Hello all and welcome to Jadestone's 2023 All Year Results Call. My name is Lydia and I'll be your operator today. If you'd like to ask a question after the prepared remarks, you can do so by pressing STAR followed by one on your telephone keypad. I'll now hand you over to Paul Blakeley, Chief Executive Officer, to begin. Please go ahead.
That's great. Thank you, Lydia. Good morning, or good afternoon depending where you are, ladies and gentlemen, and welcome to Jadestone Energy's full year 2023 results conference call. I'm Paul Blakeley, Jadestone CEO, and I'm joined on the call today by CFO Bert-Jaap Dijkstra and by Phil Corbett, Investor Relations Manager. In this call, we'll take you through quite a full presentation which was recently uploaded to the Investor Relations section of our website, or you can view it via the link on the webcast. After that, let's open the call for a Q&A discussion.
Now, slide two to outline our standard disclaimers, and in particular, the cautionary remarks regarding forward-looking statements and non-IFRS measures used in this presentation. With that, we can get started by turning to slide three. I want to open by saying that we faced a number of challenges in 2023, but I believe that we've come out of it a far stronger business today.
It was also a year of record investment as we continue to execute on our strategy to diversify the asset base towards higher quality, higher margin assets, and to set the foundations for exceptional shareholder value for the future. We added interests in Sinphuhorm, we increased our stake in CWLH, and we progressed the Akatara project on schedule towards first gas in 2Q this year, while also delivering a great outcome from our first billing campaign in Malaysia. Through the second half of 2023, we worked hard to deliver higher reliability and better uptime at the Montara facilities as we continue to focus on asset integrity following the difficulties we had faced in 2022. As a result, recent Montara uptime has improved significantly, approaching 90% this year, and we're determined to maintain this.
2023 saw huge progress at Akatara too, and by year-end, the project was beyond 90% complete as final equipment arrived at site and pre-commissioning commenced. There's still a lot of work to do to bring first gas into the processing plant next month and to achieve first commercial sales before the end of the second quarter as planned, but we're getting very close now. Our Vietnam assets have made progress too with the signing of a heads of agreement for the initial phase of development in the Nam Du and U Minh gas fields. Further steps in the commercialization process will take time, but the HOA represents a very important first step towards gas production. On Friday last week, we successfully closed the March 2024 redetermination of our RBL facility.
We've agreed with our banks on a borrowing base of $200 million for the next six months, providing ample financial liquidity to deliver the near-term activity program. Bert-Jaap will talk to this later. Moving to slide four, let's quickly revisit a slide we used earlier this year which illustrates how the recent diversification of our asset base is bringing higher value and lower OPEX barrels into the business. Both the diversification of the portfolio and the addition of fixed-priced gas into the production mix, as well as the increased margins per DOE, all provide for far greater underlying resilience, as well as some insulation from any potential commodity price weakness. On the left of the slide, we've updated the unit net present value chart using final data from ERCE's independent year-end 2023 reserves report. The message is clear.
As we continue to add newer assets into the portfolio, our margins improve materially. Assets do mature over time, and as a useful data point, at the time of acquisition of Montara back in 2018, unit NPV 10 per 2P DOE was over $10. While oil price obviously has an impact, the end 2023 equivalent value was just under $8 per DOE, and it helps to show the impact of increasing maturity over time, notwithstanding some operational cost increases that we announced earlier this year. The chart on the right sets out 2024 unit operating cost on the basis of this year's budget and is weighted by production contribution. Noting the marked difference between the two legacy assets and the others in the portfolio, this is a function of several things: relative maturity, gross throughput rate, geography, and offshore versus onshore location.
However, we expect this to be a high watermark year for OPEX at both of these legacy assets, and when combined with investment in new production such as Skua 11 or Stag 48H and other new wells, for example, this combination should lead to higher margins going forward. Slide five now, which sets out some more detail on the ongoing diversification of the group over the past couple of years. The end of 2019, Montara and Stag comprised 100% of our reserves, but four years later, that's reduced to 33%. This is the result of business development success over that period with eight successful transactions completed. To achieve this, it's also required significant investment, both organic and inorganic, across the whole group, and particularly over the last two years. But with Akatara now close to completion, organic investment in the near term will likely reduce.
Now turning to slide six, just a quick highlight on our safety performance during 2023. This can sometimes be taken for granted, but it's worth emphasizing it only comes with a lot of hard work and continuous improvement and goes straight to the very heart of our license to operate, benefiting all stakeholders from employees and regulators to shareholders. We're particularly proud of delivering 6 million man-hours worked at the Akatara development site without a lost-time injury. This is a fantastic achievement given over 2,000 people on site at times and with up to 40% unskilled labor coming from local communities. We've also had zero lost-time injuries in our Malaysia operations. In fact, this performance takes us right back to when we acquired the assets in 2021, another notable milestone.
At the end of last year, we also set out greater detail on our net-zero pathway and provided interim targets on how Jadestone can achieve net-zero Scope one and two emissions by 2040. With these highlights, I'm going to now hand over to Bert-Jaap to take you through the financials. Bert-Jaap.
Thank you, Paul. Good morning or afternoon to all of you. Over to slide seven. 2023 turned out to be a year of two halves again, just like 2022, but of course now with the second half of the year being financially stronger compared to the first half. Full year 2023 production came in at a Jadestone record with 13.8 thousand bbl of oil equivalent per day, translating into 5 million DOE produced for the year compared to 4.2 million in 2022. This year-on-year increase was mostly driven by a full year contribution of CWLH, the Sinphuhorm acquisition which completed early in 2023, and the impact of the Stag infill drilling in late 2022, which together more than offset the decrease in Montara.
The second half of 2023 was stronger than the first half, mostly due to Montara startup in March and the successful infill drilling program in PenMal towards the end of the year. Revenues decreased by $102 million compared to full year 2022 to a full year 2023 figure of $320 million before hedging and $309 million after taking into account the $10 million hedging cost. This year-on-year decrease was for roughly one-third explained by lower lifted oil volumes as we lifted 3.6 million bbl of oil in 2023 compared to 4 million in the prior year and for two-thirds by lower realized prices. We have included details on the realized oil prices, premiums, and hedging in the appendix of this presentation.
Within 2023, revenues were heavily weighted to the second half due to the downtime at Montara in the first half, but also due to the 2023 lifting sequence which included our CWLH1 lifting at the back end of the year. Operating cash flow before working capital and tax decreased year-on-year from $158 million- $36 million in 2023, which is mainly caused by the decrease in revenues. Within the year, the operating cash flow in the second half was $60 million, which more than offset the -$24 million operating cash flow in the first half. Jadestone then concluded the year with a net debt position of $4 million.
This position came in a bit better than expected due to successful management of working capital, reflecting timing of cash proceeds from the December Montara lifting, and other factors including an increase in payables relating to the Akatara project and the Malaysian drilling program at year-end. Over to slide eight. Here, the profit and loss statement is presented where we report a net loss of $91 million after tax for the full year 2023 compared to a $9 million profit in 2022. I will not take you through all the detail but provide a high-level summary of the main year on year variances as follows. Revenues after hedging decreased with $112 million as stated due to lower realized prices, lower lifted volumes, and the hedging cost. Reported production cost decreased by $18 million, mostly due to a credit from inventory movements where 2022 included a significant charge to production cost.
I will provide more detail on this shortly. $16 million higher impairment which is caused by the $17 million impairment of Stag. The remainder of the full year 2023, total impairment of $30 million was mostly caused by the full impairment of the P&LP assets offshore Malaysia. Finance cost then increased by $30 million, mostly due to accretion expenses from the abandonment liabilities and the RBL. Finally, the resulting loss before tax position created a tax credit of $11 million in 2023 compared to an expense of $54 million in 2022. With respect to operating costs on slide nine, we show the breakdown from reported total production cost to a comparable base production cost.
To ensure that both 2022 and 2023 are comparable, we adjust for non-recurring OPEX, P&LP abandonment-related cost and OPEX, royalties and supplementary payments, inventory movements, as well as adjusting 2022 OPEX to reflect the full year's contribution of CWLH1. The conclusion from this analysis is that on a like to like basis, the base cost is broadly flat year on year, which highlights our continuous effort to control production cost. It represents a good outcome, especially bearing in mind the upstream industry inflation. On slide 10, we present our usual cash flow waterfall chart. I think this provides a good summary of what you could call an eventful year. Please note that compared to the financial statements, some items were recategorized to help illustrate the cash impact such as the CWLH funding, which is shown here in investments and in working capital in the financial statements.
From an operating point of view, despite the impact of Montara's downtime, revenues and other income were sufficient to cover operating expenses, G&A, and tax for the year. After the $12 million of working capital was generated, positive cash flow of $23 million. During the year, Jadestone invested almost $118 million on a cash basis. This included organic investment in CapEx, mostly in the Akatara project, and the funding of two acquisitions, Sinphuhorm and the final CWLH1 abex payment. This significant investment program in 2023 was mainly funded by external capital. The equity raise in June 2023 generated $51 million, and the RBL was drawn for $157 million at year-end. These movements resulted in a year-end cash balance of $153 million. Over to slide 11, which contains information about the liquidity in the RBL.
First, now that we are almost one year into our RBL, I wanted to highlight how Jadestone has managed its debt capacity constructively with its RBL banks. In this period, our banks have approved six waivers. Some of these were minor, but some had significant impact such as the one related to the development cap on Akatara, which increased our borrowing capacity. The chart on the left of this slide shows how the borrowing base with its six month periods has improved from the initial forecast back in May 2023 to the actual situation today. In total, working with our banks, we have increased the available borrowing capacity over this 18 month period by more than $120 million. This is evidence of the constructive attitude of our RBL banks towards Jadestone and their confidence in our capabilities and business model. It demonstrates our ability to manage our debt profile over time.
Second, the pie chart on this page illustrates our total available liquidity of $146 million at the end of March 2024, consisting of $114 million in unrestricted cash balances, the $32 million working capital facility that we closed back in June 2023, which remains unused to date, and the RBL facility was fully drawn at $200 million. It's important to note here that the increase in net debt between the end of 2023 and the March 31st this year primarily reflects the timing of lifting receipts. During the first quarter of 2024, we had almost $116 million of revenues from liftings. Of this amount, $110 million is related to March liftings with the proceeds subsequently received this month in April and therefore were not reflected in the March 31st net debt position.
The end March net debt position also reflected the payment of a net amount of $36 million to the abandonment trust fund account for CWLH2, the first of three planned payments this year, and it reflects $35 million received from our prior JV partner on the P&LP assets in Malaysia. There was the unwinding of working capital. I also want to highlight that we comfortably met our RBL financial covenant at year-end 2023. Our net debt over EBITDA came in at 0.14x , well below the required 3.5x . As we reported on Friday, the March 2024 redetermination has concluded. Our borrowing base for the six-month starting 1st of April, as Paul mentioned, is set at $200 million. This was achieved by removing Stag from the borrowing base calculations and by integrating CWLH2 in the borrowing base.
CWLH2 has some conditions subsequent associated with this inclusion, which are mostly security and documentation related. We expect these to be generally administered to the nature as Jadestone is already on title and because CWLH2 is following the same process as CWLH1, so there's a clear precedent. Importantly, we have already paid a significant portion of the decommissioning security. As a result, we expect these conditions to be met over the next few months. We believe that having the stable maximum borrowing capacity close to the point of completion of Akatara is a great outcome for Jadestone, which shows how we have been able to proactively manage our borrowing capacity and liquidity. Over to Paul for the operational update.
Great. Well done, Bert-Jaap. Thank you very much. Okay. So let's now move on to slide 12, and I'll provide some additional color across the portfolio starting with Akatara. Recent activity has been focused on final construction and commissioning. All the key equipment has been delivered, installed, and hooked up with connections and line welding in their final phase. I'll go into more detail on activity in a slide shortly, but the key message is that we're practically there and moving closer to mechanical completion, which will lead to flowing gas into the facility for final commissioning activities and then commercial gas sales by the end of the quarter. The well workover campaign is also nearly complete with three wells ready for production, a 4th well being tested, and the 5th and final workover well underway.
We already have more well delivery capacity than we need to satisfy contractual volumes, and with significant redundancy, we will look to support some incremental production as plant capacity allows. Similarly, the gas sales pipeline has now been completed and successfully hydro-tested. It's already been tied into the regional PGI trunk line and is now ready to take gas from the Akatara gas facility. We talked in the past about the potential for further gas sales beyond the existing GSA, given our confidence around the resource potential of Akatara. At the end of 2023, we booked an incremental net 3 million BOEs of 2P reserves relating to a second gas sales agreement currently being finalized and likely starting production in 2026. There's also scope for further interruptible gas sales in the near term with no shortage of demand for the gas subject to debottlenecking and minor plant expansion.
Slide 13 provides a simple visual illustration of the progress made at Akatara over the past 12 months. From an early construction site in the middle of remote jungle to a complex but largely complete gas processing facility almost ready to produce. This is a fantastic achievement made possible through close cooperation with our main contractor, JGC, with support from local, regional, and national agencies and from many other subcontractors and suppliers. The next slide, number 14, provides some additional images across a variety of worksites. From the main generator shed, pipeline, metering station with tie-in site to the workover activity and operations personnel training venue, there's a lot of activities in the final weeks to first gas. Slide 15 provides some breakdown on key remaining activities at Akatara prior to starting commercial operations.
Mechanical equipment installation together with associated structural steel piping and cabling is now almost done, days away, in fact, and the pipeline is complete with just purging and drying ongoing today. Most effort has now moved to commissioning key equipment packages one by one and field instrumentation, which will be followed by loop testing. This will shortly be combined into a declaration of mechanical completion, at which point we'll introduce gas from well pad A for the final commissioning phase prior to commercial sales commencement. There's been a lot of innovation to maintain schedule with some minor cost impacts, all of which will be cost recoverable, and the team are highly motivated as they approach the final phase of this extraordinary project achievement. We'll keep the market informed over the coming weeks. Turning now to Malaysia and to slide 16.
The success of the infill drilling campaign on the PM 323 license at East Belumut was a key highlight of Jadestone's activities last year. We added 4.2 million bbl gross 2P reserves, equivalent to a 300% reserves replacement for this asset alone, with approximately six to nine months payback and greater than 100% [IRR]. The biggest surprise in the campaign was the discovery of an undrained high in the southwest of the East Belumut field, where we now estimate incremental oil in place of approximately 20 million bbl. The results of the campaign have already highlighted up to seven further infill targets, some of which will be drilled in the next drilling campaign at the end of 2025, along with new wells at East Piatu in PM329.
Following this success, we would very much like to expand our Malaysia business, having recently bid for the Puteri cluster, which is a collection of non-producing assets which we originally acquired with the Peninsular Malaysia position back in 2021. Results of this bid are likely in late June, though we also secured the surrounding PM428 acreage in a prior license round on very modest initial terms. Slide 17 provides some color on the lessons learned from our recent Malaysia campaign, but importantly, also highlights the general location of the next tranche of infill wells for future growth in East Belumut. This activity has been a showcase for Jadestone's capabilities in second phase operatorship and the value we can bring through technical excellence and incremental investment. Now let's move to slide 18 for a brief update on our Australian assets.
We completed the acquisition of a second 1/6 stake in CWLH in February after announcing the transaction in November last year. This was a pro rata deal to the original purchased from BP, and we're really happy with this purchase and with this asset. CWLH continues to perform ahead of expectations with much lower decline rate and good uptime. As a result, we now believe that the field life can be extended by a further four years out to 2035 without any new drilling, and as a result, we've added approximately 2.5 million bbl net of reserves. We've seen excessive weather downtime this year, however, impacting 2024 production and exacerbated with a short delay in bringing one of the wells back on stream. But the facility is now back to capacity and close to 4,400 bbl per day net to Jadestone.
At Montara, facility uptime is approaching 90% so far this year excluding weather. As a result of a very focused approach to operations excellence, the tank restoration program, and compressor optimization. This is a big step forward for Montara. With additional storage tank capacity now up to 130,000 bbl , for example, tank 5C is back in operation, as well as continued inspection on the remainder of the cargo tanks, there is much greater stability and operating flexibility since restarting production. Year to date, production of around 5,300 bbl per day has been a bit below plan, but again, largely weather related, and with recent performance has averaged over 6,000 bbl per day. We remain on track to redrill the Skua 11 well at the end of this year or early 2025, which should provide a good boost to production next year.
We've also had extensive weather-related downtime at Stag, which combined with a planned maintenance outage has resulted in year-to-date production of only 1,900 bbl a day. We're currently producing around 2,400 bbl a day and expect this to increase following a pump changeout on well 37H, which is now ongoing, and a workover on 48H later in the year. Premiums for Stag crude remain strong, however, with the latest cargo selling at around $16 per barrel premium to Brent. Slide 19 updates on our Vietnam and Thailand assets, where earlier this year we signed a heads of agreement for gas sales from the Nam Du and U Minh fields to PV GAS. Since then, we've been negotiating the detailed GSPA and preparing an updated field development plan, hopeful to have both finalized during the course of this year, which would move us towards a final investment decision in 2025.
The Sinphuhorm asset continues to be a very reliable producer for the group and important asset within our RBL borrowing base. Strong demand from Nam Phong plant underpins production at or around 1,600 BOEs per day net, and the booster compression project predicted to complete later this year will help maintain that production at current levels. Slide 20, where we show that pulling together several strands covered in the slides, we've increased our 2P reserves in 2023 to 68 million BOEs, representing 164% 2P reserves replacement during the year. The main drivers of this were the booking of Sinphuhorm after the acquisition in early 2023, as well as additional gas sales bookings at Akatara, the positive impact of the Malaysia infill program, and CWLH outperformance extending field life.
This was offset to a degree by a reduction at Montara, where 2P reserves decreased by 3.5 million bbl, primarily as a result of revised cost estimates, which bring forward the end of field life to 2030. The end 2023 2P figure did not include the second CWLH interest completed earlier this year, and that would represent a further 6.7 million bbl, which will be booked this year. 2C resources were broadly unchanged year on year, but this chart highlights the scale of the resource base in Vietnam, where, as I just mentioned, there is now commercial momentum, and we hope to monetize a portion of this resource in the near term. Slide 21 updates guidance with the production range slightly narrowed to 20,000-22,000 BOEs per day.
This change to the upper end of guidance reflects the average first quarter group production performance of around 17,200 BOEs per day, which, as we've discussed, was impacted by both planned and unplanned downtime across the portfolio, particularly at the offshore Australia assets relating to the recent cyclone season, which has had just over 750 bbl per day annualized impact. It also reflects a view of Akatara commercial gas sales commencing in June, albeit there remains a wide range of possible outcomes for 2024 production, principally based on the timing and nature of Akatara's ramp-up, as well as initiatives underway to optimize production of the group's current producing assets. Production guidance will be kept under review, particularly in relation to first gathered Akatara, and further updates will be provided when appropriate. Both OPEX and CAPEX guidance remain unchanged.
And finally, turning to slide 22, it's worth reiterating the case for investing in Jadestone today, where we firmly believe that Asia-Pacific remains a top-pick region for energy demand growth, and a range of opportunities to build out the portfolio will be available to companies who are well positioned there. Operating credentials are essential to differentiate the winners, and a good track record with key regulators and other stakeholders gives an edge. This is not easy to replicate. While the sale process for Woodside's operated interests in the Pyrenees and Macedon fields did not proceed, it is worth reflecting that these represented excellent candidates to fit within the Jadestone portfolio, and we hope to see similar opportunity in the future. We had provided a very competitive and fully funded proposal without any recourse to equity, and will continue to adopt a similar approach to funding M&A in the near term.
Notwithstanding new business, the current portfolio offers significant organic growth with Akatara on the threshold of first production, numerous infill drilling opportunities across the whole asset base, and our very significant gas resource in Vietnam gaining momentum towards the first phase of development. We believe Jadestone represents a new unique platform in the region, established in several key jurisdictions with production and cash flow at a major point of inflection, and our aim is to turn this pivotal moment into exceptional growth and returns into the future to reward our very patient shareholders. And with that, I'll pause. I'd like to thank you for listening, and I'd like to hand back to Lydia, please, so we can open for Q&A. Thanks a lot.
Thank you. Please press star followed by the number one if you'd like to ask a question, and ensure your device is unmuted locally when it's your turn to speak. If you change your mind or your question has already been answered, you can withdraw from the queue by pressing star followed by the number two. Our first question today comes from David Round of Stifel. Please go ahead. Your line is open.
Thanks. Morning, Paul. Thanks for the presentation. Can I start with one on Akatara? Paul, you mentioned a comment around additional sales, obviously something by the sounds of it you've already secured and maybe something else on top. I mean, are you able to give us a steer on how material those additional sales could be to production and also what you would need to spend on the facilities to expand them?
Hi, David. Thanks. So there's sort of two tranches to think about in a way. The first one is that additional gas which we can produce through the existing facilities without any capital investment. Nameplate capacities, squeezing a little bit here and there, can generate additional throughput. And so if you think about the DCQ for the base contract at 20 million cu ft a day, 25 million cu ft of wet gas, what we're looking at is the potential to take that up to something that might look like 30 million cubic feet a day. So it gives you a sense of what incremental gas on an interruptible basis might be possible. And that's something that once we finish the work in assessing capacities, we could implement very quickly, in fact, immediately. And certainly, the market is there.
The buyer has already signaled an interest in taking much more extra volume than that. That's something that has really no cost to it at all. In fact, any incremental sales under the contract would sell at a 20% premium to the base price. Very attractive on all counts. The second is the firm contract which we have negotiated and agreed and which would require some facilities expansion, additional separation particularly. That's a project that we're implementing and why I suggested that might be something that could start production in 2026. It would take us a little bit of time to do engineering, procure or rent equipment, and that could add a further 8-10 million cu ft a day potential over a shorter contract period of perhaps three to four years. That's what we're looking at.
I can't give you a sense of economic return. We need to do the engineering work and assess capital costs. But of course, they're going to be pretty modest as an expansion to the existing plant and not require further investment in utilities, pipelines, and so on, or wells. So it will be very, very attractive and something that we are very motivated to do.
Okay. Presumably, any costs are going to be cost recoverable here anyway.
Absolutely.
Okay. Cool. Right. Then second one, just on Malaysia. Obviously, I think we've seen the reserves step up at the end of this year. Is the revision we've seen a fair reflection of what you've seen and the potential you see from the asset, or might there be more to come on top of that?
I'm an optimist around these things, David. I would say certainly that significant height to the southwest. We've taken a pretty conservative view on reserves recovery. Actually, I think oil in place. But there is ongoing work to try to refine that, and we'll report in due course. On the four wells that we drilled, on all four, we saw significantly thicker oil columns at the beginning of the horizontal section, in other words, closest to or underneath the platform. And so we're pretty confident that we're going to find some significant incremental reserves there, and we're doing some saturation logging in nearby wells to help understand what sort of volumes there could be. But what you're seeing on one of the slides is seven wells targeted. I feel it is quite likely that we'll find more, but I can't predict any more than that.
Okay. Great. Thanks. That's very helpful.
Thank you. As a reminder, if you'd like to ask a question, it's star followed by one on your telephone keypad. Our next question comes from Mark Wilson of Jefferies. Please go ahead.
Thank you. Yeah. Good morning, gents. I mean, excellent performance to get the Akatara facility to the state and the wells. So if we could talk about the risks against getting to that final commercial sales in June, slide 15, versus and to bring Bert-Jaap for the financial, are there any slide 11, are there any financial impacts if commercial sales are not made by the end of this quarter? Thank you.
Good, Mark. Thanks. No, we're working very closely with the buyer. They understand very clearly the nature of the project, how close we are, whether or not it might slip a week or two or advance a week or two. And that's not unusual in the context of this type of activity. So no penalties per se would apply. There would, however, be a small price reduction on the volume of gas, makeup gas there. There would be, of course, an impact on short-term revenue, but no material issues beyond that. I think to the sort of the more specific question of, "I mean, could it be delayed?" I mean, it's hard to say. The motivation and the scheduling and the activity set look achievable. You don't know what you don't know.
The most likely principle, however, I'd say, Mark, if I were to paint a downside scenario, all the major components are in place, tested, and good. What we would or what we might potentially find would be something where we just simply can't prosecute all of the small final things that need to be done. We've got sufficient gas already available from the wells. The export line and infrastructure into the trunk line is all done. The major components of plant and machinery are tested. So around the fringes, there's a possibility of minor delays or minor accelerations, but I don't think it's much more than that.
Maybe too, good morning, Mark, to address the financials on page 11, if you will, which I think refers to the RBL. I mean, of course, we're looking at Akatara closely. It has net cash flow, incremental net cash flow because of the full cost recovery from day one. So this is, of course, one of the main aspects for us being heavily interested in the starting point of Akatara. Secondly, on the RBL, I mean, timing-wise, we would look at when we do the redetermination, which is scheduled for the end of September. If Akatara comes passing its completion test before, all good. We rope it into the redetermination, the scheduled one. And if it would be a couple of weeks later, I don't think that we would do a scheduled one and two weeks later an interim one.
So eventually, I think we would look at working with the banks that they have been constructive all along to rope it into the one redetermination, which is then the September one. And then, I mean, maybe a bit more technical, but with the start, the move allowed of the RBL, we actually de-risked a bit the schedule on Lemang because the constraining factor in the RBL has switched to loan life cover ratio instead of project life. It's a bit technical. But in effect, it means that there is not a dramatic change if Akatara is roped in a bit later passing its completion test. So that de-risking, I think, is an important element here as well.
Yeah. Thank you for that. And that's actually the.
Thank you, Mark.
Thank you. Yeah. That's the crux of the matter, really, here. So to be honest, the RBL only comes into it when you get to redetermination in September and where you actually stand there. So that's wonderful clarity for me. Thank you.
Thanks, Mark.
Thank you. Again, as a final reminder, it's star one to ask a question. We have no further questions, so I'll turn the call back over to Paul Blakeley for any closing remarks.
Thank you, Leah. Thank you, everyone, for your time today. 2024 is going to be a very important year for us as Akatara first gas will drive a significant increase in Jadestone's production and be a key step in our diversification strategy. Our organic growth options, particularly Vietnam and further infill drilling across the portfolio, provide significant organic upside, and this could be bolstered by further accretive M&A. Cash flow generation is growing, and we will see a restoration of balance sheet strength towards a net cash position through next year on today's assumptions. We are moving back onto the front foot, and I just want to thank all shareholders one more time for their patience. Thank you very much.
This concludes today's call. Thank you for joining. You may now disconnect your line.