Good morning, ladies and gentlemen, and welcome to the Jadestone Energy plc trading update conference call. At this time, all lines are in listen only mode. Following the presentation, we will 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, February 10th, 2022. I would now like to turn the conference over to Paul Blakeley, President and CEO. Please go ahead. Great. Thank you, operator. Ladies and gentlemen, good morning and welcome to Jadestone Energy's guidance conference call for 2022. I'm Paul Blakeley, Jadestone 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. In this call, I'll take you through a presentation which was recently uploaded on our website at www.jadestone-energy.com. It's in the investor relations section, or you can view it via the link on the webcast. After that, let's open the call for a Q&A discussion. Oh, and by the way, the 2022 guidance announcement release is also available on the website. So moving on. Slides two and three 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. First, just a quick opening comment on today's environment, where the upstream sector, after a very tough period, which was of course influenced by the first waves of COVID pandemic, is now buoyed by returning demand. After several years of underinvestment on the supply side, we believe supply will remain tight, and this will help underpin current prices for a while, albeit with some headline-driven short-term volatility. These strengthening macro fundamentals are not only supporting benchmark oil prices, but also the premiums for which we sell our production. For example, December's Stag cargo sold for over $12 a barrel above Brent, the highest ever. Last month, a Montara cargo achieved a premium close to $4 a barrel over Brent. In this part of the cycle, we find ourselves very well-positioned with a step-up in production volumes, a very strong balance sheet, debt-free, and ready to further build out the business, both organically and inorganically, while at the same time having the potential to increase shareholder returns in the likelihood of increased cash flows throughout this year. Now, let's move to slide four, where this is before we get into the discussion on the 2022 operational and financial guidance. I'd like to just remind you of our progress towards setting a target of net zero greenhouse gas emissions. We first introduced this principle in our 2020 sustainability report, and since then, we've been progressing the underlying analysis to underpin this target. We've engaged a respected third-party consultant to help us in this work and are making good progress, and I'll touch on this a bit more later on. Turning to operational and financial guidance for 2022. We expect production this year will average between 15,500 and 18,500 barrels of oil equivalent per day. That's a 36% growth over 2021 at the midpoint, with oil approximately 95% of expected production in the year and with no hedging in place currently. While we will see the benefit of the Montara H6 well and the Skua workovers throughout this year, this is partially offset by the extended annual shutdown on Montara planned for around 21 days, which accommodates inspections of the FPSO and testing of all pressure vessels within the production plant, something which is required every three to four years and which was last done in 2019. In addition, I should point out that we're currently running at reduced production rates on Montara after an engine failure in the gas reinjection compressor skid late last month. Fortunately, we had all replacement parts available in-country because an engine overhaul was part of this year's planned shutdown. More importantly, we also carry a full engine core as spare in our Darwin warehouse. This is a philosophy we've developed and continually assess inventory to ensure we carry critical items to prevent excessive downtimes wherever possible. This is particularly important at a time where movement of equipment and people is challenging. The engine change-out is currently on schedule with a new core being installed as we speak. I expect that full production capacity on Montara will be restored later this month. Guidance also reflects a scheduled annual shutdown at Stag, as well as an additional 10 days of downtime at Stag associated with rig moves during the drilling campaign later this year, but partially offset by the infill drilling, which should contribute new production in the fourth quarter. Ahead of getting clarity from New Zealand's upstream regulator on a timetable for completion of the Maari acquisition, we've decided to take a more prudent approach to exclude any contribution from the asset in our production guidance this year. This does not reflect any change in our view of this transaction at all. It's just the principle that timing is not in our hands, not in our control. When closing occurs, we'll simply enjoy the additional volumes. Both OMV and ourselves remain committed to the deal, and we're jointly working this as hard as we can. It's just worth reminding ourselves that all production and cash flow at Maari continues to accrue to Jadestone under the terms of our SPA with OMV. Unit operating cost guidance is set at $23-$28 per barrel of oil equivalent. The midpoint of this range represents about a 10% improvement on last year's outcome, and which would have been actually much more significant if not for the extended maintenance program scheduled for this year. Our capital expenditures are targeted to between $90 million and $105 million in 2022, with Stag drilling and the initial development spending on Lemang accounting for around 80% of the total. We've also reiterated our dividend policy with the underlying principle that we will grow the dividend in line with the underlying cash flow generation of the business. However, we also recognize that at current oil prices and with robust operational delivery, our cash position could increase very significantly at a time when we're also debt-free. This is balanced with the importance of meeting capital commitments and funding accretive growth opportunities, as well as being mindful that the majority of this year's CapEx is incurred in the second half of the year. Maintaining a strong balance sheet still remains vitally important to us. However, bearing all this in mind and subject to actual cash generation during the year, we will be considering additional shareholder returns either through increased dividends and/or share buybacks later in 2022. Now turning to slide five, which gives further detail on our production outlook for 2022, highlighting the 36% growth year-on-year at the midpoint of the guidance range. During the first half of January, we averaged around 20,000 BOEs a day, in particular seeing the benefit of the Montara activity program, which was carried out last year. However, today we're actually just over half this for a three to four- week period, which is associated with the reinjection compressor motor change-out that I've mentioned. The Stag infill drilling campaign is scheduled to commence in third quarter this year, with the impact of the 50H and 51H wells positively impacting on fourth quarter production and of course into next year. Finally, to give a sense of how the completion of the Maari deal could impact our production levels, when it occurs, we do expect gross production from the field to average between 4,500 and 4,700 barrels per day in 2022. Now moving to slide six, which highlights unit OpEx guidance in the range of $23-$28 per barrel. In line with our established approach, this range excludes well workovers. In any event, this well workover activity in 2022 will be significantly reduced when compared with 2021, which of course had included the well workover on the Skua-10 and Skua-11 subsea wells. At the midpoint, this year's OpEx guidance represents around a 10% reduction on 2021 outcome, which shows progress on cost containment is still being maintained, particularly when considering that the planned maintenance outages this year do have an impact. Slide seven summarizes our capital guidance for the year, where the Stag infill drilling comprises almost half of forecast spend, as well as initial activity on the Akatara development, which is approximately another 30% on the assumption that the project is sanctioned in the first half of this year. The Stag CapEx qualifies for the current Australian Tax investment incentive, where the full cost of a qualifying investment is immediately deductible against tax. As a result, the Stag expenditure is expected to reduce the amount of cash tax that we pay in the current year. Now to slide eight to provide a little more detail on our ongoing journey to net zero. Last year's sustainability report set out our net zero ambition, and during the second half of last year, we advanced this with an in-depth review of both physical and transition risks as well as opportunities associated with climate change. We've also undertaken further studies on the future emissions profiles of our assets and will layer in assumptions around future growth to make this analysis authentic and credible given our strategy. The emissions profiles were key inputs into an exercise which assessed the impact on our portfolio of several different climate change scenarios, including Paris alignment and net zero, as a consequence on our financial resilience. In turn, this has informed a recent internal assessment of possible net- zero pathways. Over the coming weeks and months, we'll be using these learnings to formulate a net- zero strategy, which we will share with you when the work is completed, and not later than mid-year. We've also been identifying where we can improve our sustainability reporting, most notably building on our initial TCFD disclosures in 2020, and expanding these to give fuller disclosure in the areas of strategy, as well as being clearer on metrics and targets. We anticipate that these enhanced disclosures will be included in our 2021 sustainability report, which we will be publishing later this year. Slide nine gives some added detail and illustrates the proposed locations of the Stag infill wells. The objective at Stag is to drill two wells into areas of relatively high oil saturation to ensure drainage of unswept oil utilizing existing wellbores as donors. We've identified well locations in both the northwest and east of the field, with several other potential locations emerging, which will provide opportunities for future infill drilling and helping to maintain a relatively flat profile at Stag for a number of years. If successful, each of the wells will add an initial day production approaching 1,000 barrels a day, just as the 49H well did a couple of years ago, after which we'll produce them at around 600-800 barrels per day. We expect that this year's drilling will pay back relatively quickly, particularly given current oil prices, and will develop around 2 million barrels of reserves and extend the field life of Stag by two years as a result. Now on to slide 10, which provides some detail on recent progress on the Akatara gas field development and the likely activity and milestones over the remainder of 2022. In the second half of 2021, we made significant progress on all commercial milestones, culminating in the signing of the gas sales agreement in December. Around the same time, we also announced that we were acquiring the remaining 10% stake in the project, while also advancing discussions with potential lenders with an intention to fund up to 60% of the project CapEx through debt. The key project work stream currently underway is the tender for the engineering, procurement, construction, and installation contract, which we expect to award as soon as the final investment decision has been made and which will keep Akatara on track for first gas in the first half of 2024. Now turning to slide 11, which provides an update on our growth projects and also touches on the current asset market. First, Lemang, which I've just covered. Move on and let's talk about Nam Du / U Minh, where we're encouraged by the Vietnamese government's backing for the project. Rising gas import prices, which are indexed to oil, continue to strengthen the commercial rationale for this project. We continue to push all stakeholders to engage on the commercial terms, and we'll report back on progress during the year. I mean, frustratingly, there's never been a better time for development of the Nam Du / U Minh gas fields, which will increase Vietnam's energy independence, support the country's growing economy, and assist in the country's energy transition following Vietnam's recent commitment to carbon neutrality by 2050. Now to New Zealand. The Crown Minerals Amendment Bill achieved Royal Assent in December 2021, which among other things, introduced a trailing decommissioning liability for upstream licensees operating in the country. We welcome this legislative change and recognize the importance that the New Zealand government places on the ability of licensees to meet their decommissioning liabilities when they fall due. We and OMV stand ready to work with the government in order to expedite the remaining approvals and complete this deal. A timely completion would be the interest of all parties, in particular, allowing the Maari JV partners to focus on maximizing the upside potential of the asset. Finally, we continue to see an active asset market in Asia-Pacific, fueled by the larger operators divesting mid-life upstream assets as part of their energy transition strategies. We've screened a lot of opportunities. We've actively participated in more than 10 processes over the past 12 months, and we're currently working in around half a dozen data rooms. Quality of the opportunities coming to market is increasing, and we have the capability, expertise, and access to funding to execute them. Inorganic growth remains a core part of our strategy alongside our organic growth projects, and this, therefore, is an exciting time in this market for us. Now wrapping up on slide 12, this sets out our work program for the year, and I'll just summarize. We're continuing to explore ways of increasing our operational efficiency at Montara and Stag, particularly maintaining high levels of uptime while driving down operating costs without compromising on safety. As we increase our understanding of the operated Peninsular Malaysia assets, we will look to roll out a similar program of production optimization and OpEx reductions, and we have already had some successes there. The Stag infill drilling program has already been discussed, and later this year, we'll commence planning for the proposed Skua 12 and 13 infill wells on the Montara asset, which we plan to have ready to drill by 2024. Following the August closing of the PenMal acquisition this year, we've already identified early infill drilling opportunities on the East Belumut field in PM323, and we're also planning these wells for 2023. On the Nam, we expect to move swiftly through to the execution phase later this year, following FID, and also hope for meaningful progress on Nam Du and U Minh. Finally, we continue to assess the prospectivity of our existing licenses, looking to identify the potential for further drillable prospects in close proximity to existing fields and discoveries. As an example, the 3D survey at Montara is proving to be very high quality as we start to look at opportunities beyond the next two Skua wells. It's an exciting time for us. Production is growing and we're unhedged in a rising oil price environment, and this will strengthen an already robust balance sheet. With an increasing number of opportunities and a strategy that is working well, we look forward to expanding the portfolio and further improving returns to shareholders this year and beyond. With that, I'd just like to say thanks for listening and, I'll now hand back to the operator and we can open for a Q&A. Thank you. Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press star followed by the one on your touch tone phone. You will hear a three-tone prompt acknowledging the request, and your questions will be polled in the order they're received. Should you wish to decline from the polling process, please press star followed by two. If you're using a speaker phone, please lift the handset before pressing any keys. One moment, please, for your first question. The first question comes from David Round with Stifel. Please go ahead. Thanks. Morning, Paul. Thanks for the update. Can I start with a question on production, please? I'm sure you're gonna probably steer us to the middle of the range, but I'm actually interested in the top of the range and what would be required to hit that. Because, you know, if I look at 18,500 barrels a day with downtime across the assets plus the compressor issue, that would be a pretty good outcome and probably points towards some of the assets doing better than expected. Wonder if you can comment on that and potentially what you're assuming for contributions from Stag in 2022. Secondly, you've mentioned the oil price and obviously a big beneficiary of that. Dividend is one thing that's absolutely fine. Just also wondering, does it change your thinking around the size of future M&A, and whether that would dramatically, you know, change the opportunity set there? Thanks, David. Okay. Let's try and answer your questions as you asked them. First, production. Of course, you know, when we put a range together, we are thinking of, you know, all the things that can go right and maybe things that we don't want to but could go wrong. You know, typically, you know, we are guiding to the middle of the range, naturally. You know, in the context of the assumptions that lead us to that and what, you know, might depart us particularly on the upside, if we think about history, you know, much of the challenge isn't actually in the activity itself. It's often in the timing. For example, last year, there was, I think, you know, a great opportunity for upside if the drilling rig had arrived early to Montara to drill the H6 well, and we hadn't encountered the well issues with the equipment that failed while we were drilling the horizontal section, and got the well on stream, you know, either on time or better still early. You know, that has a significant impact. I suppose, you know, the upsides would be around, you know, things that minimize time constraint. If the rig comes early to drill the Stag wells, you know, that will give us upside to the guidance. If we can shorten the shutdowns, and these are significant shutdowns for maintenance, this has a material impact on guidance. Of course, you know, having encountered the unplanned and unexpected event with the compressor motor on Montara, we have been trying to accelerate some of the planned work program to take advantage of this and therefore shorten the shutdown later on in the year. All of those things would improve on guidance. Finally, you know, just, you know, managing individual well performance and up times of the facilities, which is something that we've been concentrating on. You know, all of that can have a material impact. Perhaps just to give you some context, if we could... You know, if we think about a three-week outage, the math is fairly straightforward. You know, if you think about a three-week outage at Montara, you know, it's 500 barrels a day annualized, you know, plus or minus. You know, changing those outcomes for sure has a material impact on, you know, production outturn. That's how I would think about it. We will be working hard to minimize those periods when the facilities aren't producing at maximum rate. That's very clear. In terms of price, sure. This, you know, this is a great time for us. We've entered the year, I think, you know, significantly ahead in terms of cash on the balance sheet, and it will grow significantly while oil prices and strong premiums are where they are. We are optimistic that that will be the case through this year and potentially into next. So, you know, aside from the planned capital program, this certainly does allow. I'm gonna answer the question, you know, sort of reverse in the way you asked it. You know, this does allow us to, I think, you know, access potentially and fund adequately large M&A opportunities than perhaps we might otherwise have been comfortable with a couple of years ago. Having said that, I don't think that's going to yield many more opportunities. We look at things which are at the lower end of the range and things which would stretch us financially in terms of debt and potentially into equity. As always, it's just simply about the quality of the opportunity and the value we can create. Whether it's something that's gonna cost us $10 million, or whether it's something that's going to stretch us beyond, you know, let's pick a number, $500 million, it's still about quality. We remain really focused on achieving the investment criteria that make acquisitions worthwhile for us. It's all about follow-on capital value creation from future investment. Of course, you know, in the middle of all of this, as we move through the year and assess where we are financially, the strength of the balance sheet, our ability to deploy capital, new capital into M&A, it may well be, you know, clearly opportune for us to return some value to shareholders. You know, that's something that we will assess as the year goes on. And maybe one of three things. You know, we can either increase our existing dividend policy. We could, you know, provide a sort of a, you know, a one-off dividend benefit, or indeed, we could look at share buybacks as an alternative. All of those things we'll consider, you know, as we think about where the business is, where the balance sheet is, and where the environment is externally in reinforcing, you know, the strength of outlook into next year. Okay. That's great. Thanks, Paul. Thanks, David. Thank you. Your next question comes from Nathan Piper with Investec. Please go ahead. Morning Paul, morning, everyone. Three quick questions from me, please. On New Zealand, are you having any interaction with the appropriate regulators? Have they incorporated the legislation that has passed into their ways of working? What insights can you provide on them implementing those new decommissioning regulations and obviously then being able to approve the deal? Second one on Vietnam. I mean, it strikes me as a bit unfathomable why this has not progressed much faster, given the global LNG price. Then lastly, and maybe this is reflecting where we are in the U.K., but I have had some questions about windfall taxes in Australia and New Zealand, given the high oil prices. Is there any fear of that? I mean, I guess probably not given they're incentivizing your investment, but it'd be quite helpful to clarify that too. Thanks. Hi, Nathan. Thanks. Thanks for questions. New Zealand first. It's a long, hot summer in New Zealand currently. So, you know, long holiday period. The regulator is back at his desk now, has been for a couple of weeks. Both ourselves and OMV have taken the opportunity at the start of this new year to get in front of the regulator with our ideas jointly and separately on how we could speed this process along. You know, that's acknowledged by the regulator. It's being considered, but we don't have an answer on how they're thinking about it. You know, in the weeks ahead, we'll see what the response is and we'll see how you know how engaged they are and how responsive they are to what you know both the buyer and seller want, which is to move this forward to completion as quickly as possible. You know, I mean, there's very little, in my view, that stands in the way. And certainly we can be you know extremely responsive to you know what's needed in terms of providing the necessary security for decommissioning. We just need to see how the regulator responds. You know, I mean, at this stage, I just can't give you a sense. It's one of the reasons why we made the decision that you know we've. You know, we can, you know, we can set ourselves, you know, targets which we have no control over, you know, the potential to disappoint the market, or we can just simply say, you know, when we know more, we'll judge then how this is looking. Frustrating and not nearly as frustrating as Vietnam where, you know, all the logic is in favor of this development, but, you know, gaining, you know, traction and commitment, it just simply has proved difficult over the course of the last year. I think while prices continue to rise and imported gas is oil-price-linked and is running at, you know, extremely high levels right now, you know, I'm hoping this is really the opportunity to show, you know, not just all of the, you know, the clear benefits of a local project, you know, in terms of jobs and supply security and, you know, taxes and royalties and so on, but, you know, simple economic benefit to the gas buyer in including this gas in the, you know, in the mix. The environment's right. We're pressing the case hard. We have the attention of government beyond Petrovietnam. I think there is a broad recognition in the sense of the project. Let's see how we get on, and we'll report back to stakeholders in due course. Windfall tax, there's no noise of it right now. I mean, it's quite extraordinary to think, you know, we're still in a period of incentive for investment in Australia, for example, as you've described. While at the same time, you know, prices are at a record high. You know, but equally, you know, given the fiscal structure, you know, the government today is enjoying exceptional tax revenues across all sectors, given it's a resource economy. We haven't heard of any threat of windfall tax. I can't say any more than that. No, I think that was more reflecting local issues we have here in the U.K. and some of the conversations I was having with clients this morning. Yeah. Yeah. Thanks, Paul. That's very helpful. Cheers. Thanks, Nathan. Thank you. Your next question comes from Matt Cooper with Peel Hunt. Please go ahead. Hey, good morning. Yeah, thanks for the presentation. On Stag, I understand there's four wells in the 2P profile. I was just wondering that, you know, given the current very high premium there, you know, the tax incentives in your balance sheet, what stops you considering drilling all four of those wells back to back? Also a bit of a follow on from that, is there a 2C reserve at Stag that could support further drilling? Yeah. Thanks, Matt. We thought we were bold moving to two wells this year. Because of course, you know, if you think about drilling wells like this, there is a 12-month cycle of planning and long lead equipment orders and so on. These wells were in the sort of incubation stage, you know, early still, you know, early last year. To change that outlook is really not really practical, if you could get the equipment. I think, you know, we are on track for the two wells. We certainly see several other opportunities in the field. The more we collect data and understand the reservoir performance, I think the more encouraged we are that there'll be several locations that we can drill in the years ahead. The underlying philosophy here is you know, you can't materially change the outlook of Stag. What you can do is completely arrest decline, see a small amount of growth. It is actually a relatively low decline field. We can make it run for several years longer. I think as we point out, you know, these two wells do extend the field life by a couple of years. But because it's a low energy reservoir, we are limited to the number of well slots we can use. There's 12 well slots, and we have to give one up to drill a new well. 49 was easy because it was the remaining spare slot. The first of the two wells here will be reclaiming a slot that was not producing any oil. The second well that we'll drill, we're picking sort of, if you like, the next worst current production well, which is less than 50 barrels of production. You know, for all of those reasons, you sort of you're forced to pace yourself. You want to see a well, you know, decline significantly in order to reuse the slot. That's really you know those are the factors that really dictate Stag. Yeah, there is upside in reserve. But like everything with Stag, you know, it won't be huge. But there is an ability, and certainly in a high price environment like this, there's a significant ability for Stag to generate, you know, really decent free cash. We'll try to take full advantage of that as you know, as conditions allow. Okay. Yeah, that makes sense. That's very helpful. And two other quick ones. I just wonder. Mm-hmm. What percentage of Lemang CapEx you might look to debt finance? I also saw, unlike last year, I couldn't see a breakdown of the guidance into the various assets. If you could help with that would be great. I mean, let me ask Dan to speak a little bit, I think, to the debt market to help you understand where we are. I mean, Lemang is an attractive project for, you know, for debt financing. You know, given its life of field contract, you know, fixed price and so on, there's a great deal of certainty. In that sense, it's quite good. I think it might be helpful, Matt, to have Dan just, you know, give you a little color on, you know, how banks are viewing, you know, project financing, debt financing, up to what sorts of levels. Dan, why don't you pitch in here? Yeah. Thanks, Paul, and hi, Matt. We've traditionally talked about sort of two-thirds of the capital for both Vietnam and Indonesia to be debt -funded. That sort of remains our main working assumption. I think the reality is today and given the strength of the balance sheet, that the risk is sort of on the upside that we would leverage more than 60% or two-thirds. You know, our base assumption hasn't changed up until this point. We're engaged with a number of banks and are quite advanced in this work. You know, that's the expected outcome at this stage. Okay. That helps with that. Thanks. Thanks, Dan. Matt, the final question. The production split of that guidance. Yeah. You know, we've sort of given some hint in the past without being too specific. I think we can, you know, we can try and see how we can provide a little bit more granularity there. We've tended not to, but let me take that request away and see what we can do. Great. All right. Thanks a lot, guys. Thanks a lot, Matt. Thank you. Your next question comes from Mark Wilson with Jefferies. Please go ahead. Hi. Good morning, gentlemen. I'd like to ask regarding the Montara production facilities. You know, clearly such an important part of your production, even though production is diversifying to various other areas. What level of maintenance CapEx should we expect on this FPSO going forward? And just remind us again of what's involved in these major three-year shutdown cycles and whether you see any potential for those to extend. You said there's quite major work going on with them. This is in the context of this compressor issue. In terms of maintenance, what is such a key component of your production? Just to speak to that and the view over the next few years. Great. Thanks, Mark. Yeah, let me give you a sense of how we think about maintenance of the facilities. I will focus on Montara, as you suggest, given its importance to the business. Just, you know, by way of stepping back, of course, when we inherited the facilities at the point of acquisition, as you'll recall, you know, there were challenges. You know, a number of you know, enforcement actions by the regulator against the prior operator and the facility where we observed, you know, a number of issues that needed to be fixed and therefore, even before the transfer of operatorship, there was an extended shutdown in order to fix those things that, in our view, were essential for the safe future running of the facility, and all of that was taken care of. It helped inform us of the maintenance programs going forward. We felt that the right way to manage facilities, Montara and others, is to take a you know a far more you know detailed look at individual component maintenance requirements, try to group them into a way that you could more efficiently take care of them through short duration maintenance shutdowns, and then longer shutdowns for those things that required, as opposed to what's a more traditional view, which is, you know, we'll plan 14-20 days every single year. The way we deal with that, and Montara is the example, is we will have short shutdowns every year, which are typically associated with safety-critical testing of you know key components in the infrastructure. Just to give you an example, one of the key ones would be all emergency shutdown valves, safety-critical emergency shutdown valves that protect the facility, you know, in the event of incidents. There is typically an annual inspection regime to make sure all of those valves work as they're designed to work in the time they're designed to close and so on. That forms the backbone of our annual cycle, which we try to limit to seven days a year. Then in addition to that, there's the larger, longer cycle programs which would be associated with, let's say, major tanks inspections on an FPSO, on a process plant, internal inspections on all pressure vessels, pressure pipework and so on, to be tested. Those typically are on a three to four -year cycle. That forms the basis of our longer shutdown program. We took care of all of that in 2019 at the point of transfer of the facility when we took, you know, the extended shutdown. That cycle's just come round again. Here we are. There's nothing more specific or underlying in terms of facility issues. I would say over the course of the last three years of operating Montara, you know, we've learned a lot, and we found some things that have had to be fixed, and we fixed them. Nothing major. Control systems that weren't working efficiently, as an example. Things that actually improve uptime performance, not required for any underlying safety, process safety issues. What we're embarking on in 2022 is actually that formal three-to-four -year cycle coming round, where we will open up every single vessel for its three-to-four -year inspection. That's how you should think about it. Going forward, I think we'll try and provide you know a little bit more detail to help understand you know what's behind our maintenance shutdown programs each year, and particularly those which are extended. While this is an extensive shutdown, it's still only 21 days. For us, you know, we try to limit and as I talked about earlier, you know, wherever possible to deliver upside production performance, it's actually about uptime and minimizing times when the facilities aren't actually producing. I hope that gets to your point. In terms of CapEx or OpEx, you know, a lot of maintenance is actually operating costs. Mm. You know, along with a longer shutdown, it'll be elevated this year, but not significantly. You know, I think, you know, you should think about this in the range of, you know, what $1 million-$3 million, you know, small to large shutdown. It's that sort of range. I suppose, you know, Mark, as a final point, just to give you a sense of the improvement and the progress we're making. You know, in 2017, I think, in the last, you know, sort of full year of operatorship Montara in the previous owner's hands, you know what I mean, you know, as I recall, uptime performance was somewhere in the low 70% range. Last year, the Montara facilities operated at 96.4%. Now, we had, of course, with the drilling operation at Montara H6, we had additional shutdown associated with the rig move and some SIMOPS on the Montara facility, on the Montara platform, which added 10% to downtime. You know, that wasn't related to facility reliability. I think it's important to leave the message that actually we've made huge inroads in providing, you know, far greater stability to Montara operations. Oh, thanks for that, Paul. That does give confidence and some clarity there. That's good. Yeah. Second question would be, regarding Maari. My question there is, we can do the math on the cost and the working capital adjustment, assuming that this deal completes at some point. What is the expectation internally that you may have to post some kind of escrow bond, in order to you know, secure regulatory approval? Have you got any thoughts around that of magnitude or possibility of that we could, you know, we'd have to adjust our bond numbers? I mean, it's an interesting thought. Of course, we have already over the period of time last year in engaging with the regulator made clear you know, the sort of options that we would imagine they would consider. They would naturally include you know, something which provides, if you like, you know, underlying security. Now, of course, with the new regulation in place, you know, one might argue that the underlying security is the seller because there is now a trading liability. As is typical in the North Sea, you know, that sort of risk is typically no longer with the government; it's between buyer and seller. Now, with this new regulation, the sort of the same feature really applies in New Zealand, but there's no history, track record, experience, and comfort around that. To your question, yeah, I mean, I think I can imagine the government, you know, both practically and politically, feeling the need to see some sort of security in place, tangible security in place. But you know, given the strength of the profile and so on, this is something that would not materially impact on the you know, on the deal from our perspective. But it is something we're imagining and something we are prepared to discuss with the government. Okay. Thank you for that. I'll hand it over now. I'd just also like to say, while on the call, good luck to Dan with the move back to Australia, and I hope the search for your replacement is going well. I think we might have Dan on one more call. Dan, would you like to say something? That's right. Yeah. I'm working through to the end of April, so we'll continue to be talking quite a bit, Mark. Okay. Got it. Thanks, Mark. Thank you. Your next question comes from Alan Ruff. As a private investor, please go ahead. Hi, Paul. I was just hoping you could clarify the six Stag workovers, like what the cost of those is and whether they're included in guidance anywhere or not. I understand they're not in the OpEx guidance. Historically, I think they were part of major spend with CapEx, but I can't see them in CapEx. Just looking for some clarity there. Sure. Thanks for the question. I'm gonna ask Dan to speak to the way in which we allocate for workover costs. You know, historically, we've never included them in our analysis, OpEx review, just simply because they're sort of unpredictable, reactive and not part of the base operating costs. In terms of, you know, how we account for them and where you would see them, Dan, why don't you address that question, please? Yeah. Thanks, Paul. Hi, Alan. So last year we did two subsea workovers at the Montara Complex. You know, they're not expected, they're not planned for, and they were abnormal, if you like. Given the scale of that activity, we included it as part of our major spend, so-called guidance. Normally, our CapEx guidance is all CapEx. Last year it included a significant amount with respect to those two well workovers, the two subsea well workovers. Given its scale, we thought it was important to track it separately and include it and not include it in our normal OpEx to barrel guidance, given the scale of activity. As Paul says, the irregular nature, as we've just in the past sometimes described the London bus, characterization of the Stag well workovers. We've tended not to include it because it can distort comparisons from quarter to quarter or half- year to half- year. We have six well workovers, as you note, in the plan. That cost isn't separately included, but you can think of that as something in the region of around $9 million plus or minus. Thank you. That's very helpful. Thank you. Your next question comes from Ian Croesdale as an investor. Please go ahead. Hi. Good morning, gentlemen. Two questions. First one's on Maari. Horizon Oil Limited, your potential partner on the asset, have indicated that their decommissioning liability is around $31 million at the moment. That would indicate that OMV's liability is around $80 million. How would that be worked into any future equation on completion? Also one question on Lemang. The proposed debt for that development, is that included in the $200 million RBL that was previously talked about, or is it separate? Thank you. Great, Ian. Thanks. Thanks for the questions and, you know, and thanks for asking questions which I can very easily hand over to Dan to answer. Just, you know, by way of preface to them. Could you just clarify to me, just remind me, in Horizon's analysis, were they quoting Australian dollars, US dollars or Kiwi dollars? Do you happen to know? I believe they always quote U.S. dollars, whereas Q quotes Australian dollars. Okay. I think. Okay. I think it's U.S. dollars. Thanks. Thanks a lot, Ian. Okay. Of course, you know, post-tax and pre-tax to think about. Let's, you know, so how do we think about this and, you know, what would be the way in managing that in the context of thinking about security? I mean, you know, basically, there are a number of ways that we can deal with this through security arrangements. Some of them, you know, may even involve, you know, physical cash. You know, just to give you an example, in a PSC environment in Southeast Asia, you actually accrue on a unit of production basis, the decommissioning costs, you know, over the life of the PSC. That's certainly an option here. The problem we have is until the government, you know, tells us, we're not actually sure what the preference will be. Until we get in front of them, it's hard, you know, it's hard to know precisely. In terms of how we would, you know, think about that liability on the books and how we would manage that, I mean, Dan, you know, what would you add? Yeah. We talked a bit about this at the time of the announcement of the transaction. I think, you know, when you work through the different pieces, including the tax and look at the total economic cost to Jadestone for his share, as I say, net of the tax, which we would receive back, and under the New Zealand tax laws, we would receive back a significant portion of tax at that time, even if we had no other producing assets in New Zealand at the time. That brought the net number down into something in the region of $52 million-$54 million in that range. Now, that was based on estimates and analysis that was done as part of the due diligence in 2019. Of course, in the time that's passed since then, decommissioning work continues to accumulate and experience and costs and an understanding of how to do decommissioning continues to mature worldwide. Bear that in mind. You know, you should think about Jadestone's net share after tax as something in that region. That was the estimate of that we talked about at the time of the transaction announcement. Paul, should I go on to the debt piece? Yes, please. Thanks. Thanks, Dan. The $200 million facility that we had mandated the banks for back in Q1 of 2020 was really gearing up for sanctioning Vietnam. Of course, as you'll be, I dare say you'll appreciate, with the advent of COVID and the very significant drop in the oil price that occurred in the early phases then, the Vietnamese took a different tack, and we delayed the project with all of the uncertainty around cash flow and the balance sheet. Although we'd mandated banks, we had not signed that facility and so we had sort of put that in the fridge as it were. Move forward to today, we're now borrowing for the basis of Lemang. It is a different facility. The RBL market has changed certainly in that time as well. There are some different features that will be incorporated into the new facility. It will be a different facility than the one that was contemplated at the time of Q1 of 2020. I hope that answers the question. Yes. Thank you. Great. Thanks, Ian. Thank you. There are no further questions at this time. Mr. Blakeley, you may proceed. Great. Well, thank you very much, operator. It's just to say thank you for your interest in Jadestone. And thank you for participating in the call. You know, as we've discussed, we find ourselves in a really strong financial position today, with a great outlook for 2022. Strong production, high oil prices and premiums, and an active program to deliver further growth. Inorganic opportunity is exciting as well. And, you know, as we will shortly declare a firm ESG commitment on emissions and the potential for incremental returns to shareholders, you know, I hope all of that will have you find Jadestone a compelling investment case. With that, you know, thank you once again, and 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.