Jadestone Energy plc (JSE) Earnings Call Transcript & Summary

Hello, everyone, and thank you for joining us today for the Jadestone Energy Half 1 2026 Results Call. My name is Sammy, and I'll be coordinating your call today. [Operator Instructions] I'll now hand over to your host, Mitch Little, Chief Executive Officer, to begin. Please go ahead, Mitch.

Thank you, Sammy. Good morning and good afternoon, everyone. Welcome to Jadestone Energy's Half Year 2026 Results Conference Call. I'm Mitch Little, Jadestone's Chief Executive Officer, and I'm joined on the call today by Andrew Fairclough, our Chief Financial Officer. I'll introduce some of our key first half achievements and near-term priorities before handing over to Andrew, who will take us through the financial update, and then I'll return for the operational review and wrap up. Our slide presentation can be viewed through the webcast and can also be accessed on our website. After our prepared comments, we'll open the call for questions and answers. So let me get started. Moving past Slide 2, which outlines our standard disclaimers, I'll start on Slide 3. We really got off to a great start this year. And despite some external headwinds that materialized in Q2, we were able to deliver a solid first half. In particular, a number of our strategic objectives were achieved early in the year and positive momentum continues. Starting with HSE performance, where our excellent results continued through the period. Across our Indonesia, Malaysia and Australia production operations, we've now achieved an aggregate 13.6 million man hours without a lost time incident. There were no significant environmental incidents during the period, no material losses of primary containment and no regulatory enforcement notices. Beyond managing the ordinary day-to-day business risks, nonroutine activities, particularly the Stag shut-in ahead of Cyclone Narelle and the aftermath, the Malaysia drilling campaign and continued tank integrity management activities at Montara were also all conducted safely. We continue to leverage upgraded internal procedures and monitoring programs and are making good progress towards closeout of the remaining open actions associated with the Montara General Direction received in September of last year. In Vietnam, strong momentum continues. We've made significant progress towards realizing the value of the Nam Du and U Minh discoveries with FDP approval and signature of the gas sales agreement during the first half. We also launched a farm-out process, which has generated significant industry interest and is progressing towards final negotiations with select shortlisted bidders. Our first half performance was impacted by 2 external unplanned downtime events at CWLH and Stag. Since our trading statement update, remediation plans have been further matured and we reconfirm expectations of restart at CWLH near the end of Q3, with Stag still targeted for Q2 of next year, although we continue to look for opportunities to accelerate on that. Our near-term priority for the business is to restore production to our full potential, which today is well above 20,000 boe a day while continuing to advance our organic growth through delivery of FID by year-end on the Nam Du and U Minh development project. I'll now hand you over to Andrew, who will take you through the financial update.

Thanks, Mitch. On Slide 4, we have set out the key operational and financial metrics for the business in the first half of the year. As we've previously disclosed, first half production was negatively impacted by unplanned downtime at Stag and CWLH, both of which now have defined remedial work programs and targeted restart time lines, which Mitch will talk about -- more about later in the presentation. Despite this impact on production, first half revenues before hedging increased 13% to $261 million. And after hedging charges of $27 million, net revenue was $234 million. Strong production in the first quarter ahead of the unplanned downtime of Stag and then CWLH allied to the timing of our liftings helped underpin total group lifted volumes in the first half, while the strength of the oil price predominantly through the second quarter, together with high premiums for some of our cargoes increased the realized price to just over $90 per barrel. In fact, our last Stag lifting in April, which was a partial cargo accumulated prior to the Cyclone Narelle shut-in priced with a $27.50 per barrel premium to Brent, while liftings in Malaysia have currently priced with a premium around $7 per barrel as did our latest cargo of Montara crude. Field operating costs, which are operating costs, workovers, logistics, repairs and maintenance and transportation were $122 million in the period, but this included a number of nonrecurring costs for the maintenance dry dock program of the Okha FPSO, which occurs every 5 years as well as the subsea campaign at CWLH. It also included repair and maintenance costs associated with the Stag CALM buoy recovery activities, although this was largely offset by reduced operating activity at the field. We saw some increases in logistics costs with higher charge rates for vessels and helicopters and also higher fuel costs on the back of stronger oil prices as well as some foreign exchange headwinds with the Australian dollar strengthening against the U.S. dollar. Adjusted unit operating costs increased to $37.64 per barrel, impacted by a combination of lower production in the period and the higher field operating costs. Adjusted EBITDAX, which excludes the hedging impact during the period as well as other adjustments, was $102 million compared to $100 million in the comparative period. Disappointingly, we generated a small loss after tax of $4.8 million with the loss of production at Stag and CWLH outweighing stronger oil prices and the income statement continues to be influenced by certain noncash factors such as the charge associated with CWLH inventory movement. Net cash from operations was $97 million, nearly double H1 2025, and I'll talk a little bit more about that later. Capital expenditure for the period was $35 million, the bulk of which was the PM323 Phase 9 drilling campaign, which was successfully executed under budget, and we'll see the tail end of payments from that continue to come through in the second half. Net debt at 30th of June 2026 was $26 million, comprising $174 million of cash, cash equivalents and $200 million of debt arising from the bond issuance earlier this year. Moving on to Slide 5. This provides more detail on our cost performance during the half year. The chart on the left compares reported production costs for the first half of '26 versus the first half of 2025. And reported production costs can be split into underlying field operating costs, royalties and production-based payments and noncash charges, of which the main component is the inventory adjustment. Year-on-year, reported production costs increased by $44 million to $164 million. However, of this increase, approximately $18 million relates to noncash inventory movements charged to production costs. This is primarily driven by CWLH, reflecting the movement from an opening underlift at the start of the period to a closing overlift at the end of the first half. As you can see on the right-hand side of the slide, a significant proportion of the increase in field operating costs are nonrecurring in nature with approximately $14 million associated with the Okha FPSO dry-dock and subsea operations. Stag costs were essentially flat at $6 million of costs incurred in relation to the -- sorry, to the CALM buoy was largely offset by reduced operating activity. Costs for the CALM buoy activity will be recovered through our insurance. As mentioned earlier, we saw increases in logistics costs across the business in the first half partly related to higher fuel costs, but also general inflation feeding into -- its way into contract renewals. Across our Australian assets, we saw upward pressure on U.S. dollar equivalent costs due to the year-on-year strengthening of the Australian dollar against the U.S. dollar. In Australia, around 80% to 85% of operating costs, depending on the level of activity at the time, are Australian dollar denominated, and we have seen about a 10% movement in the exchange rate over the past year. Moving to Slide 6, which summarizes first half 2026 cash flows. As usual, several line items from the cash flow statement have been consolidated in this bridge for simplicity. But moving left to right, we can see that cash from operations after working capital was $97 million. Before working capital, this was $46 million, and it's worth highlighting a couple of factors that have had an impact in this half. Firstly, in relation to CWLH, based on a normal lifting and production schedule, we'd expect the overlift position in this period to have reduced significantly by the end of the first half and any inventory movement to have a relatively small impact. However, we completed a full lifting in the first quarter and a smaller shared lifting ahead of the FPSO coming off station in March for the dry dock, which created an overlift. As there has been no subsequent production, which would normally unwind this overlift position, we saw a $22.6 million charge to production costs in the first half. Also in relation to CWLH, the $14 million of nonrecurring dry-dock and subsea costs further reduced operating cash flow. We would also normally expect this to be capitalized rather than expensed. However, our JV partner is currently treating this as an operating cost. And while this is something that we are reviewing, it will currently continue to account for as an operating cost. And lastly, with Stag shut-in, while we undertake the remedial work plan, we have comfortable levels of operating costs but lower revenues compared to last year. To date, we have accrued $11.1 million of insurance proceeds in the first half of 2026, which is accounted for as other income and excluded from operating cash flow before working capital movements. We anticipate these funds will be received in this third quarter, although quite possibly in the next week or so. Moving on, cash CapEx was $32 million, of which approximately 70% was related to the 323 drilling campaign. There were significant financing cash flow movements in the period related to the debt refinancing. We raised a net $195 million from the Nordic bond issue, the majority of which was then used to fully repay the outstanding RBL balance of $150 million at the start of the year. These movements plus other financing and investing cash flow movements resulted in consolidated cash balances of $174 million as at 30th of June. And moving on to Slide 7. In March, as I just said, we successfully refinanced the RBL through the issue of Asia Pacific's first E&P Nordic bond for many years. At the end of June, we had over $200 million in available liquidity once the undrawn working capital facility is included. Whilst this remains a strong position at the half year, I would remind everyone that our liquidity is subject to the timing of cash inflows from liftings and cash flows from expenditure, of course. This will be particularly relevant this year given the impact of suspended production at Stag and CWLH and corresponding deferral of liftings through the second half. We have also continued to manage our hedge positions during the year, which is intended to protect our operational cost base. The majority of hedges in the first half were executed 9 to 12 months ago, and the third quarter similarly reflects hedges that were implemented before benchmark oil prices increased with the conflict in the Middle East. More recently, we've been able to take advantage of stronger Brent prices and have added 700,000 barrels hedged at just over $80 per barrel Brent in the fourth quarter of this year and also in the first quarter of next year. Overall, we currently have 1.3 million barrels hedged through to the end of the first quarter of 2027 at a weighted average price of just over $74 per barrel, excluding any premiums. This represents approximately 35% of forecast oil and condensate production over the period, and we will continue to hedge for downside protection and support future expenditure. And with that, I will hand back to Mitch.

Great. Thanks, Andrew. Starting from Slide 8, I'll continue by running through the operations and asset updates. And I'd like to start with the standout success of this year's Malaysia drilling campaign which was delivered safely and significantly below budget. The drilling campaign within the East Belumut field on the PM323 PSC was targeting the Southwest extension of the field, which we identified as an undeveloped localized structural high during our 2023 drilling campaign. The 2026 program was originally planned as 2 firm and 1 contingent well drilling campaign. But with near real-time interpretation and integration of subsurface results from the first 2 wells, we confirmed the value proposition of the third well and proceeded to drill and complete it in sequence. As you can see from the depth map on the top right of this slide, all 3 wells targeted the structural high of the Southwest extension area in order to fully capture the previously undrained oil reserves in this area of the field. The wells were drilled using modern geosteering tools, which allow us to utilize real-time data while drilling to ensure optimal placement of the well path near the top of the reservoir, thereby optimizing recovery by maintaining maximum standoff from the oil water contact. You can see from the cross-sections on the left of the slide that our drilling team's efforts to optimize the well trajectories working with their subsurface counterparts was very successful, bumping up against the very top of the reservoir in several cases to maximize recovery from the up to 14-meter thick oil column in this area of the field. Moving to Slide 9, which summarizes the impressive results of the 3 wells. In aggregate, they contributed an incremental 8,500 barrels of oil per day. Delivering the program more than 20% below budget is notable given the considerable extended reach nature of all 3 wells. The second well in the campaign was the longest well ever drilled on the East Belumut field. The second well also set a record across all basins in Malaysia for the highest ever extended reach drilling ratio, which measures the horizontal distance of the well away from its surface location divided by the well's true vertical depth and is an industry standard metric for measuring difficulty and complexity of extended reach well designs. On the right-hand side of this chart, we provide a summary of the impact the program has had on the field, impressively more than tripling the field production rate prior to commencement of the campaign. Without question, an inspiring performance by our in-house drilling and subsurface teams and a strong example of the operational excellence we are working hard to instill across our business. I'd like to take this opportunity to congratulate and recognize all of the Jadestone employees, our third-party vendors and partners as well as the Malaysia Petroleum Ministry for their support and commitment in helping us deliver this impressive result. The demonstration of our value creation capabilities and top-tier technical and execution skills provides us with a strong calling card for growth ambitions within Malaysia and across the region. One small component of that ambition is an extension of the PM323 PSC, which would facilitate further development opportunities and where we remain in active and positive dialogue with the regulator following the successful outcome of the Phase 9 drilling program. Moving now to Slide 10. Strong momentum continues across our next leg of organic growth, the Nam Du/U Minh development in Vietnam. Since we last spoke when presenting full year 2025 results in May, there's been considerable effort and progress on the engineering and technical aspects of the project, which culminated in a recommendation to Petrovietnam on both the FPSO and the field facilities EPCIC contracts. I'm pleased to report that Petrovietnam has approved our FPSO contractor recommendation earlier this month and are actively progressing their review of our EPCIC contractor proposal for the field infrastructure. Moving to our farm-out process. We have been encouraged by both the number and quality of interested parties and the positive feedback on the quality of the technical work supporting both the initial development and the significant upside potential on our licenses, which we detailed during our 2025 results presentation in May. The process is now moving into the late stages, and we are currently engaged in final negotiations with select shortlisted bidders. The project and ongoing farm-out are progressing according to plan, and we continue to target a final investment decision by the end of 2026. On the next couple of slides, starting with Slide 11, I'll cover updates across the remaining portfolio. Starting with Akatara, which continues to perform well. The asset safety record is really impressive and a real testament to the strong HSE principles and practices that we have embedded across Jadestone with around 9.5 million cumulative man hours worked at this asset without an LTI. First half production was nearly flat to the year ago period. And since resuming production after a brief period of downtime in April, the plant has produced an average of 6,400 barrels of oil equivalent per day and delivered uptime above 98%. Planned maintenance, critical sparing philosophy and operating procedures continue to be enhanced with a focus on protecting the top decile reliability currently being delivered. We continue to study further incremental debottlenecking potential at the plant after the success of the initial phase last year as well as the subsurface work to evaluate prospectivity of the Lemang PSC to satisfy the remaining exploration commitment on the license. Moving to Montara. The asset produced around 4,200 barrels per day in the first half, in line with plan. Along with our ongoing integrity management activity on the tanks and FPSO topsides in May, we successfully overhauled the FPSO's reinjection compressor. The upgrade has increased the compressor throughput by about 30%, which has allowed us to significantly reduce flaring, eliminating around 100,000 tons of CO2-equivalent emissions per year, increased reinjection volumes for reservoir management and increased gas lift volumes with an associated uplift in oil production of around 250 barrels of oil per day. The project was delivered for under $5 million and on the back of increased production and reduced carbon credit purchases will pay out in well under a year. We continue to maintain constructive engagement with the Australian offshore regulator, NOPSEMA, to close out the prior General Direction. Detailed plans with a target to address all open items by the end of this year have been developed and comprehensively reviewed with the regulator. We also continue to progress our evaluation of developing the estimated 800 Bcf of gas in place in and around the Montara field. The study has passed the initial screening phase and has now progressed from conceptual to appraisal phase with an aim to understand the commercial viability by first half of next year. A successful outcome has the potential to extend life of the asset and elements of its infrastructure by several years. Moving now to Slide 12. In our July trading statement, we announced a decision to replace the CALM buoy at Stag rather than repair the existing one following the damage caused by Cyclone Narelle in late March. Over the past month, we've made significant progress in both our due diligence of the proposed replacement CALM buoy and an image of which you can see on this slide and the commercial agreements required to purchase it. We have now secured the buoy and are completing final due diligence inspections. Deployment of the replacement CALM buoy to the field is currently targeted for the first quarter of next year with the resumption of production in the second quarter, although the team continues to explore ways to accelerate further, if possible. We hold comprehensive insurance coverage against both CALM buoy replacement costs and business interruption while Stag is offline. The total cover for the CALM buoy retrieval and replacement activity is around USD 30 million, which based on current estimates, should provide sufficient cover for those activities. Our business interruption insurance, which covers a meaningful portion of Stag's normal operating costs is available through May 2027, with the field expected back online around the same time. As Andrew mentioned, during the quarter, we'll expect initial insurance payments of just over $11 million, perhaps as soon as within a week. And that will cover both a share of the cost -- well, all the costs incurred on the initial retrieval attempts along with a portion of business interruption experienced. Additional claim reimbursements are expected through the back half of the year and into 2027. Lastly, with regard to production restart activities at the Woodside-operated CWLH field, all regulatory approvals have been obtained and the dive program to complete the riser J-tube repairs has commenced. Production restart is still expected around the end of Q3. Prior to commencing the campaign, the operator completed an onshore trial to rehearse and significantly derisk the offshore repair procedures. Once repairs are complete, the Okha FPSO will be reconnected and normal start-up sequences of safety, production and gas lift systems will be implemented over a period of days. On Slide 13, we reiterate the guidance from the trading statement issued in July, where our production range was updated to reflect the CWLH FPSO reconnection delays and Stag cyclone-related shut-in. Guidance on total production costs, excluding noncash impacts, is unchanged and is expected to be in the upper end of the range, primarily as a result of FX moves, especially the Australian dollar versus U.S. dollar movements and increased fuel and royalty costs associated with higher oil prices that have resulted from the Strait of Hormuz conflict. CapEx guidance is also unchanged, notably so, given the original guidance did not include the third contingent well in Malaysia. Consistent with our initial guidance in February, our CapEx guidance does not yet include Vietnam development CapEx, only the relatively minor amounts of capitalized G&A costs incurred prior to FID. Finally, our 2025 through '27 unlevered free cash flow guidance is maintained. As we did this year, this guidance range will be formally reviewed in early 2027 as part of the group's annual planning cycle and reserves evaluation. I also wanted to take the opportunity to reiterate that despite some externally generated and temporary operational headwinds, the group has maintained positive momentum, already delivering on many of our strategic objectives for 2026, a sign of the renewed focus and drive in the business in recent years under the new management team. We continue to prudently evaluate business development opportunities in the region, seeking opportunities where we can leverage our experience and diverse platform into creating value from existing assets and gas developments that pass our disciplined acquisition hurdles. I'd like to wrap up on Slide 14. Jadestone offers a compelling opportunity to gain exposure to the dynamic Asia Pacific regional economic growth story. We expect growing economies to underpin energy demand in the region, particularly gas, with Jadestone being the only independent E&P, which operates across Indonesia, Malaysia, Australia and Vietnam. This platform uniquely positions Jadestone to deliver both organic and inorganic growth, and we remain confident that we can do so for the benefit of all stakeholders. With that, I thank you for your time today. And operator, I'll now turn it back to you for question-and-answer session.

[Operator Instructions] Our first question comes from James Carmichael from Berenberg.

First, on net debt, I guess, obviously, cash flow performance is really strong in the first half. Just wondering how you see that progressing through the rest of the year, given your sort of commentary on potential working capital unwind. And I guess, any questions around lifting schedules. Just help to get a bit of color on that. And then looking at Vietnam, it looks like that's sort of edging forward with the FPSO approval and recommended platform and pipeline, contractors. Just wondering, I guess, what are the next steps ultimately between here and the farm-out and getting to FID? And then attached to that, I suppose, you referenced that the CapEx guidance includes limited predevelopment spend in Vietnam. Just wondering if there's anything you can say around what spend might be needed there if you sort of need to keep the project on track or if you get to that FID stage before farm-out?

Great. Andrew, do you want to take that first question and I'll jump in.

Yes. James, I think you probably get used to me, sort of saying, look, we don't provide guidance towards sort of our net debt forecast towards the end of the year, of course. But I mean, I think the element here is really very dependent on -- well, CWLH reconnection, clearly, there won't be a lifting in the back end of this year, will be moved into next year. So expect the overlift will continue from that perspective. And it's really, sort of, I think, through the back half of the year as was flagged, we don't have the CWLH lifting come in the back end of the year. We'll have Montara cycle through and clearly [ PM323 ] while we're still maintaining operating costs. So I think sort of directionally, that hopefully gives you a sense of travel certainly until we get those sort of [ cost ] liftings back into play next year.

Yes. So let me jump in on Vietnam project, James. And just a few critical steps left and the farm-out process is moving forward. So I'll touch on that as well. But really, from a project sanction standpoint, the last sort of firm requirements or physical requirements, if you will, are Petrovietnam approval of the field infrastructure contract award. Don't see any real challenges with that. It's been well socialized and good clarifications answered. I think that's coming in the near term. Hammering out, just kind of the last few details around the project finance and security structure is in latter stages and nearly complete. The farm-out is going quite well. We've had a lot of interest. We shortlisted down to a small set of select counterparties that have good technical capabilities, strong balance sheets. We've got some good competitive tension and healthy dialogue with those last few. That will likely -- once we get through the negotiations, it will take a bit of time to do the paperwork, of course, to paper up the joint operating agreement and finalize the farm-out agreement. So best efforts will sync those 2 together, but there's a possibility that we secure that, get it finalized and move through FID to keep the project on track and optimizing the schedule to the point we can with the final closing of that, if you will, a bit later because they're going to need to get an investment certification approval from the host government anyway. So the finalization of that probably will lag just behind project sanction a bit, but the deal should be done before then or about the same time. Capital requirements that could occur depending on timing, probably on the, let's say, $10 million plus, maybe a bit more if we achieve the ideal timing on the sanction. And then that will be at the conclusion of the farm-out, the equity share that we farm out would be reimbursed next year.

Our next question comes from David Round from Stifel.

Firstly, just on Malaysia, obviously, some really good results there. Interested where you are with the extension. What do you think needs to happen there? Does the drilling result or the drilling results change anything? I mean, does it change the terms? Does it change the likelihood of getting that extension? And actually, maybe I'll ask one on Stag as well. Just in terms of the installation, conscious of sort of the time line there, are there any weather considerations we need to be mindful of? Are there any sort of weather systems we need to avoid and hope sort of aren't as bad as they can be at that time of the year? Because I just checked that CALM buoy, it's just a like-for-like replacement.

Yes, I'll try to touch on all those, David, but feel free to remind me if I missed one. But on PM323, let's start with that. Look, the results of this program, and I didn't spend a lot of time on it. I don't want to get all technical on the call, but they were complicated wells. And the drilling design was different than any well we'd ever drilled in the PM32 (sic) [ PM323 ] license before because of the extended reach of them. So we had to drop down a hole size and do some other more challenging drilling operations. So our ability to execute and deliver those kind of results only bolsters our case for the extension. But we're in the final stages. The terms are largely agreed. We're working out a few details, but there's additional development potential in the field that we've done fairly detailed work. We still need to finalize it to fully mature it, but it could be some additional infill drilling and there's certainly associated and in some cases, non-associated gas resources there that can be developed under the license extension and with energy security and just growing energy demands, of course, the regulator is constructive and helpful in making sure every molecule is captured. And when you demonstrate the ability to execute and create value that others left behind like we have, I'd say that bodes very well. So a few details to work out. The terms are largely agreed, and I'm still bullish and still hoping we get that across the line in the very near term, but definitely optimistic that we're going to get it done and confident. On Stag, of course, we will have to incorporate into our planning during critical operations, which are not that long-lived, but there'll be periods of time where weather will be more impactful. Those aren't events that typically last for more than a few days, and there's good warning on them. So it's not like we're going to be sitting there -- it's not 0 risk, but it's not like we're going to be sitting there ready to deploy the CALM buoy and be isolated for 3 weeks. We'll plan around that. We know the weather patterns. Of course, you can get some unexpected things, and we'll have to build that into our planning. It's also why the team continues to look at are there any ways we can accelerate it and take advantage of the most ideal weather windows. But -- so it's something we're definitely conscious of, but we can plan and work around it with pretty minimal risk.

Okay. Just a quick follow-up, if I can. The Puteri cluster, I mean, we haven't heard about that in a little while. Is that connected at all to the license extension at 323?

No, no, it's not. It's a separate license, and we continue to work through what looks to be a good option for the redevelopment. But when we get more clarity on that, we'll be -- we'll share more information on it. But they're not related at all, no, to answer your question.

Our next question comes from Anish Kapadia from Hannam & Partners.

Just another question on Malaysia after the strong results today. I was just wondering if there's any updates on PM428 in terms of your plans over there and any updates on your drill and drop decision? And then second one, just given what we're seeing in terms of the events in the Middle East at the moment, the very strong gas prices you're seeing as well, I suppose kind of the strategic premium that's being placed on Asian gas. Obviously, you've got Vietnam, but Montara, the gas resource over there seems to be getting more interesting, more valuable. Can you -- it seems like you've been making some progress. Can you give a bit more detail in terms of what you've seen so far and the next steps on that?