parts of the facilities will be removed and which parts will not, that put alongside the FPSO costs, which go to Altera & Ocyan, but there is a decommissioning of the FPSO as well, which we have a small proportion of that cost. So we do do a full evaluation of the cost and then it's discounted at a very low rate of only 2%. So we see the number that we're carrying as a reasonable and realistic costs for that end abandonment.

Thank you. There are no further questions at this time. I'll now hand back to Mr. Fowles for closing remarks.

Yes. Thanks very much, Harmony. Look, I think the result reflects quite a big transformation for Karoon through the year, as I have said, some of the numbers are bit up and down. We've got, obviously, a conversion to US dollars in terms of our currency. But overall reported, I think, a very strong underlying net profit after tax and I think that reflects the strength of the operations and the quality of the assets that Karoon has taken on. I think we also are looking at some very strong near-term already sanctioned growth projects and I'm gaining some confidence that Neon is going to be something that we really want to take forward to control well in the near future. So I think that all of that points in the right direction for Karoon near term and longer term as well, of course. So I guess, lastly, I'd like to thank our Board, obviously, and our investors, all of our contractors and other stakeholders for their confidence in Karoon's management. And I do look forward to continuing to deliver and grow the company during FY '22. I'll say one last thing, which is a big, big thank you to Scott Hosking for his many, many years of absolutely stellar service at Karoon. Scott has been a stalwart of the company. And I'd really like to see a big thanks to him for easing my transition into the company, making things smooth for me and also for a tremendous and professional handover with Ray Church. As I said, Ray starts shortly. Scott, a big thank you to you, personally, a big thanks as well. And I wish you all the best in the future. So thank you.

Thanks, Julian.

Thank you. That does conclude our conference for today. Thank you for participating. You may now disconnect.