Good morning, ladies and gentlemen, and welcome to the Jadestone Energy half-year results conference call. At this time, all lines are in listen-only mode. Following the presentation, we'll conduct a question and answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. This call is being recorded on Thursday, September 9th, 2021. I would now like to turn the conference over to Paul Blakeley, President and CEO. Please go ahead. That's great. Thank you, Colin. Ladies and gentlemen, good morning, and welcome to our mid-year 2021 results conference call. I'm Paul Blakeley, CEO, and I'm joined on the call today from Singapore by Dan Young, our Chief Financial Officer, and on the line from London by Phil Corbett, Investor Relations Manager. Phil joined us just earlier this month. I'd like to welcome him to the Jadestone team and hope investors and analysts will feel the benefit in us having Phil based in London. In this call, I'll be referencing slides in a presentation which you can find on our corporate website by logging on to www.jadestone-energy.com, where you'll see it was recently uploaded under the investor relations section. If you're using the webcast, the slides should be available via the link on your player screen. Our first half 2021 report is also available for download from our website. Slide two of the presentation outlines our standard disclaimers. In particular, the cautionary remarks regarding the use of forward-looking statements and non-GAAP measures. Then on to slide three, which sets out a simple agenda for today's call, where I'll cover a brief business update before handing over to Dan for the financial review. After that, a few concluding remarks, then we'll get to the Q&A. Now moving to slide four, which summarizes our performance during the first half of the year. Oil prices, which started to recover in late 2020, continued to rise in the first half of 2021 as COVID-19-related economic restrictions started to relax following the widespread rollout of vaccines. However, economic activity is far from fully restored and the impact of the Delta variant continues to weigh on confidence. Overall, we're in a much more constructive environment for returning to investment and growth. Let me start with just a few words on our ESG strategy as we work to embed this across the organization. We're keenly aware that the environmental footprint of our operations needs to be continuously managed as we target further reductions in flaring and diesel use across our producing assets in 2021, on top of the improvements in performance that we made last year. This, along with a number of other targets, represent tangible and measurable performance towards meeting our social and environmental obligations alongside operational and financial objectives. Business performance benefited from a lifting schedule which played into improving prices and allowed us to generate a 50% increase in revenues compared to the first half of 2020 and before taking into account hedging income. This fed through into a significant increase in adjusted EBITDA year- on- year, and helped support a strong balance sheet at mid-year, close to $100 million, once the proceeds of a June Montara lifting, which were received in July, are included. This performance, together with a brighter business outlook in general, has given us the confidence to raise the interim dividend by 10%. Operationally, production from Montara and Stag was down year- on- year, primarily due to natural field declines and of course, the deferral of the 2020 activity program. Nevertheless, production in the first half of this year was slightly ahead of our plan. Total operating costs over the same period were well contained, and together with the recovery in oil prices, this first half performance helps underpin the significant investment activity in the second half of the year with the Montara H6 infill well and the Skua workovers. We also continued to execute our inorganic growth strategy, acquiring interest in Peninsular Malaysia, which add significant production reserves and running room, together with a net upfront cash receipt of $9.2 million on closing. The combination of the Malaysia acquisition, together with the Montara activity program, as well as a catch-up on Stag workovers, gives us line of sight to around 20,000 boe/d by year end. Aspects of our ESG performance and strategy can be seen on slide five, which updates a slide that we've shown before and which is an extract from our sustainability report. This was published in May alongside our annual report, and it details, amongst other things, our sustainability strategy, certain key objectives we've set ourselves, and our strengthened reporting. In parallel with the broad investments in the business, we're looking to follow up on the 15% reduction of total greenhouse gas emissions in 2020 by targeting a further 5% reduction across our producing assets in 2021. We aim to achieve this by continuing to increase the uptime of the reinjection compressor at Montara, by prioritizing usage of produced gas over diesel to run our operations, and by enhancing our own greenhouse gas emissions reporting to support improved operational practices. Improvements in discharges to sea and waste management will also be reported, while elsewhere, our social targets are also measured. For example, the number of nationals employed by Jadestone increased to 91% from 88% at the end of 2020. Graduate, apprentice, and intern programs are expanding as well as increased focus and improved awareness as we manage our business and protect our workforce in an ongoing COVID world. Safety performance in the first half was good. We maintained our zero LTI record, though unfortunately, we have had two separate and unrelated incidents requiring medical treatment during this current quarter. Thankfully, not significant enough to result in LTIs. Nonetheless, we regret these instances, are working to ensure full recovery of the two individuals, and will learn to prevent any reoccurrence. Turning to slide six, which provides an update on Montara and Stag. Combined production from the assets averaged 9,934 bbl/d in the first half, which was slightly ahead of plan. As I've already said, lower than the first half of 2020, given natural declines and deferral of work program, and also impacted by an unscheduled outage at Montara for replacement of a series of faulty valves within the compressor system. We expect to reverse this production decline in the second half of the year through the investment program we've outlined, part of which was deferred from 2020 due to the COVID impact on oil prices in the early stages of the pandemic. The current activity included in this program consists of the Montara H6 infill well, two workovers at Skua, and a backlog of workovers at Stag. Production at Stag has been impacted in recent months by a delayed workover schedule following repairs to the hydraulic workover unit and our limited access to workover crews, both resulting from COVID-related travel restrictions. However, in recent weeks, we've been able to address this backlog, and production is increasing at the same time as we enjoy a significantly higher price environment than has been prevailing over the past 12 months. Stag production also continues to benefit from strong pricing premia, with a cargo in the first half of the year selling at around a $13 barrel premium to Brent, and more recently, just over $10 per barrel. Moving on to slide seven, which gives some detail on the Montara H6 infill well. This well was targeting undrained oil close to the bounding fault on the west of the field, as can be seen on the depth at the top right-hand side of the slide, which highlights the gamma ray trace path. During the first attempt to drill the horizontal section in the well, we encountered mechanical issues with equipment which is used to steer the horizontal well path and measure downhole well parameters. As a result of this, we experienced a sudden deviation of the well trajectory and had to sidetrack and redrill this section of the well. I'm pleased to report that the sidetrack was successful. We have encountered over 1,200 meters of high-quality oil-bearing sands in line with our pre-drill expectations. As you can see, this is shown on the resistivity chart on the bottom of the slide. The downhole work is now all but complete, and we're looking forward to bringing this well on stream in the very near term at the previously guided initial oil rate of around 3,000 bbl/ d or more, with the well paying back in less than 12 months. Turning to our development projects. First, the Lemang PSC onshore Indonesia on slide eight, where we've achieved significant commercial progress. This follows a June 2021 ministerial decree which allocated gas sales from the Akatara gas field in the Lemang PSC to PLN, a subsidiary of the national electricity utility. The Heads of Agreement, or HOA, was quickly executed with the buyer, and which includes all the key commercial terms. Now we move to negotiations to turn this into a fully termed gas sales agreement. The ministerial decree and the HOA specify a first gas date, a gas sales profile with the plateau period illustrated on the chart on this slide, and a gas price of $5.60 per million BTUs. We're looking to sign the gas sales agreement by the end of this year and reach final investment decision on Lemang within the first half of next. In parallel, we're progressing FEED optimization work for the project and preparing tendering scopes of work with the aim of being ready to take a final investment decision on the project. This timing is consistent with meeting the projected first gas date in early 2024. I'm pleased that we've reached this stage in just over six months from acquisition of our 90% stake in the asset. It's a testament to leveraging our local team's significant experience in Indonesia. You can see from slide nine that we haven't yet reached the same level of progress in Vietnam as we have with Akatara. We continue to work with all stakeholders on the development of the Nam Du and U Minh gas discoveries. Combined, these fields represent a significant resource, strategically located to deliver gas to the Cà Mau power and industrial complex in the southwest of the country, at a time when existing supply is in decline. We've continued to work with PetroVietnam over gas sales terms, with all parties having acknowledged that there's a significant and growing gas supply shortfall into the Cà Mau complex from 2024 onwards. This provides a compelling argument for the development of our fields being the only alternative gas source, competitively priced, and which can be delivered in the timeframe to offset declining supply. It's frustrating that this project isn't advancing as quickly as we'd like. However, engagement with PVN has been slow, primarily due to the impact of the pandemic in Vietnam, where most recently, cases have been rising sharply and extensive lockdowns have made negotiations extremely difficult. Nonetheless, there are encouraging signs within PetroVietnam and government departments of an increasing recognition of the impending shortfall in Cà Mau supply, and we remain hopeful that further progress can be made before year end. Turning now to our recently completed Peninsula Malaysia acquisition, which is summarized on slide 10. Announced in late April, the deal was concluded just over three months later, thanks to great support from Petronas and the hard work of our experienced team, many of whom are KL-based. At signing, we announced a consideration of $9 million, subject to completion adjustments, which, when including the net cash generated since the 1st of January, was reversed to a net cash receipt of $9.2 million on closing. It's a great transaction. The acquisition consists of interest in four PSCs, with the two operated assets comprising around two-thirds of the overall production net to Jadestone. At the time of the announcement, we guided to net production levels of around 6,000 boe/d, but we're currently running ahead of this as we work to integrate the assets into our business. The immediate focus over the next six months is a detailed review of all of the assets in order to identify efficiency gains and potential upside opportunities. In particular, we do see upside for infill drilling locations on the operated assets, but with first activity likely in 2023, following detailed technical reviews and the mandatory approval processes which will come next year. I look forward to updating you more on our Peninsular Malaysia assets in due course, but so far, we're very happy with the transaction and the platform it provides for future activity in the country. With that, let me now hand over to Dan, who will take you through the financial review. Dan? Thank you, Paul. Good morning, everyone. Turning to slide 11. As Paul mentioned previously, production averaged 9,934 bbl/d in the first half, down around 18% on the first half of 2020 as a result of natural production declines and the unplanned shutdown in April at Montara to replace a number of critical valves on the compressor on the FPSO. Notwithstanding, first half production actually came out slightly ahead of plan. Despite the decline in production, sales volumes were slightly up year-on-year due to the schedule of liftings amounting to a little over 2 million bbl. The average Brent price incorporated into our liftings in the first half of 2021 was almost $65 a barrel, compared to around $38 a barrel in the same period last year, demonstrating the rapid recovery in benchmark oil prices, which commenced in early November last year. Sales premium to Brent continued to improve, with the latest liftings achieving $10.15 a barrel and $1.17 a barrel at Stag and Montara respectively. With the change to the shuttle tanker model at Stag, the premium negotiated for each Stag lifting is now typically based on a CIF basis rather than an FOB basis. As a result, care needs to be taken in making comparisons with 2020 premium for the period up until September 2020, when the switch to the tanker model occurred. Overall revenue of $138 million in the first half represented an increase of 19% year-on-year. The first half 2020 revenue includes the benefit from the company's prior cap swap hedging program, which concluded in September last year. Excluding the impact of hedging, revenues were up 50% year-on-year. Production costs have increased year-on-year, with the main component of this increase being a circa $9 million inventory adjustment to reflect the overlifting position at the end of the first half. Workover costs were also higher by a bit over $4 million, reflecting the resumption of activity at Stag during the second half of last year, and some of the early work on the Skua well workovers. There were also smaller increases due to higher operational staff costs, repairs and maintenance, such as the activity at the Montara FPSO in April, and adverse FX moves in Australia. There was also a small increase in transportation costs following the change in offtake arrangements at Stag. Although the termination of the Dampier Spirit FPSO resulted in a cash saving of around $4 million in the first half. Overall, unit operating costs per barrel were $28.16 a barrel before workovers, an 18% increase on first half 2020, predominantly due to lower production as a result of natural field decline, coupled with the higher operational costs just mentioned. Our underlying or adjusted EBITDAX was nearly 80% higher from first half 2020, which I will cover in more detail on the next slide. Operating cash flow prior to working capital changes was broadly flat year-on-year, but noting that the first half 2020 included over $20 million of receipts on our swaps, which is excluded from adjusted EBITDAX. Cash and cash equivalents at the end of the period totaled $48 million, which excludes the proceeds of the June Montara lifting, which was received in July. Including these, $46 million of proceeds are pro forma net cash at mid-year was close to $100 million, with no debt after the final tranche of the reserve-based loan having been paid off earlier this year. Through the resilient cash flow generation over the past three years, we've been able to repay the loan according to the original September 2018 amortization schedule of the RBL, and despite the initial 91-day shutdown in late 2018 to address the inherited backlog of maintenance and inspection, despite a heavy capital program in 2019 with the light well intervention and umbilical work, and the oil price impact of COVID-19 in 2020. We were able to repay according to that original amortization schedule without any review events or any amortization acceleration. Slide 12 presents the detailed EBITDAX calculation for the first half in our usual format. Adjusted EBITDAX includes three adjusting items. Firstly, it excludes swap costs of just over $4.5 million. These are swaps we took out in December and January, covering around 30% of our production in the first half of 2021. In order to protect the 2021 return to growth organic capital program, that is the H6 infill program and the Skua workovers. Secondly, it excludes non-recurring preparatory costs associated with Skua workovers, including an ROV inspection and design and planning work. Finally, there are a number of one-off project costs and corporate costs in the third bucket. This includes costs associated with inorganic business development activities, Maari transition costs, and the costs associated with the new UK Topex. This bucket also includes COVID-19-related costs, net of the Australian JobKeeper receipts. Collectively, the adjusted or underlying EBITDAX is nearly 80% higher than first half 2020, with the recovery in oil prices far outweighing the increase in production costs during the first half of this year, demonstrating the very significant operating leverage of the business. Slide 13 presents our cash bridge in the usual format. The recovery in oil prices in the first half is evident in the $138 million of revenue generated in the first half. Production costs are covered in my earlier comments, which includes the non-recurring costs associated with the Skua workovers that I just mentioned. In the first half, there were several items included in G&A which are non-recurring, and which I also just mentioned, associated with business development activity, COVID-19 expenses, and costs associated with the new UK Topex, as well as the costs from the first half swap program. Most of the CapEx of $16 million in the first half was primarily related to preliminary work and long leads ahead of the drilling of the H6 development well at Montara. We also paid the second and final 2020 dividend in June of $5 million, which brought the total dividend payments to shareholders in respect of 2020 to $7.5 million when you include the Q3 2020 interim. Finally, the change in working capital during the period primarily reflects the overlift position at period end. There were no liftings at either Stag or Montara in December 2020, whereas there was a $46 million lifting in June 2021, meaning an investment into working capital of $46 million. This cash was received in July and is included in the mustard color in the last column. As discussed earlier, this results in cash balances of $48 million at period end, rising to $94 million once the proceeds of the June Montara lifting are included. Moving now to slide 14. The strong operating performance of the business during the first half, combined with increasing oil prices, resulted in close to $100 million of cash at midyear with no debt. A robust balance sheet position, I'm sure you will agree. The acquisition of the Peninsular Malaysia assets has also further diversified our production and cash flows, and thereby further increasing the resiliency of the business. Our dividend policy is meanwhile unchanged. We intend to declare dividends semiannually, split one-third interim and two-thirds final. We are a growth-oriented business, and as such, we target a conservative balance sheet that allows us to continue to reinvest into our portfolio's high returning and rapid payback organic investment opportunities, and to capitalize on inorganic growth opportunities as and when they emerge. The positive progress on both Indonesia and Vietnam gas projects mean that the group will be undertaking significant capital investment in the near term. We continue to expect that both projects can be substantially debt-funded, although equity will be required and a good portion of this will likely be front-loaded. We also want to retain financial flexibility to capitalize upon tuck-in and medium-size acquisition opportunities that meet our strict evaluation criteria. Overall, our aim is to have a progressive dividend which grows in line with cash flow generation, but does not constrain the business in pursuing its growth objectives, as I've just described. With this framework in mind and Jadestone's strong balance sheet and increasing diversification, we are pleased to announce today a 10% increase in the interim dividend to $0.59 per share, which we expect to pay on the 1st of October. A final comment on dividends. Today's positive announcement shouldn't be interpreted to mean we plan to increase the dividend by 10% each year going forward. This is particularly important today as we look to the potential for significant increases in capital to be invested in our organic gas developments over the next two to three years. Next, an update on guidance on slide 15. There is no change to any of our guidance metrics from the recent update in August. Production guidance remains at 11,500 boe/d-13,500 boe/d. With the anticipated contribution from the H6 well and the Skua workovers beginning to have a positive impact in the fourth quarter. Both unit OPEX and major spending guidance are also reaffirmed. Turning now to slide 16. The significant recovery in oil prices that started in late 2020 has allowed us to reactivate our Australian organic capital program, which was deferred from last year. The successful drilling of the H6 well, combined with the expected contribution from the Skua workovers, will reverse the recent natural declines from our Australian assets. Combined with the recently acquired Peninsular Malaysia assets, we have a clear line of sight on significant production growth towards the end of 2021, shown here within the green dashed rectangle. While it is no longer part of our formal production guidance, we illustrate the expected contribution from the proposed Maari acquisition in gray on the right-hand side in order to show the potential for further production growth once this transaction completes. Both the seller and Jadestone remain committed to this transaction, and remain confident that the transaction will be completed, though timing of government approvals is alas, beyond our control. Let me now hand back to Paul. Thanks, Dan. Let's finally turn to slide 17, where I'll summarize. We weathered the toughest of years last year, making difficult decisions to preserve our balance sheet. As we'd hoped, we left 2020 stronger than when we entered it. This really set the business up to bounce back as we enjoyed economic recovery and strengthening oil prices through the first six months of 2021. This helped underpin a strong first half for Jadestone, and I think we're now so well-positioned for further growth against an improving macro backdrop. We aim to deliver this growth at the same time as improving our ESG performance. In particular, aiming to reduce the greenhouse gas emissions of our existing oil-based assets whilst also changing the portfolio mix going forwards and pushing ahead with our major gas developments, providing essential energy whilst also helping to reduce the need for coal-fired power in both Indonesia and Vietnam. Near term, we've line of sight on significant production growth towards the end of this year, as we've discussed, both through the ongoing Australia activity program and the contribution of the recently acquired Malaysia assets, while Maari is still within sight, too. Today, we're unhedged, offering full exposure to the ongoing strength in oil prices, while premiums are holding up as well. We further demonstrated our ability to make highly accretive acquisitions this year, and I remain confident in the potential opportunity set across the region and our ability to capitalize on it. Portfolio rationalization by the majors, accelerated by a broader energy transition agenda, and with the additional fallout from an upcoming period of consolidation in the sector, will all help provide opportunity for more growth. We won't sacrifice our rigorous approach to screening, and in particular, meeting our subsurface expectations with identified investment upside and meeting our returns thresholds. We're also assessing asset quality through an ESG lens to ensure we can find ways to continually reduce environmental impact as we look to a future which will demand even more rigorous standards in order to maintain key stakeholder confidence. Our growth will be supported by further strengthening of our balance sheet and consistent with our stated philosophy. As Dan has said, we intend to provide shareholder distributions with improving cash flows while not compromising our growth objectives. Hence today, as discussed, we're delighted to increase the interim dividend for 2021 by 10%. With that, I'll hand back to Colin, and let's open up for a Q&A discussion. Thank you. Thank you, Paul. Ladies and gentlemen, we'll now begin the question and answer session. Should you have a question please press star follow by the one on your touch tone phone, you will hear a three tone prompt acknowledging your request and your questions will be pooled in the order of their received. Should you wish to decline from the polling process, please press star follow by two, if you're using a speakerphone please lift the handset before pressing any keys, or we're also able to accept your questions by a Twitter at Jadestone Energy. Your first question comes from David Round from Stifel. David, please go ahead. Great. Thanks. Thanks for the presentation, guys. Can I start with Montara and Stag? Presumably, you're getting to the stage where you're starting to plan for 2022. Obviously, not asking about production or CapEx guidance or any specifics, but are you able to give us a sense of what the hopper looks like after H6 and the workovers, and should we expect much activity next year? Secondly, just on Maari, obviously, legislation processes is out of your hands. Have you got any sense for how quickly you could complete the deal post the legislation being put in place? Thanks, David. Let's start with Montara and Stag. I suppose if I were to offer some thoughts on future potential activity on both assets. Thinking back, before the oil price collapsed in 2020. As you know, we had planned a further Stag infill well which we postponed, as we did Montara H6. We've also talked in the past about further sub-sea wells at Skua and other opportunities around Montara, not least, that may be defined by the new 3D seismic survey that we shot at the beginning of last year. All of that says, yeah, there are a number of opportunities that are in the hopper, if you like, and things that we will consider as part of future work program. Bear in mind that we'll also be thinking about capital deployment associated with the gas developments with Lemang and Nam Du, U Minh in Vietnam over the course of the next 12- 24 months, too. Mixing all of that in with balance sheet and financial capacity and so on. Those are the sorts of things that we should think about. Does that give you a sense, David? Yeah, that's good. Like you say, you've mentioned things in past presentations. Really it's a question of, are those opportunities still there? It sounds like maybe you'll be adding some post interpreting the seismic. That's it. None of this has gone away. Indeed, wells at Stag beyond 50 in our thinking too. There's quite a lot of organic activity for growth as we think about pace, capital allocation, and so on. For Maari, yeah, you're right. The timing essentially is out of our hands at the moment. Our submission is complete, reviewed by the government. We believe it sufficiently addresses the main issue of the new amendment bill around abandonment security, in light of the draft bill that we've obviously seen and reviewed. The timing is probably more centered around the passage of that bill, which I believe the Ministry have suggested should be before the end of the year. We'll see. As to our own readiness, we do have a small team that have been and remain on standby. As soon as we have a positive signal, we could move to close very quickly. There is very little that would stand in the way, particularly as you recall that the offshore operation is managed through a third-party contractor. It would be a very quick and very straightforward transaction to complete. Very clear. Thanks, Paul. Your next question comes from Mark Wilson, from Jefferies. Mark, please go ahead. Thank you. Good morning. I'd like to ask you a couple of questions regarding Vietnam, please, if I may. The first one is, Paul, is there a scenario where M&A opportunities could eclipse the Vietnam development opportunity? That would be the first question. It leads on from the fact you speak to high CapEx for your gas developments in the next few years. That ties into the first question. One common thread across all of your assets, and I include Lemang in that, is the production history that they all have that you can look at. Vietnam doesn't have that. I'm just wondering, if you do move towards development, how comfortable are you with 100% stake in that, and would you consider farming it out? There's the two questions regarding Vietnam. Thank you. Thank you, Mark. Well, let's just try and put this in context. I suppose, a couple of remarks that I would make about Nam Du, U Minh. The first is, we do have a lot of history of assets in this region, in this part of the basin. Given its proximity, for example, to PM3, and indeed our own past interests in this part of the Vietnam sector. We have a great deal of comfort and confidence in the geology. Notwithstanding, as you rightly say, there's no production history from these assets. From our own technical work on the discoveries at Nam Du, U Minh, less so far on Tho Chu. In the area immediately adjacent to Nam Du, U Minh, we see a lot of upside potential through the technical work we've done. Actually, we remain really excited about this and will want to continue to pursue, to push very hard for its development for all those reasons. Simply, the belief that this is gas that absolutely has a home into Cà Mau and will be developed. In the context of comparing with M&A, the returns of Vietnam, which we talked about in the past, are very compelling. I think it will always compete for capital. In the middle of a growing portfolio, will its importance be any less? It's hard to say, Mark. My view is this is a really high-quality asset with a lot of running room, a lot of upside, and it will stay in the portfolio. As to its funding, do we retain 100%? We've often talked about, at the right time, testing the market for a farm down to share the burden on the capital phase at an appropriate point in time, which almost certainly is once all of the commercial arrangements are agreed, gas sales profile and so on. There will be a point in time when it's something that we'll consider, but it'll always have to be balanced with our own view of the value. We'll certainly consider it. Does that answer your questions? No. Thanks, Mark. Very good answers. Thank you. Just as one follow-up, regarding current production, you were asked about Stag infill wells in the future. Clearly, a Montara well like H6 has a higher impact on your production. Is there scope for future infills at Montara, or do you think that the geology doesn't allow it? Indeed, is there well slots subsea to take possibly a H7 in the future? Thank you. Okay, thanks. I think if you look at the map, the drainage from Montara is now very much complete. There is a possible, the team have identified the possibility of one more well up in the, what should we say, the northeast of the field. That would be more high risk. I think the focus at Montara will be more into the satellite fields. Certainly, the team are pretty excited about incremental reserves potential within the Skua, Swift and Swallow area. Of course, what we hope from the 3D survey to refine and highlight more locations. It's less likely to be in the Montara field itself. Okay, understand. Thank you for those answers. Thanks, Mark. Perhaps just to remind you, one last point. Of course, Montara is an oil rim under a large gas cap. Of course, remaining value in Montara, once drilling of oil wells is completed, of course, is a significant gas volume, given the news that Shell are moving forward with the Crux development, which is very close by. That would be a future for the Montara field itself. Next. Your next question comes from Matt Cooper from Peel Hunt. Matt, please go ahead. Hi. Good morning. Thank you very much for the presentation, and congratulations on the success at the H6 well. I've got three questions, if that's okay. First one, so you've now been operating Peninsular Malaysia for about a month. Can you give some detail on any surprises you've found to date, whether they be positive or negative? In particular, the reasons for production currently being 10% above your previous guidance of 6,000 boe/d. Second question is back to Vietnam. When do you think is now the likely earliest possible timing on FID and first gas there? Third question, I just wondered if you could talk a little bit about if you're considering including a net carbon zero commitment in the sustainability report to be published next year. Thanks, Matt. Wide range of questions. Let's see how we can try and get to answer them. Peninsular Malaysia, first off, one month in, very early days. We're reporting production performance ahead of our announced 6,000 boe/d as simply actuals. There are some swings and roundabouts on wells and fields. I don't think there's any underlying trends that would give us, at this early stage, a sense of where upside or downside exists. It's just too early. Pleasingly, performance is steady. The team who, of course, have come together virtually, have never met each other. The whole deal from start to finish has been a virtual activity. The team are actually performing really well, and that's an important part of the early outcome. Too early to say, I'll be perfectly honest with you. Certainly no signals that take us away from believing this is an asset of the quality of which we expected. On Vietnam, earliest gas date, if everything fell into place, it's so hard to predict. The way I might answer your question, if we think about the work and the engagement with PetroVietnam, which is actually focused on the supply/demand issues, and an increasing view that a shortfall in existing supply starts to open up significantly in 2024, late 2024. That would imply a successful project really does need to be sanctioned late 2022. Thinking again, approximately a two year turnaround to first gas. That gives you a sense of where activity would need to be to get to that. It would mean gas sales agreement and a resubmission of FDP and a reactivation of project activity, over the course of, what should we say, the next 12 months in order to deliver for an end 2024 first gas. That would be, I think, the very earliest you could imagine. On net carbon zero commitment, when we published, our whole emphasis in the context of our sustainability report, has been to ramp up on target setting, reporting, raising awareness across the organization, and establishing, if you like, a baseline. Continuous improvement in emissions reductions, discharge reductions, and so on, is a key feature and part of our investment. Capital and operating costs, one-off operating cost investment, which is aimed at improving performance on the assets very often, and in some cases intentionally, has an incremental benefit on these things. I'll give you one example. Late last year or middle of last year, we shut down our H3 gas injection well on Montara and installed a larger choke, with the aim to be able to reinject higher volumes of gas and reduce flaring. Things like that become part of our thinking in terms of improving asset performance from an environmental perspective. Very specifically to your question, as, excuse me, as part of our commitments, we did say we will work towards a statement on carbon zero in the future. Okay. That's all very clear. Thank you, Paul. Your next question comes from James Carmichael from Berenberg. James, please go ahead. Hi. Morning, guys. Just a couple of quick ones. Just on the shift in the premium of Stag from FOB to CIF. Maybe just provide a bit of color around that and just to confirm I'm right in thinking that there's ultimately sort of no change to the net economics for you from that shift. I guess just thinking about the ESG targets, et cetera, that you've outlined. Just interested to get a sense of how, or if, they sort of feed into your asset screening on the M&A side and whether that's had an impact on any of the packages that you've looked at over the last few months. Thanks. Thank you, James. I think what I'll do is I'll let Dan speak to Stag premiums first, and that'll give me a minute or two to answer the second part of your question. Dan, over to you. Yeah. Thanks, Paul. Look, I think just to give you, James, just to give a bit more color on Stag. Look, the premiums at Stag in the second half of last year were tracking in a weaker environment. We're tracking around $6, and the premiums this first half, the second listing was the one that Paul talked about that was over $13, closer to $14. On average, around $11 for the two listings we've done so far in the first half, and the latest listing is just over $10 a barrel. We've definitely seen an improvement in the margin overall as a result of improving macroeconomic environment, et cetera. In terms of the CIF/FOB differential, because we're using the same vessel, I think actually there's an improvement for us relative to just the overall vessel market economics. You'll see there's a transportation piece in our costs that are now in our financials, and that's tracking at around $1 a barrel. If you wanted to do a raw comparison, the best thing to do is to deduct about $1 a barrel, based off where our transportation costs are tracking at the moment, to look at the new margins, deduct about $1. I think, roughly, if it was general market conditions and we had to contract a specific vessel for that listing, to take that on an FOB basis and move it to the customer, I think it's more likely to be around $1.50 or perhaps a bit higher. I think for us, actually, we're doing slightly better as a result of having the ability to tie it in with the vessel that's there at Stag under the shuttle tanker model. Does that make sense, what I've said there? Yep. No, that's clear. Thanks. Great. Thanks, Dan. To your question on do we assess ESG characteristics, if you like, in our acquisition strategy. I mean, the short answer is yes, we do. Probably increasingly so. Not least, James, if we think about significant opportunities where bank debt might feature, as well as thinking about investor response, these are things that we simply can't ignore. As we take a position in our view, sorry to just step back a second, but if I use the IEA report on net zero emissions by 2050 as the challenge, where really the narrative is around no new exploration and no new big green field development, but absolutely a requirement to invest in existing producing oil and gas fields to meet energy needs. This is our niche strategy. As they also say, with a view to improving environmental performance in whatever ways you can. This is a feature. Just as I answered earlier, some investments in Montara and in Stag to improve environmental outlook. When we take an M&A opportunity, we're also looking at what investment opportunities there are to change its performance outlook in environmental terms, as well as in production and cash flow terms. Most recently, we have been in the data room and identified an essential capital investment to improve environmental performance as part of the acquisition and as part of underpinning our ability to fund it. I think, it's a feature today, James, and I think it'll be a feature that will grow even more strongly in the future. Ladies and gentlemen, should you have a question, as a reminder, please press star followed by one and ensure that your speaker phone is off. Your next question comes from Ian Crosdale at a private investor. Ian, please go ahead. Hi, good morning, gentlemen. My question is about Maari and the legislation. The legislation's at select committee stage, and there's been quite a few submissions from your oil and gas peers effectively complaining that the legislation is too harsh. Is the board comfortable with the legislation in its current form, and would you be happy for that to go through to Royal Assent as soon as possible? A secondary question, there seems to be similar legislation coming out in Australia and potentially in other mature basins like Malaysia and Indonesia. Do you see that affecting M&A in the future, given potentially more decommissioning liabilities for those operators leaving the basins? Hi, Ian. Hi. Thanks very much for the questions. Let's try and work our way through. First of all, yeah, like you, clearly, who've read the submissions, so have I. Yes, there seems to be a general thread that the proposed legislation is too draconian and why should previous stakeholders have a trailing liability long after they've left? Well, of course, in principle, I think what is being proposed by the New Zealand government in the heart of all of the noise is essentially just an absolute requirement for no repeat of the debacle with Tamarind and Tui, and an absolute requirement for previous owners to be held accountable for who they sell an asset onto, and that the decommissioning liability is met. That's no different in principle to the North Sea or other jurisdictions where there is, if you like, mature legislation that deals with the end of life issues. It was always absent from New Zealand and Australia, not uniquely, but unusually. Hence, it had to be fixed. Unfortunately, it's taken an event that's accelerated the need to fix it. In our view, what's proposed by the New Zealand government is workable, and in our submission to the government, we believe we've more than fully met all of the conditions that they would require from a buyer of the asset in order to secure decommissioning security. The one thing that we can't offer is the seller's trailing liability and commitment. That's something that, in the case of Mari, of course, sits with OMV, and we'll see. This is not unusual legislation in its broad frame. If it provides certainty to deal structure, then there's no reason why transactions can't move as seamlessly and effectively as they do in the North Sea. Almost exactly the same applies in Australia, where the legislation is largely about a trailing liability that exiting interest owners will remain, if you like, on the hook in the event that decommissioning costs aren't met by the current owners. Absolutely consistent with the North Sea. I don't see why companies would effectively shy away from that. In the context of the rest of, let's say, Southeast Asia, broadly speaking, Malaysia, Indonesia, as your example, they're PSC environments where decommissioning costs are established through a cess fund throughout the life of production. In most cases, funding for decommissioning has already been collected by the government, if you like, or the regulator, or whoever is responsible for that. A great example, a case in point is our acquisition of the Peninsular Malaysia assets from SapuraOMV. The cost for decommissioning the facilities is already fully met. The fund is full and will cover the cost of decommissioning facilities. Wells are an ongoing decommissioning cost as they become used and as we perhaps might want to access well slots and abandoned wells. That's something that you have to take care of. The major cost for decommissioning facilities, largely across the PSC regimes of Indonesia and Malaysia, they're already covered and cost recoverable. Very efficient funding mechanism already in place. Does that get your questions, Ian? Yeah. That's great. Thank you very much. I do have a quick question for Dan, if you don't mind as well. Sure. The CapEx spending is heavily weighted to H2. Wondered if he had a view on the impact for the cash position towards the end of the year. Dan, I'll let you answer that. Thanks, Ian. We don't give guidance or a number out for cash at the end of the year. You're right, of course, that the great majority of the spend, the major spend this year is the second half of the year. I'll take the opportunity just to reinforce that this year's guidance is characterized as major spend because it includes those Skua workovers, which are technically treated as OPEX under the accounting rules, but those aren't regular operating. That's very far from regular operating activity, and it's something we keep out of the OPEX guidance but track this year under the banner of major spend. You're right, of course, that the activity is much more weighted to the second half. As we've talked about today, as we see this outlook to around 20,000 boe/d towards the end of the year, we will see the benefit of that investment rate lastly in 2022. Cash by the end of the year will be impacted by that. Depending on oil prices, depending on what happens with Maari, of course, as well, it's very hard to be more specific. We think the business can comfortably afford the dividend we're talking about today, and be on track to continue the growth trajectory out into 2022 and beyond. Great. Thank you. And just. I guess the dividends probably covered by the $9 million from the PM assets, more or less. In terms of the early question, we were positively surprised in terms of the cash that we inherited at closing. That was about $4 million higher than our own internal projections at the time we signed the deal. That cash that we inherited is certainly helpful in the overall picture as well. We'll continue to remain focused on what we can do in terms of a final dividend once we get through the end of the year. Great. Thank you very much, gentlemen. Thanks, Dan. Ian, just a final point from me, just to give you a sense of cash flow management. Whilst the outflow in the second half of this year for this activity will start to generate significant incremental cash flows from production. In my remarks, I did say H6 pays back in less than 12 months, so it just gives you a sense of where investment timing and returns, the sort of horizon for the returns. Less than 12 months is an investment I'd do every day of the week. There are no further questions at this time. I'll turn it back to Paul. That's great. Thanks a lot. In closing, my thanks to you all for joining the call, for all the questions. We do really appreciate your interest. We're really pleased to have reported a strong first half this year and delighted with the acquisition of Peninsular Malaysia and progress on activities which will boost production by year-end up to around 20,000 boe/d. As we've just discussed, all the cash flow that will be generated from that. In the months ahead, we'll look to provide updates on H6 and the Skua well performance. We'll look to update you on progress on the gas developments, as well as on the new assets in Peninsular Malaysia. We certainly hope to be able to report progress on Maari too in due course. We remain really excited about further M&A in the region, as we've discussed, as we see a number of majors seeking to exit and a number of assets coming to the market. We think this is a really great time as markets stabilize, prices remain strong, and consumption starts to pick up again. With that, thanks once again. I wish you all a great day. Thank you. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.