Karoon Energy Ltd

Welcome to the Careering Energy 2022 Full Year Results Conference Call. All participants are in a listen-only mode. There will be a presentation followed by a question and answer session. If you wish to ask a question, you will need to press the star key followed by the number one on your telephone keypad. I would now like to hand the conference over to Mr Julian Fowles, CEO and Managing Director. Please go ahead.

Yeah, thanks very much, Rachel. That's great. Good morning, everyone, and welcome to Karun Energy's FI 2022 results webcast. My name is Julian Fowles. I'm the CEO at Karun, and I have with me Ray Church, our CFO, and I'm Diamond Investor Relations. Earlier this morning, we released our FI 2022 results and annual report to the market, and we're now going to talk through the presentation that we released with those announcements. So going to that presentation and noting the disclaimer on slide two, I'll start with the overview on slide four. FY 2022 was our first full financial year of production operations, which is important to bear in mind when comparing with our FY 2021 results. And you'll see some comparisons throughout our presentation, and it's important that you bear that in mind. The context for our fourth slide lies in the strategic refresh that we presented to the market some 10 months where we highlighted a number of strategic themes. Within those themes, of course, we continue to emphasize safe and reliable operations, which really is what underpins our business. We had a number of safety incidents during the year, which is disappointing, and I'll touch on those in more detail in the next slide. Fortunately, none of those were serious incidents. Reliability of our facilities has been outstanding, with over 99% uptime, excluding scheduled shutdowns. And this is reflected in our production performance, where we achieved just above the top end of our guidance range. This production performance plays through financially as well, where we have not incurred any significant costs associated with equipment failures, partly due to the proactive maintenance programs we've put in place since assuming operatorship. Our growth activities are also well underway, with the first two wells of the Boehner work-over sequence already completed and work started on the third. The petroler development is moving forward as planned, and we're progressing the NEON drilling campaign preparations. We continue to actively pursue potential M&A opportunities, where we're taking a very disciplined approach with the application of strict screening criteria. We outlined and progressed our climate targets at the strategic refresh last year, and those are to be carbon neutral on our existing operations and net zero by 2035 on scope one and two emissions. And we also entered four new social and environmental projects in Brazil. We finished the year in a robust financial position with cash of nearly $160 million and undrawn debt of $180 million. This provides total liquidity of almost $340 million, and Ray will touch on the implications of this a little later on. Moving to slide five, this outlines our HSSE performance in a little more detail. As mentioned, we had four lost time incidents, and although each one of those was relatively minor, it's still a disappointment to us where we emphasize so much our HSSE and safety performance in our operations. Each incident was investigated thoroughly through a root cause analysis, and lessons learned have been thoroughly applied. Of course, COVID-19 was still running through the world during FY2022, and although we saw an uptick in cases in the second half of the financial year, most of those cases were mild, many of them were asymptomatic, and none required hospitalization. And due to the continued application of our COVID-safe protocols, our production has not been impacted in any way by COVID. I'll now hand over to Ray to go through the financial results in more detail.

I'm on slide seven. I'll start with the financial highlights for the year on that slide. As you can see, the business has a strong performance in the year with revenue growing by – sorry, I think we're behind on the slides. Could we go to slide seven? The revenue grew by 125% to $385 million, while unit production costs have remained stable to deliver an underlying EBITDA growth of 235% for $205 million. Conversion of EBITDA operating cash flow was high, with temporary effects of a few weeks' growth of inventory and receivables due to liftings timing in June and July and hedge premium outflows. The establishment of $210 million of new debt facilities combined with these strong cash flows meant we closed the year with $337.7 million of liquidity. And I'll talk to each of these in more detail on the following slides. Moving to slide eight, just a few points to note on the income statement. Revenue growth was driven by two contributing factors. The increase in sales volumes, which was driven by reliable production, and three more cargoes delivered in a year generated $97 million of the increase in revenues, while crude price delivered the remaining $117 million of revenue growth, for a total increase of about $214 million. Realised prices for ballon-approved improved from $58.90 to $84.74 per barrel, and this was supported by global price increases, but also as ballon-approved is now sold to five markets. OPEX was $25.36 per barrel for the year, largely unchanged from $25.11 last year, and better than expectations as unplanned maintenance items, which had been budgeted for, were not required. as a result of the efforts in reliability of production mentioned by Julian. Key movements year on year in corporate exploration and other costs relate to an additional $1.6 million of business development costs, mainly associated with the potential at-length transaction, and $3.4 million of corporate and share-based payment costs in Australia and Brazil. Net interest and finance costs include $3.5 million of debt facility costs, mostly related to to establishment and facility fees, mainly associated, sorry, up from $1 million last year. And $2.4 million unwinding of discounts in the bono restoration provision, up from $1 million last year. The effective tax rate is approximately 37%, as the Brazilian tax rate of 34% is impacted a further 3% by non-deductible share-based payments and Australian costs. Fortunately, as the US dollar to Brazilian radar exchange rate ended the year as close to the commencement of the year rates, we have only minor FX adjustments affecting income tax expense this year. The resulting underlying net profit after tax was $89.6 million compared with the restated FY21 underlying impact of $21.4 million. Moving to slide nine. Given the prevailing consensus oil price outlook through 2026, which is above the contingent consideration oil price cap of $70 in all years, continued consideration for the boner acquisition is now fully priced. So the liability with interest is now recorded at $298.3 million, including estimated interest. The income statement impacts have been removed. from underlying EBITDA and underlying NPAT to this item. And it's worth noting that if future oil price expectations fall, any decrease in anticipated continued consideration would then be recorded as a non-cash item on the income statement. Looking at cash flow on slide 10, after adjusting for AASB 16 lease accounting treatment to include the interest component of FPSO lease payments, Bayona Operations generated $114 million of cash, which has effectively funded the deferred consideration payment, the fit and settlement from FY21, and capital costs to date on the Workover and Patola Development Program. With the initial draw and establishment of the new RBL Depth Facility, we completed the year with $158 million of cash, up from $133 million last year. And staying with cash on slide 11, the undrawn debt facilities plus cash provides the business with $338 million of liquidity at year end, which provides financial flexibility to meet the remaining CAPEX commitments and contingent consideration payments. The diagram to the left shows the tenor of the debt facilities. Moving on to slide 12 and guidance for FY23 now. Production is expected between 7 and 9 million barrels for the year. This takes account of the latest completion timing for the Boehner Workover and Polar Development Program, which Julian will cover shortly. Full year unit production costs are expected to decrease to $15 to $20 per barrel as production increases and costs remain largely fixed. Other operating costs are expected to increase to $23 to $25 million, of which approximately $2 million is non-recurring. Main contributors to this are $1 million caused by inflation, which is about 12% in Brazil and 6% in Australia, $3 million full-year impact of FY22 staff changes, $2 million in IT cybersecurity and systems, and $1 million of... office and travel costs now necessary post-COVID. Business development, share-based payments and NEON studies are expected between $12 and $14 million. This includes 2 million additional NEON studies which are non-recurring. Baona work-over and Cotolla's knowledge costs are expected between $205 and $240 million, primarily due to the impact of higher diesel costs and delays at Baona, which Julian will talk about further. And Neon Evaluations, assuming two control wells, are expected between $65 and $75 million, given the current inflationary environment and with not all contracts yet locked in. On slide 13, we provide a reconciliation from underlying statutory NPAT and EBITDA. Changes in contingent consideration and fair value of cash flow hedges have been removed from the underlying result. Additionally, restructure costs and FX gains from restatement of US dollar currency held in Australian entities have also been removed, and this produces the statutory net loss after tax of $64.5 million. Thank you, and I'll pass back to Julian now.

Yeah, thanks very much, Ray. That's pretty thorough going through on those numbers. I'll go through in the next slides our strategic progress in a little more detail and talk a bit more also about how we're going on the intervention program in a bit more detail also. So we can go to slide number 15. That outlines what we see as being the important drivers that impact Karun and our operating environment and which will continue to influence our future, both from the perspective of how we manage risks, but also how we screen opportunities. During FY 2022, we saw a sharp increase in the price of Brent crude oil, against which Bauna crude is usually benchmarked to well over $100 a barrel during the first half of this year, reflecting growing demand, a limited supply response, and falling inventories. Demand for Bauna crude itself continues to be strong, as Ray mentioned, reflecting these global supply and demand fundamentals. It's worth noting that we are seeing a great deal of volatility in oil markets, which is likely to continue for some time. with swings of plus or minus 5% on a day-to-day basis not uncommon. This reflects the opposing forces of a post-COVID demand rebound and fears of global recession. Karun's belief is that oil demand will continue for many years and that that remains our underlying thesis. We do see inflation in some aspects of our business, primarily the cost of fuels and the impact of CPI in existing contracts, and Ray has already outlined the impact of some of these. If we can move to slide 16 now, this summarizes progress against our strategic objectives where we aim to create a strong foundation for Karun from which to grow. As well as delivering our base business, we continue to pursue M&A, and you've seen that during this financial year. We also attained our goal of being carbon neutral for scope one and two greenhouse gas emissions for our FY 2021 operations, and we'll continue in that vein for FY 2022 and going forward. The board has committed to considering returns to shareholders once our development projects are closer to completion. If you go to slide 17, this details our operating performance on a month-by-month basis. In the two graphs on the left-hand side, you can see the very high facilities uptime, but also the gradual decline in field production on the lower graph. March production in this graph you'll see was impacted by eight days of planned maintenance, while in May and June production was impacted by the intervention activities. We continue to actively manage the natural field decline through active field and process plant management, an important part of which is the application of a thorough maintenance plan, which is now well established and going well through our FPSO operator, Altera Oceans. Altera's parent company recently announced that they were entering a structured Chapter 11 process, and we have received assurances from them that there will be no impact on our operations, with the FPSO joint venture with OCEAN ring-fenced from their restructuring. Slide 18 goes into a bit more detail on the intervention and patola programs. Work on the first two wells is complete, with the rig now starting to conduct the third intervention, which is installation of a new electric submersible pump in well SPS92. Results from the first well PRA2 are encouraging, with sustained stable production now at around 4,000 barrels of oil per day versus 1,900 barrels of oil per day prior to the intervention. Gas lift has been installed on the second well, SPS56. and that well is now ready to be brought back online. We should see initial results during the next week or so. We're targeting an incremental 5,000 to 10,000 barrels of oil per day from the intervention program, and expect that to be completed in Q4 this year. The patola development program will follow, with two new wells to be drilled, completed, and tied into existing slots on the FPSO. The equipment for patola has already started to be delivered, and that project remains on track for completion in early calendar year 2023, and is forecast to bring in an additional around 10,000 barrels of oil per day prior to the onset of natural decline. If you move to slide 19 now, that provides an update on the costs and schedules for the interventions and patola programs. Although both programs have been fully contracted for some time and as such are not subject to the same degree of price inflation that we see in some other projects, both projects have been impacted by the cost of diesel, which has increased significantly as a result of higher crude oil prices. In addition, the intervention program itself has seen operational delays of around about three weeks. due to exceptionally poor weather during the PRA2 workover and a cyclone last week, and a slower-than-planned anchoring operation on SPS56. Combined with the diesel cost increase, these push the estimated Bona intervention costs to $135 to $145 million, up from the $110 to $130 million communicated previously. The impact on Petola is an increase of to 180 to 205 million, up from 175 to 195 million previously, as Ray has touched on. The intervention program started with the mobilization of the rig to Bauna. The rig itself arrived towards the end of the original two-month program window, which was some four weeks later than we had originally planned when we were looking at forecast 2023 production. Combined with the three weeks delay outlined above, This has the effect of pushing back the bulk of our expected production uplifts by around about seven weeks, with a consequent reduction in the initial FY23 production forecast we made, which was 8 to 10 million barrels, bringing that to 7 to 9 million barrels. The impact is outlined in slide 20, as I mentioned. The additional part to this, of course, is the impact on our production Our unit operating costs, where we see these costs dropping significantly below $20 a barrel during FY2023, largely as a result of the production uplift that comes over a fixed cost base. Slide 21 provides an update of our progress at NEON, where we sanctioned the drilling of up to two control wells during FY 2022, subject to the receipt of still ongoing required regulatory approvals. These wells will primarily target volume and potential recovery uncertainties. We have a number of potential development concepts for NEON, which in the case of control well success, we shall be able to progress through concept select during 2023 with a potential decision to enter feed in late 2023 or early 2024. There are potential upside opportunities at the Goya discovery as well and other prospects which will be partially de-risked by NEON control well success. And these have the potential for future tieback consideration in the case of a NEON development. Slide 22 outlines our approach to potential M&As. We are, as highlighted previously, primarily focused on Brazil, but we also evaluate the relative value propositions of potential opportunities in other jurisdictions where we feel these could potentially compete with the opportunity set we have in Brazil, considering both above-ground and below-ground risks. It is important to emphasize that we are taking and continue to take a very disciplined approach to M&A, as you would have seen from our recent withdrawal from the Inalta Atlanta process. and any potential acquisition is balanced against potential returns to shareholders. Moving to slide 23, this summarizes our progress on climate and social projects. I would like to highlight that today we have released with our annual report our first standalone sustainability report, and I hope you find this report informative. We have set climate targets involving achieving carbon neutrality across our operations and a net zero target by 2035, both on scope one and two emissions. Our first priority, of course, remains to reduce and avoid emissions wherever possible, and we have implemented a number of projects during 2022 to achieve this. We also entered two carbon offset purchase agreements and are actively pursuing investments in high-quality carbon sequestration projects with social benefits, with other potential partners in Brazil and elsewhere. A social program is also in Brazil, expanded in FY 2022, with four new voluntary projects focused on education, sustainable economic development and biodiversity. And these are outlined in more detail in our sustainability report. Slide 24 presents a summary of how Karun is positioned to deliver on our promises. And I would highlight some key elements here. Firstly, we have significantly mitigated the field decline rate that we saw on taking over operations at Bona. Also, our intervention program is underway with positive results from the first well, the second well ready to be brought back online, and the third well already underway. With that program continuing to target a production increase on the order of 5,000 to 10,000 barrels of oil per day in aggregates. The Petola project is also on track and is targeting a further 10,000 barrels of oil per day uplift. We are actively pursuing attractive M&A and taking a disciplined approach. And finally, I would like to say Karun is in a solid financial position with a robust balance sheet, and we have accessible debt financing. We are, of course, experiencing strong cash flow generation at current oil prices. and that is really helping to bolster our balance sheet relative to where we had expected to be at the time when we took on the operations. Lastly on this slide, I would like to note that the Board intends to consider returns to shareholders following completion of the current Operational Investment Program in FY2022. FY2023, apologies. Finally, I'd like to thank our team at Karun for their hard work and dedication in delivering our results for FY 2022 and the work that continues to go forward in Karun's transformation and growth. Thank you for your attention and I'll now hand back to BRR for any questions.

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're on a speakerphone, please pick up the handset to ask your question. Your first question comes from Dale Coders with Bear and Joey. Please go ahead.

Morning, Julian and team. I was just wondering, firstly, on the second well, if there was any extra comments you could provide that this is a second work over well in terms of how it's gone relative to expectations, if there's been any challenges with production intervals or any early indications of flow rates. Anything else you can say really?

Yeah, thanks Dale. I think overall what I'd say was that while SPS 56 is that it went, in terms of the intervention itself, it went as planned. We found what we expected to find when we re-entered the hall. Everything was in the right place. And the operation of installing the gas lift mandrel and the various valves and lines that are associated with that, all of that went very smoothly. We have connected that well up. The new equipment in that well has been connected up. And we're currently completing, I think we've probably just completed an offtake at the field. And we will be following that now with bringing that well back online. In terms of what we expect to see from the well, I don't really want to put any numbers out there. I'm happy to talk about overall numbers from the interventions. it's been an installation of gas lift which is different to what we did in the first well where we installed a new electric pump and obviously with that first well we actually have probably slightly exceeded our expectations. The second well I think it remains to be seen the results of that. We would expect to see I think a very positive result from that well once we bring it online given that that well has never had any form of of secondary recovery installed in it. So, yeah, the result remains to be seen. I expect we'll see that, as I said, over the next few days to a week. It'll probably take two weeks or so for that well to completely stabilise and for us to get the operations around the gas list at the optimal settings.

Okay, that's good. And then just secondly, I guess on the capex increases, particularly around the final workover programme, is it fair to assume that that capex increases more than just diesel costs? It's also taking into account rigged day rates with the three-week delay?

Yeah, absolutely. I mean, we've got our contracts that are all set and there's not really any scope for those contractual rates to change. Where we do get affected, of course, is if we spend more days on our operations, we obviously have to pay those day rates for those days And in the context of the Bona intervention operations, we have about 20 to 21 days of additional time that we spent. Some of that is weather, and up to about two weeks was on anchoring operations at SPS 56, where we really encountered previously unforeseen substrates. that led to a number of operations taking longer than we had expected.

Okay, so that also remains, I guess, the key risk for the program going forward, that if you continue to see delays, the CapEx might just tickle up a little bit going forward.

Yeah, look, we've still got contingency in the programme. We've allocated some contingency through the weather and anchoring programme delays, but we haven't allocated all of the contingency as yet. So there is still some of that left there. However, if we do experience further delays, then we would expect to see that roll through into costs. Having said that, the lessons learned from SPS 56 anchoring have been applied in SPS 92, and I have to say that that operation has gone according to plan. Okay. Thank you very much.

The next question comes from Mark Simpler with the University of Marquee. Please go ahead.

Yeah, hi, Julian. Just, I mean, I guess the question with the much better decline rates than when you took over the asset and I guess that went into your reserve bookings. Do we see the prospect for potential reserve increases with what you've learned about the reservoirs?

We're doing work on reserves at the moment, Mark. I think we outlined that somewhere in the announcement, and that work is still ongoing at the moment. What we'll want to see are the results, I think, from a bit more of the intervention work before we're prepared to put a revised statement out there. So that work is ongoing, and at the right time, we'll come to the market with, if we need to, if there is a revision, we'll come to the market, obviously, with a revised statement. reserves and resources statement. Certainly, I think from the point of view of production, it is encouraging that we've been able to mitigate the decline rate. Some of that is due to how we are operating the wells, and some of it is also due to how we operate the plant itself.

I guess when we think about the production gardens, I think it's a smidge to rely on some of the of indicative stuff you put out in the past but i guess we should think about that some of that is just the timing of the interventions taking that long because i mean certainly looks like first intervention well i think we just said to dale's questions maybe gone a bit better than expected obviously saying an extra thousand dollars a day versus where it was when you released the quarterly

Yeah, look, PRA2 certainly has been performing very well, that first one. And I'm hopeful, certainly, that the other wells will also outperform, but that remains to be seen. I think it's certainly very positive, the result that we're seeing so far. So, yeah, just... Keep your eyes glued and over the next few weeks we'll see not only 56 but then 92 come in as well at some stage.

I'm just trying to get a feel for the possibly relative conservatism of production gardens. Should we assume a level of conservatism on both timing and results from the workovers has gone into that garden?

So on the timing, I think there's a couple of things that are important around that. The timing is what it is, right? The rig was mobilized when it was, and we've experienced some delays. So that naturally pushes back the bulk of our production uplift by seven weeks. I mean, that's just a natural consequence of doing that. And, of course, a large piece of that will be the patola work, which is now going to occur later than we had originally planned. I mean, is that really significant? Not in the grand scheme of things, but in terms of the annual reporting and annual forecasting, obviously there are various cut-offs there, and if you push things by seven weeks, You can probably do your own calculations on that, but that adds up to the bulk of the change in that production forecast that we've put out. We do round numbers. If you're thinking of conservatism, we do round numbers, and my preference is always to err – towards rounding down if that is suitable. But, you know, obviously we stand by the guidance and I think the guidance is pretty solid for the next 12 months.

Perfect.

Thank you.

Thank you. Your next question comes from Nick Burns of Jardine Australia. Please go ahead.

Oh, yes, hi, and thanks for taking my questions. Two from me. First, just on your production performance expectations from the upcoming campaigns, you've done a great job in reducing the decline from existing wells from 15% to 10% per annum. Can I just ask, first of all, what you've done to achieve this lower decline rate? And I guess then looking forward, what decline rate we should be expecting after the new wells are brought online? Will there be any plateau production, particularly from the Patola wells or should we expect them to decline in that 10% to 15% per annum range pretty quickly? Shiv?

Yeah, hi, Nick. Good to speak to you. Look, I think in terms of what we've done to moderate the decline rate, we're actively managing the field in a way that the previous operator probably was not inclined to do. It was a much, much smaller process. portion of Petrobras' portfolio. And for us, of course, it is our portfolio. So we've got some very active management of the wells, managing the essentially The pressure differential between the wells and the processing plant and the facilities on the processing plant. And in one or two instances, just making a difference of one or two bar in that processing can make quite a bit of difference to the stability of production from a couple of the wells. So we're very active in managing that. We've also, of course, got high levels of uptime in our facilities. And we've done that through ensuring that we've got a high level of redundancy in those facilities where that is available. So we haven't gone out and invested massive amounts of new capex, of course. But we've just ensured that everything that is available on the FPSO is functioning and available to us should we have any production disruptions in one of the plants. If we can move that to the second production train, we can move some elements into that train, for example. So we've spent a lot of time doing that, which has helped enormously with plant uptime and also stability of our production. A couple of other things we've done as well. When we do have wells that go down, we now are able to restart those wells much more smoothly than we were able to in the past. And that, again, is due to some modifications we've made in the plant and also in the wells and the flow lines coming from those wells. So that's reduced our restart time from what was previously 12 to 24 hours now to just a couple of hours if we have those wells with any interruptions. So some good things I think they've got on there. And that work continues, Nick. It's not something that we think we've done and we're going to sit back. There's an ongoing program of continually making sure that the kilometres and kilometres of pipelines which exist on the FPSO are in the best shape possible. We've also ensured that we have very good uptime availability on the compressors and our energy generation on the FPSO. We've refurbished and replaced a number of those big compressors over the last 12 months and that ensures again that we've got redundancy in that system and that the units that are operating at any time are in the best condition they can be. That was probably the first part of your question Nick.

What was your second one again? Just around where from here are you expecting any plateau production particularly from the Cattalla Wells and how he's picked the world to perform. Cheers.

Yeah, so as you suck harder on the wells, and essentially that's what the pumps and the gas lift will be doing, as you suck harder on those, I expect that we'll see an initial rise in our decline rate. And the same will be true at Patola, where I think we'll get initial flush production that will probably be quite high. And then we'll see a rapid initial decline before that stabilizes. So I'm expecting at Bauna that we will probably kick to a higher decline rate than 10% initially following the intervention work. And at Patola, I'm not sure where exactly we'll see the decline rate initially, but I expect that to stabilize back down to that sort of 10% to 15%. per annum range and probably within a matter of months the plateau period for both the intervention work and the Patola development is going to be short on the order of a few weeks I would expect. So, yeah, we'll kick reasonably quickly back into decline. As I said, the decline will be probably larger than we have experienced so far, but that will be temporary before we stabilise back down to a 10% to 15% range.

Got it. That's very helpful. Thank you. And just a question around your upcoming Neon Well campaign. Can you talk through what information you're looking for here What results at control well one would give you the green light to go ahead with control well two? And what constitutes success? And will you flow test the well? Thanks.

Yeah, the last part first. We're not intending to flow test the well. We've got a great flow test result from Echidna 1 at over 4,000 barrels a day of light oil. So we're not intending to do another test. We think we have that reasonably well calibrated. Yeah, the first well in the control well campaign will be targeting reservoir quality, the lateral extent of reservoir, as well as the oil-water contact in the fields. We have an inferred oil-water contact from pressure and log data that we took in the first well, but it'll be interesting to make sure that we can tie that down a little bit more. The overall objective with that first well is really to narrow the range of contingent resource that we see at NEON. The current range there is quite large, and at the bottom end of that range currently, we see that as being quite a challenging volume for development. I would like to make any development concept more robust by really improving certainly the bottom end of those numbers. There's a little bit of upside potential as well that we may be able to realize in the overall campaign, but primarily the first well will be targeting a narrowing of the volume range. If we do see that success with the oil water contacts around where we think it is today and with reservoir quality that we think will potentially lead to good potential development well flow rates, then that, I think, would probably be sufficient good news for us to go ahead with the drilling of the second well. Having said that, there's always quite a bit of uncertainty when you're drilling wells like these. And we'll obviously be spending... a number of days, probably a week or so, evaluating in extreme detail the results that we see from the first well before we're in a position to make that decision on the second well. So don't expect us to come out with an announcement that the well has reached TD and on the same day we'll make an announcement. Unless that result of course is very positive, it'll take us a few days to evaluate. That's how I see those things playing out.

That's great. Thank you. Cheers.

The next question comes from Adrian Prendergast with Morgan Financial. Please go ahead.

Yes, thanks, Joanne and Ray. Just a further question on me. I understand that you're obviously not in feed yet and just planning to drill one to two control wells. But given the project is just as much an engineering challenge as a drilling one, are you planning to do any further work on that front in terms of the option to tie it back? Or is that more something we should look forward to next year?

We've got work that's ongoing at the moment, Adrian, on the engineering concepts. And those are, I guess, focused in two or three key areas. One is looking at flow assurance for a potential tieback. That will probably be... One of the constraining factors, if we can't get good flow assurance, in other words, that we can flow multi-phase from Neon to Bona, we really need to tie that down. So there's work going on there with a couple of international contracting companies, and that work is progressing very well at the moment. I would say that the Neon fluids um would seem to be quite conducive towards uh multi-phase flow in in under the conditions that we see between neon and karun in that it's a very light oil it it does have gas in it of course which which can complicate things but it doesn't have any particularly nasty elements it doesn't have a high co2 content it doesn't have some nasty H2S. And it also is very, very low in wax, which, of course, would be a big consideration in that flow assurance. There's another area of work that is going on, which is looking at the facilities requirements. And that really has two strands. One is looking at facilities requirements on board the Bauna FPSO, the Sedage d'Etagerie. So what would we require there? Were we to tie back neon into that facility. But the second one of course is looking at what would a standalone facility look like. I'd really like to have a fresh, really a blank sheet of paper and if we got the ideal, what would it look like? And then we can start to understand what compromises we may need to make from a standalone relative to other potential options for those concepts. So there's currently two or probably three different concepts that we're looking at, and the engineering work that is going on is focused in those areas that I've just alluded to.

That's really helpful. Just on Batola, and you've already given a lot of really good, candid insights into how the program's going, obviously, and still tracking to that early calendar, 23, just pushed back a few weeks, but... Really, just how you're seeing risk and progress across some of the key items like the new wellheads and any comments around that in terms of risk around schedule?

Yeah, great question. We had the opportunity to take a board of directors to visit Technip FMC, which is one of the major contractors. for the Patola programme. They're building the Christmas trees and all the associated equipment and subsea equipment and they'll be obviously doing the installation as well. Progress on that equipment is all on target. We've started to see some of the delivery of that equipment. It was great, in fact, to be able to stand in the yard at Technif FMC in Rio and put our hands on one of the patola wellheads. which is obviously going to be installed in the not-too-distant future. Just to actually feel it and touch the steel, I've got to say it made the project very, very real for everyone who was fortunate enough to have that trip. I've got a great deal of confidence, I think, in the relationships that we have with our major contractors and their ability to deliver the program elements that we need. We've been very fortunate on this in that we started our contracting procedures over two years ago now, and that has played very well ahead of... the current supply constraints that we're seeing in some other projects around the world, we've really been able to get ahead of that. So I think that has played well for our program.

That's very helpful. One more just from me, and it's probably not that material, but just more a modelling question. Just at Bayona, the years between when you're not doing work over or intervention type work, just the typical sort of maintenance capex levels, just year to year, what you would expect?

That's a great question, and I don't have the number off the top of my head for that one, Adrian. I'll ask Ray. I'm not sure if he has it either.

I know we have a – if I just look at the two years we have with us, we've got around a $9 or $10 million minimum burn rate on CapEx, but that's all. That's kind of all kinds of minor CapEx items. The maintenance program, most of that's expense and goes through P&L. That shutdown that happens in March –

At some stage there will be, depending on the performance of electric submersible pumps, there's still plenty of crude to produce. And those pumps typically have a failure rate after about two and a half, three years or so. So it is, I mean, we're, I've got to say, our guys are under strict instructions to deal with with those pumps with the gentlest of hands and the greatest of TLC, which is why we're not ramping up those pumps to their absolute maximum rate, but certainly looking at the long-term production for them. So there probably will be some future campaign, depending on the failure timing of those pumps. which would be, you know, in the next few years. Looking beyond that, of course, if we're able to extend the life of the field, then there would be further CapEx activity around that. But in terms of ongoing CapEx on a year-by-year basis, yeah, I think Ray's about right.

I think, Adrian, it's just you notice that the FPSO is leased and not owned by us. So that's where, you know, that's why Julian went to the pumps. because there's not a lot else of areas where we have capex costs.

Yep. Yep, that's perfect. And you already give great guidance level, so I was just going to be creative. Thank you very much.

All right, no problem.

Once again, if you wish to ask a question, please press R1 on your telephone and wait for your name to be announced. The next question comes from Gordon Ramsey with RBC Capital. Please go ahead.

Julian, I just want to congratulate you and the team for the result on PRA2. It's 4,000 barrels a day. That's a very good flow rate. I guess from my perspective, it certainly bodes well for the SPS92 well. So can you just comment on that? Can we expect a similar result from that well?

So SPS92 is the biggest producer on the field. It's always been a great producer. In terms of what we might expect to see from 92, it obviously is also going to have a new pump installed. And, you know, we'd expect to see a similar performance from the pump itself in terms of its capacity to draw down pressure at the well bore reservoir interface. In terms of what it's likely to give us in terms of production rates, I would be hopeful that it will produce a result that is at least as good as PRA2, given that PRA2 has historically been a smaller producer over the last few years. So in terms of putting a number on it, I'm not really in a position to stick a number on that. There's a whole range of numbers that could come out of it. But certainly I'd be hopeful that we'll see several thousand barrels per day of additional production come out of SPS 92. And combined with the other two wells, I think... that we have a good chance that that will get us up into that 5,000 to 10,000 barrel of deer range of uplift that we're forecasting.

Yeah, I agree. It looks like your first two wells have even got to your lowercase already, so that's good news. Just very, very quickly on NEON, that $67 to $75 million valuation cost, the new cost you've given us, what does that include? Is that just the one well?

So that's two wells. The two wells are a little different in their evaluation program, so they don't have the same costs. um but uh there'll probably be a little bit more expenditure on the first well and a little bit less on the second well assuming that we drill the second well if we decide not to drill the second well there will be some savings but we won't be saving the full cost of that second well if we don't drill it because we've already got a number of contracts that are in place and we will that there will be certain causes in those contracts that require us to to pay a number of days of notice But yeah, that 65 to 75 includes both those wells and the evaluation programs and the work that's going in place at the moment to get those wells in place. So yeah, that's where we're at with it.

And then the commitment to that potentially by 1Q 2023 in terms of the development, what are the requisite, what are the approvals that are needed for that?

So, yeah, by 1Q24. Yeah, no problem. So we have to go through concept select on this. And as I said, we've got a number of concepts that we are currently evaluating. We're doing a lot of that work ahead of time, so we're not going to wait for the well results. before we do the engineering work that's required to help us decide between those concepts. However, the well results themselves will feed in really important information into what what those development concepts might look like. And that will be really what helps us make the decision between one concept and another. It will still take some engineering work through the concept select phase, which I expect to be a period of some six to nine months following the well results. And that's what takes us towards the end of 2023 or into the very early part of 2024 before we've decided on the concept and we then make decisions the decisions that enter the front-end engineering, the detailed design phase, essentially. I expect to be quite well advanced at that stage. That obviously is more than 12 months away from now. And we have some ongoing spend that will help us to continue to accelerate that program, as I've said. So, yeah, it's really decisions around the results of engineering studies work as well as the data that we'll gather on the hopefully two new wells in Neon.

Okay, and just lastly on costs, you've highlighted diesels being the main factor and obviously the rig delay. What else is there? Is there any other areas we should be thinking about or are they just so minimal we shouldn't worry about them? You know, as you're saying, a lot of the material costs are... have been locked in. But are there any other costs? You know, inflation in Brazil just seems to be incredibly high.

Yeah, look, I mean, a lot of our costs, of course, have been for materials which are fixed. But where we see services, obviously on a year-by-year basis, those service contracts have a CPI inflation component, and that's probably towards the high end of the range of what we had been expecting. Brazil, historically, of course, is an area where you get some significant inflation, but certainly it's been towards the high end of that range, as it has been within Australia too. Quite a chunk of that gets absorbed within contingency, to be honest. But yeah, look, if inflation really blows out, not that we expect it to do that, but if it was, then we would probably see numbers towards the upper end of those estimates. Having said that, Gordon, we've built in some contingency there, as you know, and we've now factored in the full sequence of delays that we've seen over the last few months of operations. And we've built in, of course... Diesel prices that were certainly growing substantially in the early part of this year, they seem to have stabilised a little bit now. And even in Brazil, they've actually dropped back a little bit. But yeah, we've seen a period of pretty high costs.

Okay. Thanks, Julian. Appreciate it.

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

Yeah, look, thank you very much to everyone for your attention to Karun. I do appreciate it's a very busy reporting period at the moment and getting any attention from the analyst community and from our shareholders is actually fantastic and we do really appreciate that. There's been quite a few on the call, which is great to see. And yeah, we'll continue to do at Karun what we've been doing over the last 18 months, safe and reliable operations being obviously the name of the game, and then delivering on our promises. So thank you very much once again for your support. And thank you, of course, to the Karun team for their continued hard endeavors to deliver on our promises. So thanks very much to everyone.