Jadestone Energy plc (JSE) Earnings Call Transcript & Summary

Good morning, ladies and gentlemen, and welcome to the Jadestone Energy plc [ Training ] Update Conference call. [Operator Instructions] This call is being recorded on Thursday, February 10, 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's 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 by the link on the webcast. And after that let's open the call for a Q&A discussion. And by the way, the 2022 guidance announcement release is also available on the website. So moving on, Slide 2 and 3 outline our standard disclaimers, and in particular, the cautionary remarks regarding forward-looking statements and non-IFRS measures used in this presentation. So with that we can get started. But first, just a quick opening comment on today's environment, where the upstream sector, after very tough period, which was of course influenced by the first waves of COVID pandemic, is now by buoyed returning demand. But after several years of under investment 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, and for example, December's Stag cargo sold for over $12 a barrel above Brent, the highest ever. And last month, a Montara cargo achieved premium close to $4 a barrel over Brent. And so, in this part of the cycle we find ourselves very well positioned with the 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 4, where -- and 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 introduce this principle in our 2020 Sustainability Report and since then we've been progressing the underlying analysis to underpin this target. So we've engaged the 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. So 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 expecting production in the year, and with no hedging in place currently. While we will see the benefit of the Montara H6 well on the Skua workovers throughout this year, this is partially offset by the extended annual shutdown on Montara planned for around 21 days, which accommodate inspections of the FPSO and testing of all pressure vessels within the production plant, something which is required every 3 years to 4 years and which was last done in 2019. In addition, I should point out that we are 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 the country, because an engine overhaul was part of this year's planned shutdown, but more importantly, we also carry a full engine core spare in our Darwin warehouse. And this is a philosophy we've developed, and continually assess inventory to ensure we carry critical items to prevent excessive downtime wherever possible. And this is particularly important at the time where movement of the equipment and people is challenging. The engine change out is currently on schedule, with a new core being installed as we speak. And 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. And 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, the timing is not in our hands, not in our control. And so when closing occurs, we'll simply enjoy the additional book volumes. Both OMV and ourselves remain committed to the deal and we're jointly working this as hard as we can. And it's just worth reminding ourselves that oil production and cash flow of Maari continues to accrue the Jadestone under the terms of our SPA with OMV. Unit operating cost guidance is set to $23 to $28 per barrel of oil equivalent. The midpoint at this range represents about 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 '22 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 recognized that with current oil prices and the 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, and so maintaining a strong balance sheet still remains vitally important to us. However, bearing all in this mind, and subject to actual cash generation during the year, we will be considering additional shareholder returns, either through increase dividends and/or share buybacks later in 2022. Now turning to Slide 5, which gives further detail on our production outlook for 2022, highlighting the 36% growth year-on-year, the midpoint of the guidance range. During the first half of January, we averaged around 20,000 boe 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 3 week to 4 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 into third quarter this year, but with the impact of the 50H and 51H wells, positively impacting on fourth quarter production, and of course, into next year. And then, finally, to give us 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. And now moving to Slide 6, which highlights unit OpEx guidance in the range of $23 to $28 per barrel. In line with our established approach, this range excludes well workovers. And in any event, this well workover activity in '22 will be significantly reduced when compared with 2021, which of course had included the well work 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 7, 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 the 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. So now to Slide 8, 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, and 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 will 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'll be publishing later this year. Slide 9, gives some added detail and illustrates the proposed locations of the Stag infill wells. The objective at Stag is to drill 2 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 couple of years ago, after which we'll produce them at around 600 to 800 barrels per day. We expect that this year's drilling will pay back relatively quickly, particularly given current oil prices. And we'll develop around 2 million barrels of reserves and extend the field life of Stag by 2 years as a result. So 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 to 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, so move on, and let's talk about Nam Du/U Minh, where we're encouraged by the Vietnamese government's backing to 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. And that's the 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. And finally, we continue to see an active asset market in Asia Pacific fueled by the larger operators divesting midlife upstream assets as part of the energy transition strategies. We 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 [ funds ] 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. And so 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 increased 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 Lemang, we expect to move swiftly through to the execution phase later this year following FID and also hope for meaningful progress on Nam Du/U Minh. And finally, we continue to assess the prospectivity of our existing licenses, looking to identify the potential for further global 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 2 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. And 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 Q&A. Thank you.

[Operator Instructions] The first question comes from David Round with Stifel.

Can I start with a question on production, please? I'm sure you're going to 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 a compressor issue that, that would be a pretty good outcome and probably points towards some of the assets doing better than expected. So wonder if you can comment on that, and potentially what you're assuming for contributions from Stag in 2022? And secondly, just you've mentioned the oil price, and obviously a big beneficiary of that. Dividend is one thing that that's absolutely fine. Just also wondering, does it change your thinking around the size of future M&A, and whether that would dramatically change the opportunities out there?

Okay. Let's try and just answer your questions as you ask them. And so first production, of course, when we put a range together we are thinking of all the things that can go right, and I guess things that we don't want to, but could go wrong. And so, typically, we are guiding to the middle of the range naturally. In the context of the assumptions that lead us to that, and what might depart us, particularly on the upside. If we think about history, much of the challenge isn't actually in the activity itself, it's often in the timing. And so, for example, last year there was, I think, 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're drilling the horizontal section, and got the well on stream either on time or better still early. That has a significant impact. So, I suppose, the upsides would be around things that minimize time constraint. If the rig comes early to drill the Stag wells, 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. And of course, 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 in the year. So all of those things would improve on guidance. And then, finally, just managing individual well performance and uptimes of the facilities, which is something that we've been concentrating on, all of that can have a material impact. And perhaps just to give you some context, if we could -- if we think about a 3-week outage -- and the math is fairly straightforward. If you think about 3-week outage at Montara it's 500 barrels a day annualized, plus or minus. And so, changing those outcomes, for sure, has a material impact on production outturn. So that's how I would think about it. And 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 is a great time for us. We've entered the -- I think, 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. And we are optimistic that will be the case through this year, and potentially into next. And so, aside from the planned capital program, this certainly does allow -- and I'm going to answer the question, sort of, reverse in the way asked it. This does allow us to, I think, access potentially and fund adequately larger M&A opportunities than perhaps we might otherwise have been comfortable with a couple of years ago. But 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, and potentially into equity. So as always, it's just simply about the quality of the opportunity and the value we can create. And whether it's something that's going to cost us $10 million or whether it's something that's going to stretch us beyond, let's pick a number, $500 million, it's still about quality, and we remain really, really focused on achieving the investment criteria that make acquisitions worthwhile for us. And it's all about follow on capital value creation from future investment. And, of course, in the middle of all of this, as we move through the year and assess where we are financially and the strength of the balance sheet, our ability to deploy capital -- new capital into M&A, it may well be, clearly, opportune for us to return some value to shareholders. And so, that's something that we will assess as the year goes on. And maybe one of 3 things, we can either increase our existing dividend policy; we could provide a sort of a one-off dividend benefit; or indeed, we could look at a share buybacks as an alternative. So, all of those things, we'll consider as we think about where the business is, where the balance sheet is, and where the environment is externally in reinforcing the strength of outlook into next year.

Your next question comes from Nathan Piper with Investec.

3 quick questions from me, please. And 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? And what insights can you provide on their implementing those new decommissioning regulations, and obviously then being able to approve the deal? Second one on Vietnam. I mean, it strikes me it's a bit unfathomable, why this has not progressed much faster given the global energy price. And maybe if you could provide a bit more insight as to why it is so slow. And 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.

Nathan, thanks for questions. So, New Zealand first. And it's the -- it's a long hot summer in New Zealand currently, and so long holiday period. The regulator is back at his desk now, has been for a couple of weeks. And 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. That's acknowledged by the regulator. It's being considered, but we don't have an answer on how they're thinking about it. And so, in the weeks ahead, we'll see what the response is. And we'll see how engaged they are and how responsive they are to what -- both the buyer and seller want, which is to move this forward to completion as quickly as possible. I mean, there's very little in my view that stands in the way. And certainly, we can be extremely responsive to what's needed in terms of providing the necessary securities for decommissioning. We just need to see how the regulator responds. And so I mean, I just -- at this stage, I just can't give you a sense. And it's one of the reasons why we made the decision. We've -- we can set ourselves targets that you have no control over with the potential to disappoint the market, or we can just simply say, when we know more we'll judge then how this is looking. Frustrating -- and not nearly as frustrating as Vietnam, where all the logic is in favor of this development, but gaining traction and commitment it just simply has proved difficult over the course of the last year. I think, while prices continue to rise and import gas is oil price linked, and is running at extremely high levels right now, I'm hoping this is really the opportunity to show not just all of the clear benefits of a local project in terms of jobs and secured supply and taxes and royalties and so on. But simple economic benefit to the gas buyer, and including this gas in the mix. So the environments, 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 to 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 we're still in a period of incentives for investment in Australia, for example, as you've described. While at the same time, prices are at record high. But equally given the fiscal structure the government today is enjoying exceptional revenue -- 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.

I think that was more reflecting local issues we have here in the U.K. and some of the conversations that having with the clients this morning.

Yes.

Your next question comes from Matt Cooper with Peel Hunt.

So on Stag, I understand this fall wells in the 2P profile. I just wondering that given the current very high premium there, the tax incentives in your balance sheet, what -- kind of what stocks you're considering drilling all 4 of those wells back-to-back? And also a bit of a follow on from that is, is there a to 2C results at Stag that could support further drilling?

Yes, thanks, Matt. We thought we're bold moving to 2 wells this year, because, of course, if you think about drilling wells like this, there is a 12 month cycle of planning, and long lead equipment orders and so on. And so these wells were in the sort of incubation stage early -- still early last year. And so to change that outlook is really not really practical if you can get -- even if you can get equipment. So I think, we are on track for the 2 wells. We certainly see several other opportunities in the field. And 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. And the underlying philosophy here is, 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. And we can make it run for several years longer. And so, I think, as we point out these 2 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 wells slots we can use. There's 12 wells 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 2 wells here will be reclaiming a slot that was not producing any oil. And 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. So for those -- all of those reasons, you sort of you're forced to pace yourself. You want to see a well decline significantly in order to release the slot. So that's really -- those are the factors that really dictate Stag. And yes, there is upside in reserve, but like everything in Stag, it won't be huge. But there is an ability -- and certainly in a high price environment like this, there's a significant ability to Stag to generate really decent free cash. And we'll try to take full advantage of that as conditions allow.

That makes sense. And 2 other quick ones, I just wonder what percentage of remaining CapEx, you might look to debt finance. And I also saw, unlike last year, I couldn't see a split down as a guidance into the various assets. So if you could help with that, that would be great?

Yes, 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 attractive project for debt financing, given its life-of-field contract, fixed price, and so on, there is greater uncertainty. So, in that sense, it's quite good. But I think it might be helpful, Matt, to have Dan just give you a little color on how banks are viewing project financing, debt financing, to what sort of levels? So Dan, why don't you -- why don't you pitch in here?

Yes, thanks, Paul. And Hi, Matt. We traditionally talked about sort of 2/3 of the capital for both Vietnam and Indonesia to be debt funded. And 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 2/3. But our base assumption hasn't changed up until this point. We're engaged with a number of banks quite advanced in this work. And so that's the expected outcome at this stage.

Thanks, Dan. And Matt, your final question.

[indiscernible] that guidance?

Yes, so we've sort of given some hints in the past without being too specific. I think 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.

Your next question comes from Mark Wilson with Jefferies.

I'd like to ask regarding the Montara production facilities. Clearly, such an important part of your production, even though production is diversifying to potential areas. So what level of maintenance CapEx should we expect on this FPSO going forward? And just remind me again what's involved in these major 3-year shutdown cycles, and whether you see any potential for those to extend. You said there's quite major work going on with them. And this is in the context of this compressor issue. So 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.

Thanks Mark. Yes, let me let me give you a sense of how we think about maintenance of the facilities, and I will focus on Montara, as you suggest, given its importance to the business. And so just by way of stepping back, of course, when we inherited the facilities at the point of acquisition, as you will recall, there were challenges. A number of enforcement actions by the regulator against the prior operator. And the facility where we observed 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 facility. And all of that was taken care of. It helped inform us of the maintenance programs going forward. But also we felt that the right way to manage facilities, Montara and others, is to take a far more 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 cycle, short duration maintenance shutdowns, and then longer cycle, longer shutdowns for those things that are required. As opposed to what's a more traditional view, which is, we'll plan 14 days to 20 days every single year. And so, the way we deal with that, and Montara as the example is, we will have a short shutdowns every year, which are typically associated with safety critical testing of key components in the infrastructure. And just to give you an example, one of the key ones would be all emergency shutdown valves -- safety, physical emergency shutdown valves that protect facility in the event of incidents. And there is typically an annual inspection regime to make sure all of those valves work as they're designed to work and the time they're designed to close and so on. That forms the backbone of our annual cycle, which we try to limit to 7 days a year. And 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 plants; internal inspections on all pressure vessels, pressure pipework and so on to be tested, and those typically on a 3-year to 4-year cycle. And so that forms the basis of our longer shutdown program. And so we took care of all of that in 2019 at the point of transfer of the facility, when we took the extended shutdown, and so that cycle has just come around again. And so here we are, there's nothing more specific or underlying, in terms of facility issues. I would say, over the course of the last few years of operating Montara, we've learnt a lot and we found some things that had to be fixed and we fixed them. Nothing major control systems that weren't working efficiently, as an example. The things that actually improve uptime performance not required for any underlying safety -- process safety issues. So what we're embarking on in 2022 is actually that formal 3-year to 4-year cycle coming round, where we will open up every single vessel for its 3-year to 4-year inspection. So that's how you should think about it. And going forward, I think we'll try and provide, a little bit more detail to help understand, what's behind our maintenance shutdown programs each year, and particularly those which were extended. And so, whilst this is an extensive shutdown, it's still only 21 days. But for us we try to limit. And as I talked about earlier, 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, a lot of maintenance is actually operating costs. Along with a longer shutdown it'll be elevated this year, but not significantly. I think you should think about this in the range of $1 million to $3 million -- small to large shut down. It's that sort of range. And I suppose, Mark as a final point, just to give you a sense of the improvement and the progress we're making. In 2017, I think, in the last sort of full year of operatorship Montara in previous owner's hands, I mean, 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 movements, some SIMOPS on the Montara facility, on the Montara platform, which added 10% to downtime. But that wasn't related to facility reliability. And so I think it's important to leave the message that actually we've made huge inroads in providing far greater stability to Montara operations.

Thanks for that, Paul. That does give confidence and some clarity.

Yes.

Second question would be regarding Maari, and my question there is, we can do the math on the cost and the working capital adjustment, assuming that, that still completes at some point. What is the expectation internally that you may have to post some kind of escrow bond in order to secure regulatory approval? And if you've got any thoughts around that of magnitude or possibility of that, that we could -- we'd have to adjust our bond numbers?

I mean, it's an interesting thought. And, of course, we have already, over the period of time last year, in engaging with the regulator made clear the sorts of options that we would imagine they would consider. And they would naturally include something which provides if like your underlying security. Now, of course, with the new regulation in place, one might argue that the underlying security is the seller, because there is now trading liability. And so as is typical in the North Sea, that sort of -- 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 that there's no history, track record, experience and comfort around that. And so, to your question, yes, I mean, I think I can imagine the government, both practically and politically, feeling the need to see some sort of security in place -- tangible security in place. But, given the strength of the profile, and so on, this is something that would not materially impact on the deal from our perspective, but it is something we're imagining, and something we are prepared to discuss with the government.

I'll hand it over. Now, I'd also like to say well, on the call that good luck to Dan with the move back to Australia. And I hope that the search for your replacement is going well.

I think we might have Dan on one more call. But Dan would like to say something?

That's right. Yes, I'll be -- I'm working through to the end of April. So we'll continue to be talking quite a bit of time.

Your next question comes from [ Alan First ] as a private investor.

I was just hoping you could clarify the 6 Stag workovers. Like what the cost of those is, and whether included in guidance anywhere or not? I understand they're not in the OpEx guidance? And historically, I think they were part of maybe spend with CapEx, but I can't see them in CapEx. So just looking for some clarity there?

Sure, thanks for the question. I'm going to ask Dan to speak to the way in which we allocate for workover costs. And, historically, we've never included them in our analysis of OpEx we reach simply, because they're sort of unpredictable, reactive and not part of the base operating costs. But in terms of how we account for them and where you would see them, Dan, why don't you address that question, please?

Yes, thanks for Paul. Hi, [ Alan ]. So last year, we did 2 -- we did 2 subsea workovers at the Montara complex, and they're not expected, they're not planned for and they were abnormal, if you like. And so -- and given that scale of that activity, we included it as part of our major spend, so called guidance. But normally, our CapEx guidance is all CapEx, but last year it included a significant amount with respect to those 2 well workovers -- the 2 Skua well workovers. And so, given its scale, we thought it was important to track it separately included and not included in our normal OpEx per 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 because it can distort comparisons from quarter-to-quarter or half year to half year. We have 6 well workovers as you note in the plan that cost isn't separately included. But you can think of that as something in the range of around $9 million plus or minus.

Your next question comes from [ Ian Crossdale ] as an investor.

Two questions. First one is on Maari. Horizon Oil & Gas is 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? And 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?

Great, [ Ian ]. Thanks for asking questions, and thanks for asking a question which I can very easily hand over to Dan to answer. So, and just by way of preface to them. Could you just clarify to me, in -- and just and just to remind me. In Horizon's analysis where they quoting Australian dollars, U.S. dollars, or Kiwi dollars, do you happen to know?

I believe they always quote U.S. dollars, whereas Q quotes Australian dollars? I think it's U.S. dollar.

Okay. Thanks a lot, [ Ian ]. So -- and then, of course, in post-tax and pretax to think about, let's -- so how do we think about this? And what would be the way in managing that in the context of thinking about security? I mean, basically, there are a number of ways that we can deal with this through security arrangements. And some of them may even involve physical cash. And so, just to give you an example. In a PSE environment, in Southeast Asia, you actually accrue on a units of production basis to decommissioning costs over the life of the PSE. And, and that's certainly an option here. The problem we have is until the government tells us, we're not actually sure what the preference will be. And so, until we get in front of them, it's hard -- it's hard to know, precisely. But in terms of how we would think about that liability on the books, and how we would manage that. I mean, Dan, what would you add?

We talked a bit about this at the time of the announcement of the transaction. And I think when you work through the different phases, including the tax and look at the total economic cost to Jadestone for its share, FSA, net of the tax, which we would receive back and we -- 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. And that brought the net number down into something in the region of $52 million, $53 million, $54 million in that range. And that was based on estimates and analysis that was done as part of due diligence in 2019. And of course in the time that's passed since then, decommissioning work continues to accumulate and experience and costs are not earned and understanding of how to do decommissioning continues to mature worldwide, so bear that in mind. But you should think about Jadestone's net share after tax as something in that region that was we estimated, that we talked about at the time of the transaction -- announcement of the transaction. And Paul, shall I go on to the debt piece?

Yes, please. Thanks, Dan.

Yes. So, the $200 million facility that we had mandated the banks for back in Q1 of 2020, that was really gearing up for sanctioning Vietnam. And of course, as you will be -- I guess, you will 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. So although we mandated banks, we had not signed that facility, and so we had sort of put that in to fridge as it were, and moved forward to today we're now borrowing for the basis of Lemang. So it is a different facility. The RBL market has changed, certainly in that in that time as well. So there are some different features that will be incorporated into the new facility. So it will be a different facility than the one that was contemplated at the time of Q1 of 2020. Hope that answers the question.

There are no further questions at this time. Mr. Blakeley, you may proceed.

Great. Well, thank you very much operator. And everyone, it's just to say thank you for your interest in Jadestone, and thank you for participating in the call. 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 as we will shortly declare a firm ESG commitment on emissions, and the potential for incremental returns to shareholders, I hope all of that will -- we'll have you find Jadestone a compelling investment case. And so with that, 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.