Karoon Energy Ltd

Thank you for standing by and welcome to the Karun Energy 2023 full-year results 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 via the phones, you will need to press the star key followed by the number one on your telephone keypad. If you would like to ask a question via the webcast, please enter it into the ask a question box and click submit. I would now like to hand the conference over to Mr. Julian Fowles, CEO and Managing Director. Please go ahead.

Yes, good morning, everyone, and welcome to Karun Energy's FY23 results webcast. My name is Julian Fowles, and I'm the CEO at Karun, and I have with me this morning Ray Church, our CFO, and Anne Diamond, our head of IR. Earlier this morning, we released our FY23 results, our annual report, and this presentation to the market, which we are now going to talk through. I'll focus on a number of key slides rather than go through every single slide in detail. given quite a bit of the information was already released to the market with the Q4 results announcement last month. Noting the disclaimer on slide two, I'll start with the highlights on slide four. FY23 was a year focused on executing the strategy we had developed for Karun's growth. Operationally, this was about growing profitability through growth in production from the intervention in patola programs, while also evaluating the potential for a neon project at the same time as building capabilities within the company. The result was that we achieved substantially higher production, which increased by over 50%, and we had costs at the lower end of our range. Importantly, we also delivered the program safely, improving on our FY22 lost time incident rate and our total recordable incident rates. Our underlying NPAT rose 70% despite a six-week unplanned production outage and a 5% lower realized oil price than in FY22. NEON progressed with good results in both of the control wells and an increase in booked 2C contingent resources, while our Bona 2P reserves also increased. We largely achieved our annual sustainability targets and continue to seek further ways to reduce direct emissions in our operations. We also signed a term sheet for direct equity in a Red Plus offset project. We finished the year in a strong financial position with no further draw on our debt facility, despite a very capital-intensive 12 months. With the promised growth in our production now delivered alongside continued strong oil prices and a largely fixed cost base, we are in an excellent position to continue to seek further value accretive opportunities through M&A in addition to the potential organic neon project. Noting that safe and reliable operations continue to be at the core of what Karun aims to achieve, slide 5 goes into more detail on our HSSE performance. I'm pleased to report that we saw meaningful improvements in LTI and TRI rates despite the 90% increase in hours and the high degree of complexity of the work that we undertook. There is still room for improvement, especially in the area of process safety, where a gas leak led to an unplanned shutdown of our production operations for six weeks from late March. I would emphasize that safety continues to be a key focus for the board and the management team. I'll come back to our operational performance a little later in the presentation, but I'll hand over to Ray now to talk in more detail about our financial results.

Thanks, Julian, and good morning, everyone. I'll also speak to the highlights of the slides and try not to repeat things covered by Julian or covered in later slides. Slide 7 provides the financial highlights of continued strong delivery from production and sales growth over a relatively fixed cost base. The resulting EBITDA growth after payment of the interest component of capitalised operating leases and income taxes means our operations generated $271.8 million of cash. which, when combined with our opening cash position, fully funded our $356.2 million spend on CAPEX and contingent payments, so that no debt draw was necessary through this CAPEX-intensive year. Moving on to slide eight, I'll highlight a few details on the income statement. Increased revenue was driven mostly by production growth from the Bona intervention and Patola development programs. $212 million of additional revenue were due to higher liftings, partially offset by realised prices for Bona crude, which were marginally down as global inflationary concerns cooled Brent prices in the second quarter of 2022, and China temporarily focused on Russian imports in the first quarter of 2023. The combined result was a net total revenue increase of about $181 million. Production costs were impacted by the effects of AASB-16 emissions, to the FPSO operating lease, and I'll provide more colour to this in a few slides. Royalty and other government take grew by $25.2 million. This reflects the higher production levels, as well as $14.6 million associated with the temporary export tax, which applied from 1st of March to 30 June 2023, and fortunately has not been extended. Finance and interest costs included $3.5 million of debt facility costs, mostly related to establishment and facility fees, up from $1 million last year, and $2.4 million unwinding of discounts in the Bowen restoration provision, up from $1 million last year. The effective tax rate is approximately 36%, slightly higher than the Brazilian tax rate of 34%. due to non-deductible share-based payments and Australian costs, as well as appreciation of the Brazilian real against the US dollar across the year. The resulting FY23 underlying net profit after tax was $145.9 million, or up 70% on the prior year. Slide 9 illustrates the peak capex now behind us in FY23 as we transition to a capital light phase. Looking ahead, we still expect sustaining capex to average less than $10 million per annum. I'll move on to cash flows on slide 10. As you can see, sales proceeds exceeded $550 million in the year, which then funded $281 million of operating costs, taxes, and other running costs, leaving a surplus of $272 million operating cash, which covered the contingent payment and the majority of CapEx outflows, and required only $83 million drawn from opening cash. This reflects the benefits of the increased production, a relatively stable cost base, and a higher oil price environment. and no additional debt was drawn in the financial year. I would also like to note that approximately two-thirds of the contingent consideration payment paid in January each year is deductible for Brazilian tax purposes in the calendar year of payment, which should result in savings of income tax due in the first quarter of the following calendar year. Staying with cash and debt, slide 11 provides the total liquidity movement between balance dates. Undrawn facilities will be cancelled at the end of September this year, and we're currently in advanced stages of negotiations with lenders on refinancing plans. Appetite and support from both our existing lenders and potential new lenders is good, and we'll update the market when that process is complete. Conceptually, we expect to create a funding package that aligns with our plans to fund further growth at terms no worse than our current facility. Moving to the application of cash, slide 12, reflects our priorities for allocation of capital. First priority use, of course, is safe, reliable and sustainable business operations, which includes meeting our emissions reduction commitments, then ensuring we fund our sustained CAPEX needs and existing commitments, followed by debt service and management of balance sheet health. Cash available after these priorities will then be allocated on economic merit to pre-development of the NEON discovery, acquisition opportunities and dividends or return of capital to shareholders. This priority waterfall is of course aimed at maintaining liquidity and balance sheet health while supporting growth as we build scale to higher future levels of operating and long-term free cash flows. Moving to slide 13, as I previously mentioned, the uplift in our reported FY23 production cost is largely driven by AASB16 treatment of operating leases, reflected in depreciation and amortization and interest on lease liabilities capitalized. This slide shows production costs on a pre-AASB16 basis, which is how unit costs are expressed by our industry peers. As you can see, on that basis, underlying gross production costs declined year on year by $7 million from $118 million to $111 million, while unit production costs fell 38%. This $7 million production cost reduction included a number of factors. Lease and related costs were $13 million lower due to the extended FPSO shutdown. and $4 million of other year-on-year savings related to FY22 local content levies no longer applicable as the production period passed 10 years and COVID-related costs were not incurred in FY23. This was partly offset by $6 million higher logistics, chemicals and manpower costs driven by year-on-year increased FPSO production activity and about $4 million inflationary increases. I should point out that AASB 16 adjustments in FY22 did, in fact, match on a pre- and post-AASB 16 basis. So the table is, in fact, correct. Finally, slide 14 provides a reconciliation to statutory NPAT and EBITDA. Consistent with our past approach, non-cash movements in fair value of continued consideration have been removed, as have FX movements. The $25 million in non-underlying tax benefits in statutory impact relates to the impact of currency movement on the value of future tax deductions on Karim's balance sheet, which is re-measured at each balance date. Thank you, everyone. I'll now hand back to Julian to talk more about strategy and outlook.

Yeah, thank you very much, Ray. Some great numbers there. I think everyone would agree. Turning now to slide number 16, this summarizes Karun's strategic objectives. As a company, we're focused primarily on achieving safe operational excellence at Bauna, while identifying the most value-adding opportunities to grow production, balanced against potential returns to shareholders, while we also operate responsibly with respect to our carbon footprint. Inorganic opportunity screening has remained consistent through the year with geographic preference for Brazil and U.S. Deepwater Gulf of Mexico producing oil assets, where we're employing strict and rigorous assessment criteria to all of our evaluations. NEON is the key organic opportunity we have, and there we're targeting a potential concept select decision in Q1 of calendar year 2024. Slide 17 summarizes our producing fields and the results of our intervention in Patola campaigns. I'll not go into this slide in a lot of detail since most of it has been covered in the past, but I would highlight that both campaigns delivered above expectation production rates and were delivered at the low end of cost guidance with a total final capex of just over 300 million U.S. dollars. Slide 18 illustrates our operating performance. Our focus here is on safe and reliable operations, so it was disappointing that we suffered a six-week unplanned production outage from late March, just after the second patola well came on stream. This negatively impacted our production result for the year. Although unfortunate, the outage was also an opportunity not wasted, and we undertook a significant amount of inspection and remedial work on the FPSO. The work highlighted that there is more to do to support the long-term integrity of the FPSO. Our next planned maintenance shutdown is scheduled for March 2024, with inspections and maintenance an ongoing effort as normal in operations. Production rates appear now to have stabilised as we start to see pressure equalisation with the aquifer at Patola. Like most oil producers, we are faced with natural decline as we reduce the volume of oil in our reservoirs, and we anticipate at this stage that we shall see a higher decline rate than previously, estimated at this point to be approximately 15% per annum from current rates, although I would note that there remain sizable error bars around this estimate, given the relatively limited production history since completing our work programmes. Slide 19 summarizes the NEON results and the studies currently underway. I've covered this extensively in the recent past, but would like to highlight the 14% uplift in booked 2C contingent resources and the new booking of approximately 15 million barrels of 2U prospective resources at NEON West, lying just two kilometers to the west of NEON. We are planning to be ready for a decision on concept select early in CY24, with three potential options currently being assessed, as outlined here. Slide 20 covers our approach to potential inorganic growth, with no change to our strategy here, and evaluations ongoing of potentially value-accretive opportunities, as I've mentioned before. Progress with our sustainability projects is summarised on slide 21. During the year, as expected, we saw an increase in our carbon footprint as a result of our extensive work programs. However, both the absolute volume of CO2 emitted and our emissions intensity have now dropped away significantly, as you can see in the chart on the top right. Our approach to carbon remains to look for opportunities to remove emissions from our operations in the first instance, and then to look to offset the rest, with the important note that we look for projects with social co-benefits. We maintained our carbon neutral position through the impact of operational projects and the purchase of high-quality offsets for FY22, and we anticipate that we shall achieve the same for our FY23 emissions. We are well down the path of investigating potential direct investments in nature-based solution offset projects, with our longer-term objective to transition towards ARR projects. Through our activities, we contributed some US$150 million to the Brazilian and Australian economies in FY23. Full details of our ESG goals and our progress in achieving those is summarized in our sustainability report, which was released alongside our other announcements to the market this morning. Slide 22 outlines our guidance for FY24 and includes our six-month transition year to 31 December 2023. We are expecting production for the full year of 9 to 11 million barrels. And due to our largely fixed cost base, we expect also to see a reduction in cash costs on a unit of production basis to between 11 and 15 U.S. dollars per barrel from this year's 15.75 dollars per barrel. Importantly, our CapEx will reduce significantly compared to FY23 as our major investment programs have been completed. NEON will attract some capital as we progress the project through the concept evaluation stage, while other capital spend is anticipated to consist of sustaining CapEx for our ongoing operations of up to around $10 million and the next contingent payment to Petrobras, of course, which will become payable in January next year, subject to oil prices. A summary of FY23 is provided on slide 23, covering the items we've discussed in the presentation. Interestingly, you can see in the chart on the bottom right how our share price has become more directly correlated to the oil price from September 2022 as we delivered our production growth programmes. The Board has carefully considered the question of capital returns to shareholders. Given the six-week unplanned shutdown and the impact of that on not only our cash holdings, but also the delay that has led in achieving stabilised production from the intervention wells and our new Potola development, we have determined that now is not the right time to commit to a capital return. The Board has committed to reassess returns to shareholders over the next six months. I think it is worthwhile reflecting what our performance in FY23 has achieved. Supported by a continued robust oil price, our teams have safely delivered a tripling of our daily production rate for a capital spend at the low end of our FID approvals, without any significant debt draw, leading to a 70% uplift in underlying NPAT. Karun now sits in the near-unique and enviable position as a mid-cap oil producer, of having well over 30,000 barrels a day of sweet, light crude production, with $75 million of cash in hand, very little debt, a largely fixed cost base, a potential new organic operated project starting to take shape on the horizon, with over 100 million barrels of booked 2C and 2U resources, net to Karoon. and a core team of highly skilled and capable industry professionals with a proven track record keen to tackle the next opportunities. Finally, I would like to thank our team at Karun and our core contractor partners for their hard work and dedication in delivering our FY23 results and the work that continues in Karun's transformation and growth. And I should like to thank our shareholders for your continued support of the company as we enter this next exciting phase of production delivery for Karoon. Thank you for your attention. I'll now hand back to the moderator for any questions.

Thank you. If you wish to ask a question via the phones, you will need to press the star key followed by the number one on your telephone keypad. If you would like to ask a question via the webcast, please type your question into the ask a question box. Your first question comes from Gordon Ramsey from RVC Capital Markets. Please go ahead.

Thank you very much, and good result, Julian. Congratulations. Just a quick question on your comment where you said after doing inspection work on the FPSO, there's more to do, and just wondering if you've kind of had an audit after you had the production interruption and where some of that work might need to be done and whether that could affect CAPEX and FY24. Sure.

Yeah, thanks, Gordon. Look, it's a great question, and obviously it's been a major focus for us over the last few months. We do have reviews and audits ongoing that we're doing in concert with the FPSO operator, Altera and OCM. What we found from our extensive work that we did during the shutdown was that there are areas on the FPSO that we need to do additional work, especially to tackle some of the corrosion that we see in in the pipework. Although we've tackled the high pressure pipework, there's still some of the low pressure areas that we want to get on top of. These don't cause us any particular concern at this moment, of course, where our production is ongoing. But we do anticipate that we'll need to do some further work on those. Maintenance and inspection work is part and parcel of any production operation, as you know, especially in the offshore environment, which can be particularly corrosive. So that's part of what we are continuing with. And we're working very well and very closely with the FPSO operator to ensure that we can continue safe and reliable operations for many, many years to come with a focus, of course, on looking to extend the life of the FPSO.

Thanks, Julian. Just one more from me. After the conclusion of the temporary Brazil oil export tax, I'm just wondering whether you're expecting any further changes in Brazil with respect to how they treat project developments. And I guess where I'm coming from is NEON, whether there will be more emphasis on local content or there may be some other changes that could affect how you move forward with that project.

Yeah, thanks again, Gordon. Look, along with the rest of the industry, we, of course, celebrated the end of the temporary export tax. And we're very pleased to see that that was not extended or a new tax imposed. It's very hard to predict what governments will do. Of course, they're driven by their own needs in terms of what they're hoping to achieve. there does continue to be I think a good dialogue with government and with the ministry and the regulator around how the industry can best contribute to Brazilian society part of that we cover through obviously our social projects and the taxes that we pay as part of our production we don't at the moment see anything directly going through legislation that will that will have an impact. But that doesn't mean to say that we would sit back and anticipate that that's going to be the status quo forever. I do expect, as we've seen in other countries, that with oil prices sitting where they are, around $80, $85 a barrel Brent, that the government will look very, very closely at that to see if there are areas that they can efficiently not necessarily overly burden the industry, but try to efficiently encourage additional investment into the Brazilian economy. There is an extensive amount of investment, of course, going in over the next few years. primarily in the pre-salt area where Petrobras and their partners are investing heavily to increase production in projects that are already defined. We would expect to see that production overall in Brazil for oil lift perhaps to some 5 million barrels a day over the next five, six or seven years. The government, of course, will benefit as a result of that. However, as I said at the start, it's difficult to predict exactly what they may tackle. But very pleasing to see that they didn't extend anything to do with an export tax at the end of June.

Thanks, Julian. And just to confirm your reply for royalty relief for the smaller fields around the neon area?

We're certainly in discussion on that. There's a number of things that we have to do and quite a bit of work we need to do to engage. with the regulator. But the regulator, as you know, is very well-intentioned in terms of how it applies the rules with respect to both mature fields and to small or marginal fields. And we expect, I think, a pretty positive dialogue to continue there. We engaged with the regulator on that. I personally did that with the chairman and our vice chairman with the regulator in early July, and certainly we had some encouraging meetings with them at that stage.

Thanks very much, Julian. Much appreciated.

Thank you. Your next question comes from Adam Martin from E&P Financial. Please go ahead.

Yeah, morning, Julian Ray. Hope all's well. Just in terms of, I suppose, first question, just the operating environment you're seeing over in Brazil, just around costs. I mean, obviously, costs are falling unit basis quite significantly in the next 12 months, just in productions rising. But thinking a bit further out, as production starts to plateau and eventually come down, I mean, what are you seeing there just around operating environment for costs, particularly operating costs, please?

Yeah, thanks. Look, I think that we see from the industry in general that there has been quite a significant escalation in costs for new projects and for additions to existing projects. Petrobras, of course, is the big gorilla here. It's been out for... leasing FPSOs and building new FPSOs, and there's a significant amount of cost inflation that they have seen with that. I guess a marker that we have is, if I look at the cost that we had for the Maersk developer, the Noble developer drilling rig, to try and – to try and contract the same or a similar rig now would probably cost something between 50% and 100% more on a day rate basis for that rig. That doesn't mean that development costs, field development costs have seen a similar escalation, but certainly there has been significant price escalation over the last few years in Brazil That, I think, has probably started to plateau. And I would hope that over the next few years that we start to see that come back down again. Of course, it's important for us from the point of view of looking forward to potential neon development and how we would cost that up. But, yeah, we're, without a doubt, along with the rest of the world, seeing significant cost inflation. Of course, our operations themselves are largely on a fixed basis. We don't necessarily have any new things to put in there. However, the operational contracts do have included in them, of course, inflation clauses. So we would expect to see those costs go up on an annual basis in line with inflation.

Okay. No, that's helpful. And then in terms of that whole cost piece, is it similar to Brazil versus U.S. Gulf and Mexico? And perhaps you could just articulate how the M&A works going there. I mean, is sort of leaning into one region versus the other, any interesting trends you can sort of point to when you're going around looking for assets there, please?

Look, there's quite a number of assets that are in the market or pre-market that Karun gets to look at. We've established, I wouldn't say as much as a presence, but we've established certainly – a name in the Gulf of Mexico where people are now coming to us to ask us to have a look at assets that they are contemplating putting on the market. I think that, as you know well, in any M&A situation, it's likely that there will always be a gap between seller and buyer. expectations. I think that the current time is no different to that. We do have, I think, in Karun a desire to to broaden the portfolio, given we essentially have one egg in one basket. There are pluses and minuses with that, of course. Having one egg in one basket means that you take absolutely very careful care of that egg and that basket, and you're not distracted from that. However, it would be nice to have a little bit more of a portfolio approach here, where And a production outage in an FPSO at Bauna doesn't cause a complete stop to all of our cash flow. So it would be nice to be able to spread some of our risk there. But, yeah, look, I think that we see very positive things in both areas, Brazil and Gulf Mexico. We don't necessarily have a preference one for the other. We're happy to look in both areas. And although Petrobras is no longer currently in the market in Brazil to sell down, producing assets. That may, of course, change in the future, but it doesn't mean that other companies are not in the market to deal with their portfolios. So, yeah, I've been encouraged. As you'll be aware, we haven't jumped at the first thing here or there. We continue to apply very rigorous and strict criteria to our screening. And, yeah, that work continues. And as soon as we've got something to say to the market about it, you can be sure you'll be hearing from me.

Okay. No, great. Well, well done on the result and good luck on that. Thank you. Thanks, Adam.

Thank you. Your next question comes from Sarah Kerr from Morgan Stanley. Please go ahead.

Thanks, Julian Ray, and congratulations on the result. I was just interested, again, on that M&A comment. Would you be keen to be a non-operator in another producing asset so you can keep looking after your egg?

Yeah, I like it. Thank you. So, look, I think if we have a preference in Brazil, it's probably to operate, given we have a good – a highly capable team in Brazil. However, for the right asset and the right operator, Karun would also be comfortable as a non-operator in Brazil. In terms of Gulf of Mexico, I think... The approach that would be wise is for us to look at initially non-operated stakes in assets in the Gulf of Mexico. What I've found in my time in the industry is although you may know a lot about a particular area, you may be a very good operator there, that doesn't always... completely translates to a new jurisdiction. And I think we do need to be very careful and prudent about how we do that. So I'm happy to go into Gulf of Mexico as a non-operator. I'm equally happy to go into or to expand in Brazil as a non-operator. But if there is an operated opportunity that comes up in Brazil, we would certainly look to grasp that with both hands if it's sufficiently value-accretive.

Thanks. And if I can just ask another question, if I may. I just wanted to get a little bit more colour on the regulatory environment in Brazil, specifically the energy tax reforms that are before Congress at the moment. And do you see impacts to the transfer price and a special taxation regime for oil equipment imports? And could that impact NEON's development?

Look, there are a few things going on in that space. It's very early days at the moment, but I'll flick that one to Ray if he doesn't mind. Yeah.

Hi. We've obviously been engaged in that conversation. The market, sorry, the industry generally is involved. And at this stage, most of the focus is around VAT and state-level optimization. The state-level system there is very complex and complex. It means that if we procure from, say, a Rio office, we buy from a supplier in another state, and then it's delivered in a third state, there's a quite complex reconciliation mechanism. And so part of the discussion is around simplifying some of those things, which is good for us. But the quantum of things that are changing so far – the quanta of things that are changing so far aren't, you know, it's sort of a remix so far rather than anything material. Yeah.

I think one thing that's really important that the government is very mindful of is the import and export regime around oilfield equipment, which is covered under the perpetual regime. I I know that that is a topic that's being debated. The CEO at Petrobras, who has previously been very prominent in the government in his previous role, he's obviously very keen to ensure that the petro regime is retained. And at the moment, I know that that is something being discussed, and it's something that needs to be, I think, maintained in order for Brazil to maintain its competitiveness in upstream oil and gas. Personally, I don't see a significant risk for that, but I know that, again, as with any government, that these things will come and go. And as Ray has said, the focus at the moment is on some state-level taxes and how those can potentially be simplified and to do that efficiently.

That's clear. Thanks so much.

Okay.

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

Thanks, Julian and Ray. Yeah, Julian, just on NEON resources post-drilling, first chance we've had to chat about this since you posted the updated resource range. You flagged, you know, cost inflation, high cost for new development offshore Brazil. Just wondering how that's impacting your thinking around minimum economic pool size for Neon, looking at the bottom end of the range, 38 million barrels. How confident are you that, based on where you're seeing costs at the moment, that that is economic, or... Is there a scenario here where you may want to or need to return to Neon and maybe drill a further appraisal well just to lift that 1C number or possibly drill a well in the Neon West prospect? Thanks.

Yeah. Hi, Nick, and thanks for that. Look, we drilled the Neon wells extremely efficiently. They were well below budget. I think about a third below the budget that we set for them. Really an outstanding performance there. Much better than I had anticipated. I think better than the team had anticipated. So in terms of drilling, we've shown we can do that efficiently. However, I would say at this stage we believe we have sufficient information, we've captured sufficient control around our risks at NEON for us to be able to take the next step, whether that is to say that we have confidence and we can move forward into the concept select phase or whether we need to, in some way, go back to the drawing board. Those 1C resources that we've booked here would, without a doubt, be sitting in the marginal field development scale. And without a doubt, if... if those numbers remain as they are, then we'll need to think very, very carefully about how we potentially develop neon At the moment, though, I think that we're still in the process of integrating some of the well results. We have quite an amount of effort in the modeling of potential subsurface outcomes still to do. I think we've captured the range of those very well in the new contingent resource booking. And, of course, I've always said that I believe NEON – should be able to stand on its own two feet before we look to try and add in things like Goya or anything else around that. But having said that, Neon West is very, very close to Neon itself. Simply, it's just two kilometers to the west, and we would be, I think, foolish to ignore that. the very high potential that Neon West has and prospective resources there in any potential field development. So I think that there's a number of levers that we have there. We don't have any control, of course, really, over cost inflation. other than through the most efficient contracting strategy we can put in place. And that is also something that is obviously going through the evaluation stage. So I'm not put off by a 38 million barrel 1C. As I said, I've been encouraged by what we saw at Neon West. And I think there's still a lot of water to flow under the bridge before we get to those decisions on Neon in early calendar year 2014.

Thanks for that, Julian. And look, my other question was just around your comments in relation to returns to shareholders and board discussing options by the end of this calendar year. Just thinking through, obviously, you know, with most of the capital program now behind you, there's a lot of cash that's going to be coming into the business over the next six, 12 months. You know, how should shareholders be thinking about this? You know, Should shareholders be tempering expectations for a large dividend or buyback because clearly you've signalled, you know, neon investments that's coming back? That could be, you know, quite significant and obviously inorganic growth opportunities. Just trying to think about how shareholders should be thinking about this going ahead. Thanks.

Yeah, look, I think with respect to NEON and the type of costs that we would expect to see there, if we're sufficiently confident to move NEON forward, then I think that at some point we will be seeking to bring a partner into NEON. I think that would be wise. And it's something that we'll think about at the right time. But strategically, I think that would be the plan with NEON. So there would be some cost mitigation there, if you like, in terms of how much we would have to spend. In terms of capital returns to shareholders, the board... is very keen to ensure that shareholders see some of this. The question at the moment is, I think, around taking a prudent approach, having just come out of that six-week unplanned shutdown. The board, as you know, errs on the conservative side and would like to make sure that we've got more production under our belt and probably build something of a bigger cash holding before we have the confidence to make any announcements there. But also, of course, capital returns to shareholders, as Ray has pointed out in one of his slides, will be balanced against the need for additional growth investment into good M&A. And so those two things have to, to some extent, balance each other. It doesn't necessarily mean that growth in M&A would mean that we don't make capital returns to shareholders. It's just, as I said, a balance of how that moves forward. Yeah, the board will look again over the next six months through this transition year. It's actually quite a handy period to be able to do that once again. And we'll certainly keep the market and shareholders fully informed as the board goes through those deliberations.

That's great. Thanks, Julian. Yeah.

Thank you. The next question comes from Henry Meyer from Goldman Sachs. Please go ahead.

Morning, Julian and Ray. Thanks for the update. The first question I have is just trying to understand what's constraining production at the moment. I guess it's great to see that the decline is looking pretty steady now. Just hoping to understand, you know, across the three main fields, are you hitting well or pump constraints? There's now liquid handling capacity on the vessel. Just trying to understand if you have opportunities to spin the pumps a bit harder. Um...

Yeah, look, that's a good question. And it is one of the things that we tackle with the subsurface team in Brazil. We have a very experienced subsurface and operational team in Brazil. They've operated Brazilian fields. A lot of them are ex-Petrobras people. They've operated not only this field, but other fields in the past. There's a number of constraints around going all out, if you like, on production. One of those is that we've just spent about $130 million installing some pumps, some new pumps in two of the wells. And I absolutely want to make sure that we see the longest life we can from those pumps. The pumps themselves, I guess, cost around $10 million each, maybe a little less. But the installation of those pumps, as we've just experienced, is a very complex and costly operation. And I don't want to see us damaging those pumps by trying to overexert ourselves. And I'm happy to give away a little bit of production upside here. by operating the pumps maybe at 95, 96, 97% of their capacity. I think at the moment we operate those pumps at around about 58 hertz. Their capacity is around 60. And we tweak the pumps from time to time to get the best out of them, but very mindful that we don't want to see any... any interruption in the pump operations themselves. Because the worst thing you can do with those pumps is shut them down and restart them on a regular basis. So we'd like to see those pumps continuing to operate smoothly and safely. So that's one thing. I think the other thing is Of course, we're constrained by pressure at the wells themselves. Not all the wells have got pumps. Some of the wells have got gas lifts. But the pressure in the reservoir itself or the reservoirs themselves does constrain how much oil we can evacuate on a daily basis. We've just about, I think, got that optimized at the reservoir. Current level around 33, 34,000 barrels a day. Of course, we see a decline almost on a daily basis of probably a few tens of barrels or a few barrels a day. But we do spend quite a bit of time trying to optimize that and making sure we can minimize the decline rate that we've got in the field.

Got it. Great. Thanks, Julian. And maybe a quick follow-up there. Are there any opportunities to complete more workovers and install more ESPs in the field to get a 3P outcome, for example? Or do you expect more workovers required just to maintain the 2P forecast?

So I think the piece of work I would anticipate is actually around the average time to failure of the electric submersible pumps, so these ESPs. Typically these last about three years on average. I'd like to think we can get five years out of them. But in the case where we hit the average or even less than the average, we would at that point go back in and work over those wells. At the same time, we would probably take a look at whether there's any other workovers available. that would be worthwhile. It doesn't look as though we would get any significant advantage from installing additional pumps in these wells at the current time, but obviously that's something that we would continue to assess as we take more out of the field. So, yeah, probably in around three years, maybe a little more, we would anticipate coming back for for a further workover campaign, all things being equal from the point of view of average time to failure. Now, if you think about that, three years' time is 2026. If NEON progresses well, that could be a convenient time to come back to do more drilling work, perhaps even development well drilling work on neon were we to move that project sufficiently far forward in the time being and thereby reduce overall our costs from the drilling program on a single well basis by sharing mob demob costs and hopefully by having a longer contract term for a rig that would allow us to get a better rate. So there are some things there that potentially come together in that sort of three-, four-, five-year timeframe.

Got it. Thanks, Julian. I appreciate all the detail.

Okay. Thank you. Once again, to ask a question via the phone, please press star 1 on your telephone. Your next question comes from Adrian Prendergast from Morgan Financial. Please go ahead.

Yeah, thanks, Julian and Ray, and congratulations on delivering that earnings platform that we all hoped for when Corinne first got the asset, so well done. Some of my questions have already been asked, but I guess just an extension on, I guess, the overarching strategy around that blending of organic and inorganic growth that you've got now over the long term. And, yeah, I'm just interested in how you think about opportunistic acquisitions, given how much Neon has sort of upgraded as a potential third Does it change the nature of the asset that you're looking for? Like maybe you prioritize more just existing production and less long-term development options for potential acquisition?

That's quite an involved question. Thanks, Adrian. Look, what I'd say, first of all, on NEON is that we've been very encouraged by the results of the control well drilling there. And I think that the team is enthused about moving that project forward. I would say, though, that the timeframe for that, I mean, at the moment, I think we're looking at potentially Should everything go right? And look, this is a little bit of a wet finger in the air, but sort of a 2028, maybe late 2028 timeframe for first oil from neon. Obviously, we're only 2023 at the moment, so that's a good five years away. With a decline rate of 15% per annum, that does leave us with not quite a hole in our production, but certainly leaves us with a gap. that I would like to fill. So that certainly pushes me more towards wanting to see acquisition of a producing asset. I think that's really important for Karun. But it doesn't really take away from my desire to see an asset that has further development upside. We've seen the benefit of that in Bauna, obviously with the interventions of Petrola coming on stream. And I'd like to be able to some extent to replicate that. It is harder now than it was during the pandemic, of course. And there are clearly price expectations that we won't necessarily meet for all potential opportunities. But from my point of view, I would still like to see long-term development upside in any asset that we might acquire. And I think that can really add long-term significant value for our shareholders and help to de-risk the current asset concentration of Karim's portfolio.

That's some great color. Thanks, Julian. And maybe just one more. You know, Bayer and the crew have now been in the international market for a few years. Just how you find that the customer base has evolved over time? Is it you're finding a narrow sort of repeat business type customers or is it sort of very applicable across a wide range through that global network you've got access to in the marketing?

We continue to see the same range of customers that we built during the first six to 12 months of our boner production. in the international market. I would say, though, that we also continue to bring in new customers. There's a new customer I think we brought in last month. We probably have a list now of ten different organizations, nine or ten organizations that have bought Bowen Accrued from China through Europe, all parts of Europe. North and South America, and some other parts of the world as well. So, look, I think that we continue to see very strong demand for bow and a crude. It's a crude that clearly finds a welcome reception in the market. In almost all of our sales, maybe with the exception of one or two, we have sold burner crude at a gross premium to the Brent price. So, again, we continue to see strong support for the crude we produce.

That's great, Julian. Thanks and congrats again. Yeah, thanks.

Thank you. There are no further phone questions at this time. I'll now hand back to your speakers to address your webcast questions.

Yes, there are just a couple of questions on the webcast. The first one, I think, is one for Ray from Pranav Nambia. When does Karina expect to complete the loan refinancing? What kind of flexibility are you expecting from the new facility? And what would the new facility do to your financing costs?

Okay. Thank you for the question. We are, as I've mentioned or it's shown on the slides, we're in advanced stage of negotiation of new facilities. We have good appetite being shown by existing lenders as well as some new potential lenders. I won't disclose pricing, but it's no worse than our current facilities, at least where we are today. And I think timing We are expecting sometime in the next couple of months to have that closed. Volume obviously is going to be potentially expanded because we now have a larger production base with Patola being tied in. So all things considered, it's a net better financing for debt product with a greater level of lender participation. I hope that helps.

Thanks, Ray. And the second question, which is from April Lewis from Barrangier. I think we've already covered it, but just to reiterate, how are you thinking about the dividend policy, which is overdue and timing when dividends could occur and the preference of the relative value to accretive growth, which I think we have covered, but maybe talk about a dividend policy.

Yeah, look, I think in terms of a policy itself, that's something that the board has been considering very carefully. And exactly how to... How to manage that. There has been quite a bit of work ongoing, as I've said to the market in the past, around ensuring that we are able to return money out of Brazil most efficiently. And I think that work has been well advanced. and is a key part of being able to pay dividends efficiently to shareholders or make capital returns to shareholders in a way that doesn't necessarily cause any leakage through that transfer. But, yeah, I mean, we've talked about what the board has said, and the board at this stage has decided not to make a capital return to shareholders, but has committed to consider that over the next six months.

Thanks, Julian. There are no further questions through the web.

Well, I think that probably brings the presentation to a close. I thank everyone for your attendance and for your attention. Some great questions there. It's good to see the continued interest in Karun. We've come through this phase of having delivered the projects that we promised with better results than we had originally anticipated. And now I hope to see over the next 12 months what the delivery of that production can do for us. and how we can best reward our shareholders through that process as well. So thank you once again. And with that, I think we will say goodbye.