Jadestone Energy plc (JSE) Earnings Call Transcript

Good afternoon, everyone. Thanks for joining us for Jadestone's Capital Markets Event, 2020. And before we get started, big thank you to BCLP as well for letting us use their facilities today here at Adelaide House, which I think works pretty well. My name is Robin Martin. I'm the Investor Relations Manager for Jadestone and just to get us started, we'll kick off with a safety briefing. If you should see a fire, please sound the alarm. You can see the icon on the screen for what that button looks like. We'll leave the building through the exit at the front or the nearest exit if we should happen to be blocked there and evacuate to the Muster Point, which is point number three, shown on that map, that's underneath London Bridge. Today's session is being recorded, February 25, 2020. The time right now is 4 minutes after 1:00 p.m. All the materials that we're presenting today are also being live webcast to an external audience. And for those of you who might be joining through conference call, they'll also be downloadable within a few minutes on our website. Just a brief note on questions. I'm going to hand the floor over to Paul very shortly, but we'll invite questions during the session, please just raise your hand. We've got the CoMarco folks, James and Dan, are here with roaming microphones. We'll try and get those through microphone for the benefit of anyone who's dialing in or on the webcast. We've also got a Q&A session at the end of this day. We're not going to take calls from external audiences, but we will accept questions via Twitter or you can e-mail us during the session, and we'll try and address your questions live. So with that, I'll hand it over to Paul Blakeley, President and CEO.

Very good. Thank you, indeed, Robin, and thanks to you all to echo Robin's comments being here this afternoon. I have to tell you, I stepped out just a moment ago, not because I thought I could make a clean getaway, but I just wanted to see where the fire alarm buttons are. They're not easy to see, and I haven't seen one in this room, but there are 2 by the doors on the way out. So one of us will catch it. So we're going to spend a couple of hours and talk about the Jadestone story, and as Robin says, let's try and make it a little bit interactive where we can. There's a lot of detail that we're going to cover. And in order to do that, we felt it would be helpful and appropriate if you were to meet some others of the senior team in Jadestone, and so we brought a few of the culprits with us. So apart from Dan and myself, who many of you know and know pretty well, we also have with us Henning Hoeyland, who heads up all our subsurface work. He's based in KL, and all of the subsurface work is done there in Kuala Lumpur. You'll be hearing quite a bit from Henning later. We have Ha with us, and Ha is in Singapore, with Dan and myself. And she heads all the commercial work, and with her Vietnam background, is also very, very helpful as we look to work through the Vietnam business and expand there, too. And then finally, Owen Hobbs, who is our Country Manager in Australia, based in Perth. Owen is, of course, running all of the producing assets right now with Montara and Stag. And the way we structured the business, the Maari asset in New Zealand, and with some synergies, will also be under Owen's remit and he'll explain how we're going to structure that and make that as efficient as we can. And then finally, not on the list, I wanted to introduce Dennis McShane, Jadestone's Nonexecutive Chairman; Dennis, we're -- it's great to have you with us as well. Thank you. And if there are questions for him, please feel free afterwards to catch up with him. Thank you. Okay. As usual, we seem to have increasing volume of advisories. I'm drawing your attention to them. I'm certainly not going to ask you to read them at this point. I just would say, in particular, however, to be aware of forward-looking statements and non-GAAP measures. But moving on to the business. So by way of agenda, we're going to spend some time talking about how we do things, not just what we're doing. I thought it was a great opportunity to try to explain a little bit where we might be different in our approach compared to some of our peers, approach to the business, approach to the opportunities that we see and take on. And then we'll move into what we're up to and perhaps a little bit about what's coming up too. But first off, I'm going to open the discussion about Jadestone today by walking you through our approach to the ESG landscape and our commitment to it. And though we are an upstream oil and gas company, providing essential energy supply a part of the world that really needs it, we've always worked to reduce our footprint from an environmental perspective, and I'll describe some of the practical steps that we're taking to achieve that. In social and human terms, we strive to deliver an exceptional health and safety culture, and we'll touch on that, too. And Owen certainly will pick up on this in his discussion. It's essential that there's no harm to people, and we always put this at the forefront of any decisions that we make. Building lasting, organizational capability and engaging local communities are examples of how social conscience and leadership in risk management plays a part, too. Asset integrity, managing regulatory compliance, these are all practical demonstrations of governance at work as well. But none of this is new. This isn't just something that because ESG plays an increasing role in visibility today, we should talk about this. This goes just simply as part of our day-to-day business. And we'll put some of this in a simple context, and how it fits into our particular model of sustainability. I hope, in some ways, you might see this as a differentiator, too, for Jadestone because really, as we look at the next slide, and for the webcast, I'm going to call them out every now and again. This is Slide 8. I'd like to map out some key steps that we're taking to further raise awareness and commitment to our agenda and what sustainability means to us in that, as I say, in a very practical sense. In fact, it's really at the very heart of our strategy. The fundamental principle that taking on underutilized facilities, suboptimal operations and under recovered reservoirs and turning this around, this provides extended energy supply, extended employment, societal and national benefits, tax and so on. And with no growing footprint, we think this is a very strong case for sustainability. Improving efficiency, maximizing resource capture, investing in what's there, what's actually there, rather than looking for what might be there, that while creating exceptional value is the very best thing we can do. And yes, in the detail, we work hard to continuously reduce emissions, reinjection, for example; and compression uptime plays a very key practical aspect in that; reduce discharges, oil and water, reinjection of produced water and minimizing waste in all practical things. They're all practical things that we measure and look to continuously improve. Last year, we set about an exercise to identify all the material matters in our business. And this year, we'll publish our first sustainability report and lay out our targets, key measurements, that will stand alongside all our other operational and business KPIs and become part of our day-to-day management focus, and indeed, therefore, reward. It will affect everyone's remuneration if targets are not met. We'll also establish this year a climate change working group to look for new ideas to monitor how we're doing. But all of this is guided by existing frameworks, such as equator principles, and of course, the banks that support us in the RBL are all signed up to this, on the task force on climate-related financial disclosures. These are all practical aspects, again, where we're guided in our reporting. But turn to HSE performance. This is at the very sharp end of our business. It includes process safety, personal safety, regulatory compliance. This is all about a license to operate. There are no shortcuts, no second best is really good enough, and we work hard on our HSE performance to be best-in-class. We've made good progress. And this means measuring the smaller things, but never room for complacency. And every morning I wake up and I wonder, "Is there an incident?" Because, in the end, we rely on everybody to play a role. It's very easy for someone to step on to our facility not in the right mindset, an inspector, to find something that we missed. So this is a never-ending challenge, and we work this day and night. But our aspiration in all of this is target 0, whether it's 0 for personal health and safety and welfare or target 0 in the context of environmental performance, regulatory performance and so on. This is something that we never relax on. I know Owen will pick up some more of this as well, again, in his discussion. And now I'm turning to Slide 10. I'd like to lay out to you Jadestone's approach to performance. The principle being how we directly align everything that happens in our business with shareholders and shareholder returns. It's not uncommon for the CEO's performance agreement to reflect key deliverables and the cascade -- the cascade of this then goes down through the organization. But what is less common perhaps is the level of granularity, the specificity, so that almost everyone can see their direct contribution to the overall business. The requirement is that every year, we can be better than the last. And the rigor that we apply to this, which -- that we assess from a success point of view and reward accordingly sets higher standards. And we measure this, honestly, and we differentiate widely. And it's simple and transparent, too. I don't believe we should make this sort of process complicated, but we don't always end up in the comfort range and just smear the reward across the whole organization. We look for individual, personal effort and delivery and recognize it. Okay. So moving on to Slide 11. Delivering exceptional performance starts with having the best people, but also team players, people that fit in the organization and a good fit within our culture. We're looking for self-starters who are motivated, results-oriented, good communicators, honest, all of which are core values to us. But I can be honest with you, some of the brightest people that I've met don't always work out for us. It's not just what they know, but it's what they do and how they do it. And it's really important that we understand and recognize that in the Jadestone culture, some people won't fit. Remuneration does play an important role alongside offering opportunities, personal development, training and so on. But in the end, successful business will generally attract the right kind of people. And I've been through and seen this a couple of times in the past. As you start a business venture, the understanding of the company and its performance and aspirations isn't clear. But later on, as success is delivered, you -- I find you can attract the very, very best people that the industry can offer. Remuneration at senior levels is split into 3 elements. And at the senior -- at the top table, if you like, it's broadly 1/3, 1/3, 1/3. Base pay, which is benchmarked at around the 50 percentile with benefits that our competitive industry forms, if you like, the underlying remuneration component. Annual performance pay, the second element. We look to pay above the 50th percentile here. But as I say, we also look to show a real differentiation in the way we reward people because we want a very clear signal that delivery is required for reward. And then finally, of course, there's a long-term incentive program. Historically, we divide this into broadly 4 or 5 buckets of activity that we measure. Some of it is summarized on the slide here. It's around, if you like, operational performance, shareholder value and growth, but recalibrate this regularly on an annual basis. And we look now to draw out some of the existing targets that are buried within those broad categories. And we'll pull this out into the ESG component that will be more clearly shown in our long-term incentives and our annual performance targets going forward. If we then turn up to the performance culture via the performance agreement, what I show here is a sample of the CEO's agreement broadly broken down into those categories that I touched on. It gives a sense of weightings, we can change every year, of course. And this is finalized and agreed with the Board and then cascaded and broken up down to all the teams whether they're functional, operational and so on. And the level of detail here, my performance agreement generally is about 3 pages, and it's a lot of detail. It's highly numerical where possible, with very hard targets, both up and down; very specific objectives and metrics where possible. And because of this detail, we're able to cascade this down with absolute clarity. So for example, the OEM on the Montara platform build up a performance arrangement, which can be threaded, intermined and provide him absolute straight line vision on what he has to do with his team, offshore Montara, to deliver to the benefit of the company and ultimately to shareholders. Okay. So now let's move on to Slide 13. I just want to move on now and recap on Asia Pacific, the region where we are active. I want to talk about the opportunity set that faces us today as we focus on the business going forward. I'd like to remind you that it's a region with over 100 billion barrels of oil equivalent in production -- reserves in production today. 85% of that is in shallow water or onshore, 50% of it is held by NOCs, and the other 50 with international oil companies, the majors down to the independents. But importantly, almost 70% of the producing reserves today is either mid-life or mature, and this is what we target, of course. This plays to our strengths and our capabilities. And more specifically, this is where we start to see movement from the majors as they look to divest from this type of opportunity. There's also 70 billion of discovered resource. And according to WoodMac, almost 40% of that is economic today. And so in principle, what I'd like you to take away from this is the notion that in Asia Pacific, there's a huge opportunity at work. And for Jadestone, particularly with our skills and capabilities, there is a massive amount that we can do. I haven't talked very much about competition in the arena, and I think always can draw comparisons with the North Sea. In Asia Pacific, when we look at an opportunity the sort of the likes of which you might see in the North Sea, where I would expect 10 or 12 companies to be in the data room here, there might only be 2 or 3, possibly 4 in Asia Pacific. So again, it speaks to the interesting opportunities that we have. So just briefly now on fundamentals with both oil and gas, and I'll start with oil. Again, just to remind you, rapid growing economies, definitely energy short. Regional production of oil meets only 20% of demand in the region. So underpinning that means really strong oil price fundamentals. I think we're starting to see this particularly emphasized by IMO 2020, and it is having, I think, a far greater impact on premiums, on differentials than we ever expected. The demand for sweet heavy crudes, particularly, and those from Northwest Australia certainly fit the bill, means that we're seeing, I think -- and Dan will talk about this. I think our last cargo, booked from Stag, will sell at a $21 premium to Brent. Montara, which is a lighter crude, I think the last order we have, was for $7.60 premium to Brent. So this is extraordinary. And in the region, I think, any environment helps our business metrics enormously, and in many ways, of course, offsets the volatility that we're seeing in the oil price today. Moving on to gas. I think fundamentally, from a demand perspective, the situation is very similar. Asia is gas short, and the shortfall is growing. I think increasingly, we see that, that shortfall is met by LNG imports. And to some extent, over the longer haul, that probably has had an impact on price setting from a regional perspective rather than country-by-country. And we're seeing gas prices for domestic gas across the whole region, sort of, converging really based on the alternative supply, broadly being LNG. And although in different countries, there are different versions of that solution, and I'll talk specifically for a moment about Vietnam, where there is no current LNG import capability, I think this plays very well for our project that we'll talk about in a few moments. And so though, of course, LNG spot prices are very low today, when you think about LNG imports into the customer base in Asia, it's really for long-term contracts in support of primary power consumption. And on the slide here on the bottom right, you can see that WoodMac data implies that longer-term LNG contracts are still broadly in the $10 to $12 range. And also, I think the slide there shows that across the whole region, although there is country-to-country, we're still seeing, I think, strengthening gas prices at a time when in most other parts of the world we're seeing the opposite occur. And so this gives us great comfort as we move forward with our first gas project in Vietnam. And whilst we're not able to talk specifically about the gas price for that project, we've always articulated publicly that we're looking at something that is -- that's in the $7.50 to $9 range. And when we do get to the point where we can announce all of the detail around the project, I don't think that's going to disappoint you. And of course, when you think about the alternatives between countries making decisions around domestic resource versus LNG, from a pricing formula perspective, there is, of course, a strong element of domestic security supply, things around jobs and infrastructure and taxes and royalty that weigh very much in the favor of domestic gas. And that's why we think it's a great opportunity for us to look to broaden the portfolio beyond the Vietnam project in Asian domestic gas. Okay. Just a very quick recap on strategy. There's nothing here that you probably don't know. I think, very, very simply, the story from Jadestone's perspective and in our history and capability is all around taking the assets, preferably producing and sometimes undeveloped discoveries and looking to invest in them, increase uptime performance, invest capital in new wells and increase reserves and recovery and so on. And this is something that we've spent a lot of time getting good at from our previous lives in Talisman Energy, both here in the North Sea as well as in Asia Pacific. But now importantly, for Jadestone, developing that capability and that track record that will help us access more opportunities in the future. And just thinking about the progress that Jadestone has made since we started just 3.5 years ago, with the legacy Mitra Energy business, we've transformed from no production to averaging 13,000 -- 13,500 last year. It was just over 4,000 in 2018. And I believe, by the time we exit this year, we'll see growth up to 18,000 to 19,000 barrels a day with infill drilling this year and the closing of the Maari deal. So year on year on year, that's starting to look like really solid growth. Well over $300 million of revenue over the same period, as we show on the chart here, versus none 3 years ago, of course. Share price, trading liquidity, value, all moving strongly in the right direction. And I know Dan will get into a little bit more detail on our position, in the context of all of these key measures. In terms of 2019, at a glance, we're on Slide 18 now. I preface by saying 2019 had its challenges. If you think about this, we started the year with Montara shutdown, an extensive shutdown to remedy all sorts of operational deficiencies. In the process of that, we removed 8 enforcement notices that had been served on the previous operator from NOPSEMA. I think we suffered some of the very worst seasonal cyclone activity that the region had ever had. And unfortunately, on a more practical level, we are unable to capture drilling slots to meet our timetable, and as a result, we didn't drill the 2 wells that we wanted to last year but managed one at Stag. And so despite that, delivering on all guidance targets was pretty important to us. Drilling the first infill well at Stag in over 6 years was pretty important to us. We concluded very extensive and complicated set of activities as part of the refurbishment of Montara, the riserless light well intervention program in a couple of the subsea wells, was something which had a number of firsts, and Owen is going to touch on that, the umbilical replacement, and of course, transferring operatorship of Montara. These are all really important milestones in the course of the year. In addition to that, getting to the point where we could submit the FDP for Nam Du/U Minh in the fourth quarter on schedule. I have to tell you what was important given the amount of activity that preceded that. Unfortunately, of course, we're still looking for that final nod from the government. The acquisition of Maari continues to build out the business, closed -- the deal was agreed and signed in fourth quarter. And of course, just to remind you that at the outset with the Montara acquisition, we said that it would pay back by fourth quarter 2019, and it did. So share price rising to 70p, bringing the market capitalization to USD 500 million was -- feels like an important measure in the benchmark, and so this is all very positive, and what was actually, behind the scenes, quite a challenging year. And of course, really pleased to provide our shareholders a loyal and solid shareholders with 170% return last year. I rounded that number, it was actually 173%. Okay. So just a quick recap on portfolio. Again, a slide that most of you are familiar with, Slide '19. We're looking to constantly broaden the business, adding Maari with 4,000 to 4,500 barrels a day before year-end was important. It does consolidate our oil production out of Australasia. And Maari, too, of course, does attract decent premiums as well as Montara and Stag. Of course, we still focus very, very much on the Vietnam gas development. We're going to talk quite a bit about that, both Ha and Henning will talk about both the project progress as well as the subsurface. And whilst I said to Dan, I wouldn't mention it, we are still negotiating to recapture an interest in Ogan Komering, Indonesia. Small though, it is important because I still think Indonesia with a significant yet-to-find to produce resource is an area where Jadestone can play. And if we can, that's great. And if we can't, well, I still think there's a lot of opportunity elsewhere. And since I mentioned, Maari, just by way of a very quick recap. And I know Owen will get into more detail. Headline purchase price of $50 million in fourth quarter last year for almost 14 million barrels of 2P reserves, but a lot of upside, which Henning will share his thoughts on. Given the effective date at the beginning of '19, I mean it's quite likely that we will receive cash at closing, clearly 100% IRR returning project. But importantly, it's a producing asset. It does come with a decommissioning liability. And one of the key things that we do is, we test the quality of an acquisition in a sort of stress test, in a sense, by assuming the -- all of the abandonment costs are accelerated to today one of the deal, and in this case, it still generates 50% IRR. So that for me is a great test and represents the quality opportunities that we can still find today. We really like this -- we really like Maari. We like New Zealand, the business environment is great. We like the Taranaki basin from a subsurface perspective. I think we'll see a lot of upside on the asset, but I also think we'll see more upside potential in New Zealand in the future. So now moving on to a quick overview on Nam Du/U Minh, the gas development in Vietnam, and again, others will talk in far more detail. So I'm not going to say too much. It's a pretty simple project. It's in our own backyard. We understand it well. It's got really high-quality channels and reservoirs. And is great within our portfolio because it does offer fixed price gas; PSC physical structure rather than tax and royalty; a longer, flatter profile with a very high take-or-pay, giving real cash flow certainty to the business. So it really complements the rest of the portfolio. And while we signaled FDP approval around year-end, we're hanging here, waiting for that final signature with a critical meeting this Wednesday actually, and we are pushing hard, and in the meantime, working hard with the project team to maintain the project schedule. So a moment on inorganic activity and opportunity. I touched on this back on, whatever it was, Slide 13, I think, but I think what I'd like to say and emphasize, increasing momentum by the majors now more clearly visible with broad statements around quantum of asset sales and so on and so on. I think this is really exciting for us. As I said, the competition is limited in the region. Perhaps, if we were to be very specific about it, credible competition within Southeast Asia, from some of the local companies who would certainly be interested. I'd say they don't have all of the experience, but certainly, they can demonstrate some capability to take on older-producing assets, less so in Australasia and particularly offshore, and mostly, in my view, that's around not seen with the regulator. And whilst they're very onerous as a regulator, the fact that we have managed 2 asset transactions already and have really demonstrated, I think, our capability, it's definitely a competitive advantage. So I think, broadly, there is a lot more that we can do, and we can do that particularly from a technical capacity. And from a financial capacity, too, strong cash flows in the business today, significant cash in hand, expanded bank capacity. There's much more given all of that flexibility. And just to talk to a couple of touchpoints on other initiatives, we'll continue to strengthen the Board. Lisa Stewart joined the Board late last year. She brings really strong technical skills, is a petroleum engineer, has global international experience, including in Australia, and she really brings a lot to strengthen the Board's experience. I'm not going to say much about dividends and senior bank debt because I know Dan will, as with hedging, except to say, just for the avoidance of doubt, we confirm our dividend for this year, a maiden dividend. We can confirm that we secured far more financial flexibility with our senior bank debt. And finally, and perhaps this is news, although we have talked about a delisting from Toronto, given the huge disparity between trading liquidity, both on the London Exchange versus Toronto, we made the decision that this year, we will drop that listing. And there are some savings -- some organizational savings and certainly management distractions in doing that. And really now just to wrap up with the last couple of slides from me. I just wanted to reemphasize, production is growing strongly. And whilst, of course, we'd like to be showing that production built into 2019, it comes during the course of this year. In the end, what you have to remember is in 2,000 -- sorry, in 2020, I beg your pardon. In 2019, whilst we had hoped to drill a couple of wells, particularly a big well on Montara and we were unable to do so. One Stag well, basically just about offset decline -- natural declines in the fields. And so it's this year with another well at Stag, with that deferred well at Montara, H6, and also with the closing of Maari, we'll see strong production growth through the year so that our exit rate will look like somewhere around 18,000 to 19,000 barrels a day. So that's a really important step change for the business or the next step for the business. And beyond that, with Nam Du and U Minh projects coming on stream late '21, and also with 2 more wells that we'll plan during the course of that year, again, we'll see further growth in production. And whilst this isn't guidance, we should be 30,000 boes a day or more at the end of '21. So production, growing strongly. And I think the business is set to deliver everything that we hoped as a result. And then finally, just turning that into free cash as an outlook. We enter 2020 with $100 million cash on hand and the RBL 200 million as I've said. But over the course of the next 2 years, we're also set to spend significant capital. We are planning those 2 wells in each of the years. And of course, the largest portion of that capital going to the Vietnam project, but all of this can be comfortably achieved, and as this chart shows, all the way down to $50 a barrel. Free cash flow is maintained throughout and then grows dramatically as we move into 2022. So this is a great outlook, in my view. The business is getting stronger and stronger. And thank you to your support for us as we do this. So that's how I'd like to leave this story. I'm now going to ask Henning to step up. We're going to see all sorts of colored maps and squiggly lines, and I know you're all going to enjoy that. And Henning over to you.

So since this is the first time I've been here, I will start by saying a few words about myself. Paul normally does it, but at this time, he didn't, so I'll have to do it. So I'll try to think of what he would normally used to say about me now, 'best guy ever and all of that.' But I'm -- my background is Reservoir Engineering. I -- before I joined Jadestone -- I've been with Jadestone since the beginning, in 2016. I gave Paul a call within a week of him joining and decided to join up. It was an exciting opportunity, a small company, very well placed in Asia Pacific for what we're trying to achieve. I had 10 years with Talisman Energy, like a lot of us had before that. And my background has really been around producing reservoirs. In North Sea, it was around producing reservoirs, midlife reservoirs, with still 10, 20 years left of life; looking at reservoir, looking at drilling more wells, looking at facilities, debottlenecking, spent a little bit of time in operations; then went out to Asia, did the same thing. So if I talk about myself, I'm probably a bit of a mid-life/producing asset specialist, that is where I excel. Looking at performance data and analyzing the trends, seeing things that other people don't see, that's really my specialty. That's where I think I add value. I always feel you should operate where you add value. I could do a lot of different things that are around the producing assets, that's where I add value to Jadestone. I'm very confident that I can find the best assets for Jadestone, better than anyone else, and that's why I'm here. We have a team -- that's what Paul would have said, I'm sure. So you can see him, he's smiling and nodding all the way through. So that's probably a confirmation of that. So we have a team set up around me in KL. The reason we set up in KL is really around access to talent, connections, reputation we have in KL already. As a small company, sometimes it takes us a bit of time to build that reputation to attract the top talent; in KL, we already have that. We're known through our engagements with Talisman. We're known through -- by everyone in KL. It was very easy then for me to reach out to the top talent and handpick those to the team at Jadestone, and that's a fantastic start. Also that oil price went down and the market was struggling, it made it even easier for us to, of course, to get people on board. So we have a top-quality team in KL across all disciplines. We have a very good mix of international talent and local talent of different age groups and experiences, which is really driving growth in my view of the company. So following on from that, I wanted to first talk a bit about how we actually work and what we do. So you saw the title was a differentiated approach to subsurface, and everyone asked, "What is that? Isn't that the same for everyone?" So we spent the last 3 years going through loads of data rooms. The last slide in the pack, you'll see some of those. It's shockingly how many data rooms we go through. We see all the other companies. We see how they work. We see how they work through their assets. We see how they work in greenfield producing assets. So we have kind of come up with a bit of a sketch for how companies work. So we have the greenfield workflow here, which has a different discipline: geology, geophysics, petrophysics, engineering. They all work within silos. They look at their own individual uncertainties, and they bring it together in a model. Great for a greenfield. It is not that dependent on each other. That model will then be built for development. What we see, going through all these interims, is that most companies actually stay in that mode. They go into producing fields, mid-life assets, and engineer will deal with the proxy data, but the rest, they stay in their mode of "I'm in my silo. I give out my data, and that's it." So where we see, where we can differentiate ourselves, is really that, for us, everything is around performance data. The advantage of having a producing asset is the production data is the pressure data. That's where we can understand the rest of our data. That's where we can see upside, others can't see. That's where we see developments that they can't see. So what we do is take all these disciplines and have them working around the production data. That anomaly in data is what we're trying to explain. That's the story of the reservoir. So we bring all of these things together, and that's what we do. So we focus more on the details. And we'll see, as we come to the next few slides, that's really where we've seen the big, big difference with other companies. That's where we can go in and find a lot more value than the seller. That's where we can be then competitive, and that's where we bought assets. Montara is fantastic example of that. Maari will be another great one for that. So I'm going to actually go through our 3 producing assets, and then I'm going through the Vietnam before I touch a bit on BD. So starting with our first acquisition back in 2016, which is Stag, I guess, it's fairly a modest production now. It was a great starter asset, fairly large oil in place, $175 million. Recovery-to-date is already quite high, with 38%. And you can see that from the well density, there's quite a few wells already drilled. You see here the ones in red are the actively producing wells, while all the green ones are abandoned, and blue here are the water injectors. You see 49H, that's the well we drilled last year. We'll talk a bit more of that on the next slide. And the reason why you see this well density and why you need such a dense pattern of wells, and why we're going to continue adding to that, is really around that this is medium-heavy oil. It means oil is slightly heavier. It's harder to flow compared to the water. So you have 2 things done you need to watch out for. First of all, you're going to have to pull in a lot of liquid because oil takes quite a while to get. So we have ESPs and all the producers, which allows us to produce a lot of liquid even at very low pressures. The second bit is that, again, because the water will flow easier, there's going to be a lot of oil in between wells, which will not move. But the water going under the wells and up to them. So it's all about tightening that well pattern. And if we look at another couple of slides here, this is all about finding those spaces in between existing wells and where we can find remaining oil. If we look at production graph history, another part of having a bit of a heavy oil is that you get early water breakthrough. Once water breakthrough in heavy oil, you then need to produce a lot of liquid to get the same oil as you would that in a lighter oil reservoir. It also gives you very low decline rates. So you see here, we're managing to maintain liquid around that. Oil rates are very stable. We're probably looking at the base declines of 8%, 9% a year at the moment, and that's dropping year-on-year as you go more and more towards the tail. And for a reservoir, this, at 2P now, we're targeting for 47%. We'll talk a bit about upside beyond that, but hopefully, we can push this one closer to 50% before we're finished. I showed you 49H in the previous slide. So as Paul also mentioned this, this is the first one in 6 years in Stag. It's managing to offset decline for the last probably 2 years. It's probably producing as much now as it did when we took over almost. This is actually showing a deep resistivity measurement, and resistivity shows you oil versus water. So what you see here is that the blue color is either water or is nonreservoir. The green-yellowish is showing kind of partial sweep, while the warmer redder color is showing all oil. So if you look where the well comes in, let's say the blank pipe section, you can trace the well all the way through the reservoir. The initial part, we did expect a bit of a partial sweep, and we got that. We didn't expect it to go in to an area of thick oil columns. Again, that was as expected. You saw the 7-8 good oil column there, very nicely, the well sitting at the first. It was a bit of a surprise after that, it was a partial sweep after that good oil zone. Then we got a positive surprise at the end, where actually there was a lot more remaining oil in the last bit. So overall, very much in line with what we had expected. It delivered initial oil rate. It delivered those reserves. And if I talk with Paul, they will always ask for delivering more. In my view, actually delivering on this is a fantastic news. I mean it tells us we understand the reservoir. It tells us that we can then fine-tune our models. It tells -- it gives us that confidence in the next few wells we're going to drill. And we're going to show you a bit on that in the previous slide. But for me, it's a great thing. It really gave us a lot of confidence going forward on the Stag reservoir. So the map you're looking at here is showing a remaining oil volume in -- with the oil the current well is producing until end of 2030. So again, the warmer color is showing more oil, while the colder color is showing most wet zones. So the reason we run this in our model and predict it all out is -- and of course, the areas that are not being fully swept by existing wells, well, we need to put in new infill wells. So you'll see around the 49H well, there is less remaining now. It's draining quite well, especially on the western side of the well. We highlighted this well already when we acquired the asset in 2016. We had 5 wells in our 2P case then. We are delivering that now. We still have 5 wells. And some of those limitations, you'll see I've highlighted 3 areas here, is actually around slot availability. 49H used the last remaining slot on the platform. And for future wells, we'll have to take an existing producing well, a slightly better location. And that might be where we need to find some solutions and adding more slots to go beyond the 5 wells we have now. We have 5 areas we've highlighted here. We have an A, B and C. A and B are very similar to 49 in terms of concepts. They -- in terms of -- they don't go in between existing wells. They cut across a lot of wells to be able to pick up more of the remaining oil with one well. And that's a very important thing, which we proved at 49 it worked, and both A and B area will do very much similar to that. The one that we think is lowest risk and we like the most for this year is actually C. It's a long horizontal well going out east, sitting against Stag 12 and Stag 15, which are 2 of our best wells, and that can be combined with an injector at a later point. So that C well there is something we're planning to drill this year, after the Montara H6 well that Paul talked about. So now we have the second well of the year. In terms of kind of further upside and all that, we are looking at ways to add more slots, which will allow us to drill more wells without actually giving up anything. So that brings us to the production profiles. So we drilled Stag 49 last year. So that's -- you see the -- for this year, we had a full year of Stag 49 production. That's a small bump up on base production rates. We'll drill another well this year. You'll see that it doesn't contribute a lot to this year. It's 2 things: we're going to have to give up a slot, which we'll have taken a bit earlier in the year for abandonment. So the increment for this year is not a large amount for that one, but it does offset decline and it manages to grow production in the following years. We then have 2 more wells planned for 2023 -- 2022 and then a final well for 2023. So with this ongoing infill drilling, we're managing to maintain a slightly growth production on Stag over the next while. And as you see there, the economic life of the field is 2035, so it still has -- and that's with the current activities of those former wells; anything beyond that, could extend life further, and of course, increase reserves. So you have a lot of time to find further targets, wait for slots to become available and then refill more in the years beyond. Moving on to Montara, our second acquisition in Australia acquired in 2018. While Stag is a low decline, a bit heavier oil, at probably moderate rates, Montara is very different, light oil, is really world-class reservoirs, very productive, high rates. But also because they are so productive, the decline rates are probably more than double of Stag. In terms of infill drilling and development, that's great because you can get oil early on and you get value for it. There are strong regional aquifers, so you don't really need anything for pressure maintenance. Stag is very low pressure; here, you have excellent pressure. If you look at the map here, you have 4 fields. You have a Skua field, up north there. You have the Swift field and then Swallow sitting just under it, here. Then you have the Montara field. So these are 4 producing fields we have. Montara has a large gas cap. These don't really have anything significant gas. These 3 are subsea tiebacks. They well advise the platform sitting here, which then goes back to the FPSO. In terms of expected recovery factors, we talked about getting close to 50% on Stag. These are fantastic reservoirs. Montara is a bit of a thin oil rim, big gas cap. We're probably getting to 55%, which is very good there. While these other ones, I think, are anywhere between 60% to 80% recovery factor. 80% is a very, very high number when we talk about oil recovery. We have analogue from a close by field, [ Jaberi ] field, which actually ceased production quite a few years ago. They reached 79% production before they gave up production. It's just a combination of the fantastic rock quality we see here. If we look at production graph here, I just want you to focus on kind of since we started influence around late of '18, we had to extend a shutdown and came out in 2019. We can see the step change in terms of production from what we've seen previously. No new wells drilled, a lot of low-hanging fruits, as always, in the first year or 2, same as we'll do in Maari. We're focused on the low-hanging fruit initially. This was around reactivating some idle wells. It was around optimizing production, lowering the total sales pressure and really increasing production that way, while second stage of that is all about drilling more wells and developing more resource. I then want to take you through 2 of the reservoirs in a little bit more detail. The first one is the Montara field. We talked about that, it is a thin oil rim, large gas cap and strong aquifer. We have 4 horizontal wells there: H2, 3, 4, 5, which are the horizontal producers, and you have the gas injector in G2. You can see the thin oil rims, so the wells are placed to be kind of a bit of distance to both water and the gas. Depending where it sits, they will have a different distance to each contact. Part of the key thing for management of this reservoir and optimizing reserves is really maintaining that GOC. If that goes up, the oil will follow and go above the wells and we won't get it back. And that's why compression availability, injection into G2 is very important. When we did the acquisition, we overidentified infill well. That was H6 well. We've updated our modeling, redone all of that, it still confirmed the well as the best, best location. We have a westerly daunting fault, and we have H2, H5 well on the other side so that oil is basically trapped. It's not going to go anywhere unless you put the well down. You'll see this is the H6 planned well coming through, sitting horizontally and oil lag came in line with H5. We're probably expecting around 3,000 barrels initial oil rates, plateaued may be over a year around there. So we'll deliver a lot more than a Stag well and deliver a flatter production for longer. It's all around when the gas finally breaks through and the oil rate will come up a bit. Incremental reserves is still around 1.88 million based on our modeling. So that's the first well we're going to drill this year. So that's -- we're looking to spread that by middle of the year, is in our plans. The second reservoir, I would like to talk about is the Skua reservoir. So very different to Montara. No thin oil rim. It's fairly thick oil column up against a fault with very strong aquifer. All of the wells sit crestally, giving excellent sweep and very high recovery factors. It's quite interesting in several ways. This is a field which was initially developed and came online in early '90s. In late '90s, mid-'97, it ceased production and -- due to low oil price, but also due to very high OpEx. It had an FPSO just for this field. Still a lot of remaining potential, but just way too high OpEx so they abandoned it. When they then came back for the Montara development, they saw the remaining potential here. So from the initial wells, which are the 8, 9 and 4 were all abandoned, they then came back and drilled 2 horizontal wells: Skua-11 and Skua-10. They've performed really well. This is one of the reservoirs during the acquisition, where we saw a lot more potential than [ P3P ] and not only in base production but also in further drilling. We've identified upfront the Skua-12 well, which we put into 2P. And then we talked about there could be some further potential along the crestal. But at that point, we weren't really sure. It's going to be a bit of an upside potentially coming in. When we're looking at year-end reserves at the end of last year, we are maintaining Stag 12 (sic) [ Skua-12] and probably increasing reserve slightly. We are adding Skua-13 into 2P. So again, it's an upside well. We've updated our modeling. We've gained confidence based on the performance. And again, we want to add that into 2P. So it shows, again, we're delivering on our promises during the acquisition. Part of that upside is already coming into base and we're delivering. And if we look at the Montara acquisition, reservoir performance has an excellent, as good or better than expected across the board in all of the reservoirs. So that's been really, really positive. And it shows that when we do acquisitions, it's not just about making high promises, it's about having that balance through and making sure we can deliver that and also achieve more. The -- both wells are probably in kind of delivering around 4,000 barrels initial oil rate. Again, it's very different to Stag. These are very productive reservoirs, probably not a very long plateau period, like the H6 and reserves around 1.5 million to 2 million each. The Skua-14 well has not gone away. It's something we're still evaluating. We need to do a little bit more work there. There's still some remaining uncertainties and risks that we need to get comfortable with before we can push that forward. And there is the subsurface part, but there's also the flow assurance part, we need to look at the subsea and bottlenecks and so on before we commit to a third one, but Skua has really done well since -- over the last year or 2. We then come to the profiles from Montara. You can see on the base production, there is a little bit of a steeper decline than Stag, probably closer to 20%. Since there's a lot of optimization rate at the end of last year and coming into this year, from last year to this year, the decline is not as deep, but going forward, it is around 20% and a bit. H6 comes in, in the second half of this year and then has a full year of production next year. So we see the big slice of H6 there contributing a lot, especially in 2021, but also, what Paul talked about, the exit rates. In '21, we're planning to drill 2 wells in Skua, Skua-12 and 13, and delivering that yellow wedge, which, again, will grow production. So you can see here, based on these 3 infill wells that we've identified and we're pushing, we're actually managing to not only offset declines, which are steeper but actually able to grow production on Montara. We are working on a lot of options beyond that. Skua-14, I already mentioned, through our other infill targets that we are progressing, but there are also other tie-backs and so on that we are considering. So we'll come to that in the next slide. Again, economic life, we've extended 1 year compared to the year before. It's around Skua-13, adding a little bit more oil, which managed to extend 1 more year. So it goes out to 2032 now, which again, gives us plenty of time to identify more upside and develop that and extend life further. So when we did the acquisition, it was very much focused always around 2P. That's the value we put to the market. And we see 2P growing already. We've added -- extended life. We've added more wells to it. Actually, base production has even increased in 2P slightly. We did mention briefly about upside beyond that, and we always said we are very excited about it. We never put any value on it. So if you now look at a few of these things, we'll touch a bit more on it, still not in a lot of detail, just a bit on our plans and progress over the last year. One thing is that we always knew that the seismic data had resolved. It was not of great quality. There's been new acquisitions across south and north of our blocks. But across our blocks, there's been no new seismic. And it was around P3P, not wanting to commit. We didn't really see the value, didn't really see the future of the asset. And we've talked about the new seismic that we're acquiring. So just last week, we finished that acquisition over both blocks. That's now been acquired. It's now being shipped for processing and probably Q4 this year, we'll receive the final process data. Service will give a big uplift of seismic data quality across these 2 blocks, but also a little bit north and south of us. And there are several things that will become easier than the existing producing fields. We'll be able to better define, hopefully, see some more infill wells, probably derisk a couple. There are a couple of other things. There are quite a few prospects around, especially around Skua and Swift, Swallow. There are quite a few oil prospects. And with old seismic, it was always a bit too high risk, especially for us to go after this. With the new seismic, we expect these to come down in risk and hopefully be able to high grade 1 or 2 of those to push forward. When we talk about exploration, we are never into the kind of big exploration far away from our existing facilities. This is all about being able to drill a well and tie-back and produce it within -- at least within 2 years and be able to get cash flow. And that's the kind of thing that we can look at. So kind of '22, '23, it might be in kind of a range where we're potentially looking at putting in a possible exploration well if we can combine it with another development well. Other things we'll be looking at. If you look at gas, there was a brief mention of the gas during the acquisition. Again, no value put on it. We have talked about the gas cap already on Montara. You see 3 other discoveries of gas. Combining those 4, it could probably end up to 0.5 Tcf of resource. There's a bit of a range here, and we're still working that, and we never really spent a lot of time on that during the acquisition. Since then, Shell have actually progressed the trucks development. We should then looking in to tie back to Prelude to backfill the need for gas there. So we see this as a key gas to at some point go into Prelude. With the facilities there, it will be a very cheap and simple tie-back. Timing, of course, of some of this is very uncertain. It's not really all up to us, it's up to Shell when they need the gas, where there's a lot available. But that's definitely something which will give us value in the longer term. The final bit is taking it back to the Skua analogue of abandoned fields and how you can get them back to life. Once you get rid of the FPSO, they had by themselves. When you start looking at tying them back and reducing the OpEx, it unlocks the new opportunities. There are several fields up there and here which have been abandoned. Just as an example, there's a Puffin Field here, which is -- will also be covered by the new seismic. It's a field that have had its own FPSO, struggled with oil rates and it was abandoned because of high costs, exactly as Skua. There are several of those. And for us, that's very interesting. There's no way that anyone will go ahead and develop Puffin by itself. It just will never work. It has to be a tie-back to Montara. It's the only oil-producing asset within a couple of hundred kilometers. So anything oil here of a marginal nature like that will come back to us. And that's the other strand like we talked a bit about at acquisition, but now we're starting to press it. We're starting to look at overall area strategy, not only at our blocks but also what's outside. It kind of goes a little bit into the PD side, but it is something which will help now with us being a new seismic. That was Montara. Montara is, I would say, since the acquisition, we've definitely had reaffirmed all of our expectations around the subsurface. A lot of the upside is coming through. And especially around production optimization, actually probably been better than we expected, but Owen will comment more on that. The last acquisition of a producing asset is in New Zealand. It's announced November last year. It's Maari and Manaia oil fields sitting in the Taranaki basin, like Paul talked about, just south of the giant Maui gas fields. And if you look at this, it's actually turbidite fans depositional. So I'm not sure how much you guys know about geology so I'll probably know -- a part what I know almost, but that's fine. So this is kind of the area which is supposed to represent a Maari field. These turbidite fans, they will deposit some sand, you'll have a bit of a poorer stuff and then you have another fan. So between the fans, you have baffling oil barriers, so the communication is not great. So this kind of complexity is really bad when you have an initial development because you're not quite sure how the wells are going to communicate. So you'll end up with a suboptimal development. And I'll come to that and show you how it happened. But when I look at it from my point of view, I look at midlife assets producing fields. I think that's fantastic. That complexity tells me they would never have got it right the first time because it's just too complex, they wouldn't know. It's tough to gauge, but a seismic can't tell you enough about it to fully understand it. So you had to have -- take a punt on it, and it went a bit wrong. For us coming here as a second operator on this is fantastic news. That means there's a lot of remaining potential. I will take you through some of the fields, I'll show you that, but that kind of complexity really excites me. Whenever we see there's different types of complexity in each type of fields, Montara had some, Stag had some, this one is actually very, very exciting, as exciting as Montara, probably more actually. We'll take you through a bit on the history, and then I'll show a bit about what we think is there and what kind of upsides. Discovered fairly quite a while ago, 1970, 1983, it was an initial development of the 3 main reservoirs. You have the Maari field here with a wellhead platform and the FPSO. The Moki -- Maari Moki reservoir is the main reservoir. They had 5 producers and 3 deviated injectors initially. This is the reservoir where they got it a bit wrong. It's very complex. So injection got -- they got it a bit wrong. So expect the very high initial rates, size of the facilities for it, but the results weren't as -- quite as expected. That never achieved the high rates expected and it came down much quicker. They also put a single horizontal well in the Sequence 0 reservoir, which is shallower and they put a bit of a long reach well into the Manaia Mangahewa structure. Later on, when they realized that Moki wasn't as developed quite as it should do, they actually gave up the 3 deviated injectors used to sidetrack to producers and converted 2 horizontal producers and started to injection. So what you've seen here in the last probably 2 years almost now is very much of a flattening oil decline. And actually, I would say that over the last 1.5 years, oil rates has been on the way up. And it's not because of the Mangahewa and the Maari Mangahewa, they're both declining. Sequence 0 is stable. The Maari Moki's oil rate is actually going up. Several wells are going up now. So when I look at timing for buying this asset, they've been through it. They've struggled with it. Here, they've just started firming up how to actually handle and manage these fields better, how to get more oil out of it. We can see that works. This is a fantastic point for us to come in. They've actually proven some of these concepts. We understand how to take that forward and how to unlock further upside. So again, very flat declines. It's some ways, a little bit similar to Stag in that all ESPs, stable production, but not heavy oil, it's light oil, but there are similarities there. I'm going to take you through a couple of the key reservoirs and the opportunities we see. We have the Maari Moki reservoir, which we talked about. It's the main reservoir, around 150 million barrels in place. We talked about the initial development. There are complexities that they couldn't overcome. They thought the vertical deviated injectors would work, it didn't. They gave up those. And what they've done now, they actually converted MR1, which was a producer to injection initially. That gave good support to MR2 and MR7, especially. Then late 2018, they converted MR5 well on the eastern side here, which has given very good support to 10 and also 2, 4 and 8. And we've actually started seeing -- these actually starting coming up in oil rates. We look at kind of a cross-section there. You can see some of that complexity. These are -- you would think they're sitting too close, but because of the complexity on turbidite fans, actually, you'll need to tighten the pattern, you need more producers, you need more injectors. If we look at recovery factors here, in the 2P case, we are quite -- we only have a few activities. We have one more conversion of a producer to injector, and we have 4 coiled tubing laterals included. Coiled tubing laterals is very different than conventional drilling in terms of we don't need a rig to bring in. Bringing in the rig is a fairly big thing in terms of schedule and costs. Coiled tubing laterals, we can drill from our current workover rig we have on Maari. It means we can control the schedule ourselves, and the costs would be a lot less. That takes us around to 27% recovery factor. We've done our own modeling here. We've analyzed the performance data. Take you back to the workflow slide early on, where we'll definitely see we're working very much in a greenfield more still. When you incorporate the performance data, you can start understanding this reservoir much better. And that will really help us on increasing the recovery factor. I would target this one to get as high as close to 35%. If we can get that high, that means that we can actually double the remaining reserves from this field. Maari and Manaia oil fields. We're going to show a couple of other examples. You have the Maari Sequence 0, single horizontal producer. Last 2 years, this one has produced with no water and almost flat oil production throughout. It really highlights the high potential for this field. It's poor quality, so we'll need more wells. We've added only one coiled tubing lateral in 2P case, again, no rigging needed, which gets recovery factors only up to 5%. It's tighter rock. So it's never going to get to very high like other reservoirs, but we should be able to get this 1 above 10%. So again, that upside activities will be able to double the recovery or remaining reserves of this reservoir. Manaia Mangahewa, we have one long rich well. There's vertical baffling here. So what we see is that, that well only kind of drains from the first 2 lobes, mostly. There is -- in 2P case, we have a NFA case, no further activities, getting us to 70% recovery factor. One more well to target these 2 lower lobes, we'll be able to increase recovery factor to above 25%. And again, it'll probably double the remaining reserves for this reservoir too, and again, it's above 2P. The final one is the Manaia Moki, it's a shallower reservoir above the Manaia Mangahewa. Potentially a very large oil in place. There is still a lot of uncertainty there, something we need to work both around the volume, but also on the potential flow rates. So there's a lot of further work before we can consider any activity here. That brings us to the profiles. You'll see there's only a small component for Maari for this year based on our assumption of closing the deal this year and only accounting for oil from that point onwards. In '21, we'll see a full year of oil production from Maari, plus a bit from activities. Most of that is around converting a producer to injector. '22, we'll see a bit more contribution from that. And in '23 is where we start expecting to see more of that upside coming through, which we talked about. Only with those few activities we have in 2P, it takes reserves life out to 2031. With the upside we talked about, we can probably take it out to technical recovery factor -- technical recovery and cutoff of 2038. So lots more running room here, lots of excitement on Maari and Manaia. Moving on to Vietnam. Paul talked a bit about this already. I want to highlight first, the PM3 asset sitting here. A large, probably 75% of the team sits -- of our team have worked on PM3. So this is really our bread-and-butter, especially on geopsychology. That really helps us a lot in understanding these in terms of analogues, in terms of the seismic quality. We have 3 discoveries in our blocks. We have the Nam Du, U Minh and Tho Chu. These 2 are single channel low Tier 2 simple reservoirs, which were targeted for first part of development. This one is with higher CO2. So we'll need a lot more facility. So that's been deferred for a later stage of development. The -- what differentiates this area to a lot of other areas is the world-class seismic. So it is the Nam Du channel. So what you can see, often, you can see from seismic, you see the sand, but also you can see here is actually the gas. So you see the shutoff of these warmer colors towards here, that's the gas water contact. You can see also in the cross section, that's the gas water contact. That means that even though we have only one well at the crest, we understand the extent of the gas, you understand the contact, so it limits the uncertainty and manages the risk. If you follow that channel south of the -- here and across that fault, we don't have a well there because seismic tells us that is same response. We also know this is gas. It's on the other side of the fault so we can't call it discovered yet. It's technically exploration, but we are very sure this is gas. So sure, we're putting our first development well into that and then putting a second well in the main channel. So really, everything about Vietnam is about this fantastic quality seismic. As we move on to U Minh, I'm going to show you a bit of the upside more on U Minh. So if you see here the discovery well for U Minh sits here. The U Minh 1x you have a planned development well here. This is the U Minh channel with another development well planned here. So what we've shown here now is that there are several other channels overlaying to the site of the main U Minh here. These are on seismic that world-class seismic we have identified as prospects. If you look at Australia, the prospects will probably come at quite a big risk. Here, it's very different because of the quality of the seismic. So I've selected 3 to highlight here. We have one, which is exactly the same as Nam Du as an extension of the channel here. The response is the same. Again, we believe that is gas. You then have the meandering channel here, [ F40 ], which we have a lot of gas there. Well, we expected a big gas. This one is a little bit -- tiny bit more risk because we don't actually have a well in the channel yet. Once you have a well in the channel, we can tune the seismic to that. You can see here that, that development well will actually go through here. Once you through here and if this finds gas, that will derisk these 2 lobes also. So it's very cheap to do this exploration and exactly the same as we did in PM3. You drill and you find new stuff as you develop the other reservoirs. The third one is the H60 to the west. There's no development well going through that one. So we're going to have to discuss in '21 or '22 if we do an exploration well there. Very cheap and shallow wells there, so it wouldn't cost a lot, but is very important to understand that. If we talk about volumes, I'm not going to give specific volumes, but with a bit of success in the upside here, shallow upside only, we could potentially double the gas for the development. That's a shallow gas, which can be added onto existing development. If we then come to the overall production profiles, layered up the base profiles first, you see the Stag, Montara and Maari Base. Fairly stable base and then a bit of slow decline afterwards. We then see the activities, which are the infill activities and everything in 2P, which allows us to grow production above 20,000 a day oil alone. You then see the next slide, which is Nam Du coming online. Comes online late '21. And in '22, you see the first full year. '22, that's when we're expecting them to reach the 30,000, that Paul talked about, and we see significant growth beyond that. We've talked a lot about it on Montara, on Maari, on U Minh, that's the great stuff there. There's a lot of organic growth beyond that, and of course, M&A. Just to give you a bit of a flavor of the reserves story, what that I will end up with. So the year-end reserves for last year is still undergoing the final loaded, almost finished and signed off. We'll have a small reserve add end of last year, again Skua-13 well, an extension of Maari life. This year, we think we'll be quite strong on reserves adds. We'll have the Nam Du, U Minh development going towards sanction now. Does that mean we'll add everything in one go or do we just go for staged adds like Nam Du Phase I, something we need to decide on? Maari will be booked at year-end once the deal closes, which will give us a significant growth in reserves this year. Going forward, beyond that, we'll have the U Minh, the Nam Du South channel. We talked about we can drill a development well there in '21. As soon as that's drilled, it will go into reserves. Then we have Tho Chu and others. And others there, you have the Maari stuff, you have SC56. You have the Montara upside. There's a lot of exciting upside here. So even the organic, there's a lot of M&A talk about Jadestone. We definitely are growing through that. Even the organic growth now is starting to look exciting. The assets we have now, they all come with considerable amount of upside. So we're talking about potentially up to 200 million BOE here in terms of reserves and upside -- resource upside. So my final slide is that we've talked a lot about the assets we have, the assets we have acquired. I wanted to just give you a bit of a flavor for the work we've done in actually finding those. I talked earlier on about where we differentiate ourselves, where we feel we do different than others, and it's definitely around the producing midlife workflow. This is actually showing all of the opportunities that -- we did a detailed subsurface evaluation on -- over 3 years from late 2016 to late 2019. And what we did is we separated them all out by producing and nonproducing. You see the squares here are the producing and the round ones are nonproducing kind of projects, not yet on production. We separated them out by country. And then we did a comparison of seller’s volume versus Jadestone volume. Green, we are at higher. Red, seller at higher. So what we learned from this is a couple of things, of course, is if you look at all of those which we have considerably higher volumes than others, it's all about producing assets. That's where we've seen we can differentiate ourselves. Around nonproducing, people can be optimistic and conservative, it's really around that dynamic data we managed to achieve and see that upside. We can also see that majority of the cases, actually, we're finding a lot less than the seller and we dump the asset and we don't go forward. So we look at a lot of things before we actually find them. And of course, the third one, 2 of the top-performing assets on our evaluations are Montara and Maari and also the ones we bought. So we're buying the right stuff. We are going through a lot of work, detailed due diligence to identify those. This is where we differentiate ourselves from a lot of other smaller companies coming up. We are very picky, actually. We go through a lot of assets before we find the ones that really work for us. It has to have that upside on reserves that Paul talked about, has to have further development activity and has to have cost savings, and that's where we really can add the values. And you can see on Stag and Montara, we're already delivering. We're finding more upside on Montara and we expect the same with Maari. That's my last slide. So unless there are any questions? Yes.

I just have one question on that graph, if you put that on the side and sort of CapEx assumption because you could have...

So what we looked for here is to remove all of kind of other -- there's no more activities. We also removed cost savings and OpEx, which can extend life, we took that down. So we took everything against the same economic life, same assumptions. This is purely about us seeing an upside in the volumes. Just as like-for-like as we can. So for example, on Montara and Maari, we extend the life by a lot compared to the current operator. So if we include that, this would have been much higher. Now we have more drilling on Montara, and it's going to have a lot more Maari that would have been even higher. This is very much like a like-for-like.

How much time would you spend on organic versus I don't know about this inorganic selection process…

So subsurface alone, yes. So when I -- it's -- it'd probably be another graph there. Back here, I would say, 80%, 90% on inorganic. As we come closer to here, it was probably 50-50. As we grow the team now, we're able to handle both better. There's probably, I would say, 60 on an organic list, 40 on inorganic. And as we -- what we're doing as we pick up assets, we're growing the team and be able to handle both. But my time, I do spend a lot on PPD still. We still look at a lot of things. You can still see it comes in periods. After we close Montara and there's a bit of closer period -- kind of a period of less activity then a lot of activity as we build up and pick Maari and now we see another big growth in activity, I think, over the next half year at least.

Hi, everybody. My name is Owen Hobbs. I've been -- I'm going to keep this relatively brief, primarily because Henning got carried away with the turbidite sands, which I always thought was an episode of Baywatch. But anyway, the other reason I keep this brief is because Paul has covered a lot of my ground and that's no criticism, I mean he's paying my salary for a start. But Paul also, there are very few CEOs that are as close to the detail of the business as Paul is. And I think that's symbolic of who we are. So I can be fairly brief, just to sort of touch on some of the points raised by others. I want to really focus on -- well, first of all, just quick background. You have enough balance sheet to make sure we've got time for that. So 35 years in the industry, I've worked on onshore/offshore assets, big assets, small assets, mature assets, growth assets. I was in semiretirement before Paul called me out and working with my own business, which is relevant to the Maari asset when we can talk about that. And you may notice my vows. I won't be talking about the rugby today. But I -- so I understand operating capability. More recently, I was operating Origin Energy's conventional oil and gas operation across Australia and New Zealand. So I'm going to concentrate on our capability, what differentiates us and how we deliver on our promises. We now have 3 assets. Here there's 4 pictures, but we've doubled up Montara so we haven't snuck out and bought one without telling market. Stag, which is formational for us, it was a formation asset. Montara, which, as Henning said, was transformational. And of course, we are soon to pick up Maari as well, which we're all really excited about. We operate in a tough regime. We operate under NOPSEMA as Paul has said, and I'll touch on that in a minute. But we have experience, we're an experienced operator now. We have real capability. And we demonstrated capability. So we have to deliver on what we side we were going to do. You've seen the results of that, but also from a regulatory point of view as well, there's nowhere to hide. So a very, very rigid and rigorous regime in Australia. Everything that we do is public, so we actually have to walk the talk. We have huge capability in the business. We now have experience operating midlife assets in Australia, and that's not easy. So none of this is easy. I want to make that clear. This is hard work, but we have the technical team and the experience to really deliver and add value to our assets, while also maintaining excellent safety and environmental performance. This is scalable, so as we add more assets to our portfolio, we'll talk about Maari a bit later on. This experience and this capability is very scalable. Busy slide. So this is -- the intent of this slide is to talk about our process. So we talk about what differentiates us and how do we add value. And this is a process diagram and every company has one around how you think about adding value at every phase, at every stage of an asset's life cycle. So what makes us different? Well, I've never worked for a company where we're so relentless and so focused on delivering value. We really focus on this. It's day in, day out. Every morning call we have, we talk about value of the asset, how we improve production, how we reduce costs. It's a constant relentless focus, exhausting, but relentless. So every company has one of these, but we deliver on it. Picking out a few things, Henning's already talked about our due diligence process, so from a subsurface point of view, but also an operational point of view, and we sent experts over to kick the tires of these assets. And in fact, if we could disconnect them, we'd take them for a run around the harbor. We really go to the nth degree on due diligence. We often find things that the current operators aren't aware of. And in that process, we also find the value. So we have people in this process, so any other organization would be leading large departments; engineering, technical, there our people that exist in the business. We send them over and they do the hard work for us. Gulf Shores, so there's a lot of effort put into making sure we understand the assets. Picking out another box here under operate, debottlenecking. Again, a lot of work goes into this. It's not rocket science, but it's -- again, we put the effort and the focus in. An example there, for instance, is Montara, one of our bottlenecks is our produced water. So as Henning said, we produce a lot of water with our oil. Water rates are increasing. A few months ago, we were looking potentially at having to invest quite a bit of capital to increase our produced water facilities. Over the last few weeks, we're doing a lot of work on that. We've optimized them. We'll be making some engineering changes, and we believe that we can significantly increase the volume of producer oil that we can manage without having to spend a great deal of money at all. So it's that constant focus and -- on optimization and delivering value from these assets. Great photo. Baby whale shark swimming around one of the areas around Montara. Paul mentioned our HSE performance. I mean, of course, that's a given for any operating company. But when you're operating midlife assets under a NOPSEMA regime, you really are under scrutiny. Our performance is excellent, 0 lost time incidents since we've been operating all our assets. You'll see the TRIR value, which is a pretty industry standard measure, 9.9% on Montara. That's higher than we'd like to see, but that's one cut finger. So that's been our major incident in the last -- well, last sort of 12 or 18 months since we've been operating Stag and Montara since August. So an excellent safety record and an excellent environmental record. We talked about NOPSEMA. So why do we make an issue of NOPSEMA? Well, I mean, they're just doing their job. They are the government's watchdog. And they are, as I said, very, very rigorous effect, arguably, probably one of the toughest regimes in the industry anywhere. They run a thorough assurance process. So they're on our assets, not just us, of course, every offshore Australian asset is under the same regime. So they're probably doing assurance or doing an assurance activity on our assets on average once a month. The results of that are public. So again, nowhere to hide. And if you're not doing the right thing, you will have an enforcement notice issued and it can be anywhere from sort of basically a speeding ticket type level to a prohibition notice where they'll actually shut you down. And they've done that recently on another operator in the north of Australia. So you have to be operating well. And we've never had an enforcement notice from NOPSEMA. They're not uncommon. And so because of that, we're very proud. But also that regime, that thoroughness, that focus is actually, we think, is a competitive advantage for us. The fact that we can operate at these assets, midlife assets, which are a focus for NOPSEMA, maintain excellent HSE and environmental performance and also deliver significant value is a real differentiator for us. And there are no doubt there are independents and small organizations that will be deterred from moving into the Australian market for that very reason. So the fact that we do it well is a competitive advantage for us. I won't go into much detail here. You've all heard about Stag. A couple of points worth noting here is the FSO Dampier Spirit, that's a leased vessel. And we'll talk about that in a minute when we talk about opportunities. So that's a leased vessel. That's -- basically you pump your oil into that and then every 2 or 3 months when we're full, we bring in an offtake tanker. The other thing worth noting on here, as Henning's already mentioned, is the small workover unit on the platform. So that gives us a real advantage in doing our workovers. We budget about 5 workovers a year on our submersible pumps. We produce a bit of sand, so they don't last forever. The fact that we can do it ourselves with in-house capability without having to bring a rig in is a huge advantage for us. And ultimately, one day, when we look at abandoning these facilities, it's also an opportunity, reduce abandonment costs significantly. And we're spending a lot of time looking at abandonment costs, and Dan will talk about that in more detail. Again, we've covered this a lot in Henning's slide and Paul, but this indicates the value that we've added. So these are historical levers, if you like, historical performance up to current year. The gray bar represents the previous operator, the installer per barrel OpEx costs. And you can see that's come down consistently in a trend. The only anomaly there is in the first half of '19, where we had a major cyclone's impact on the facility, as Paul has already mentioned. This was a tough year last year. We're all going through cyclones, again, as we speak. It's just one of the challenges of operating in north part of Australia, our summer and cyclone season. So that's just an impact you have to manage. But even on that, actually, even Mother Nature, while we can't necessarily prevent cyclones, although we do make a lot of phone calls, we -- basically, we're looking at how we respond to those and working with our Bureau of Metrology. They have some amazing data these days, worldwide data that we can use to actually change the way react to our cyclones and keep people on the platforms longer and have less downtime. So again, we just don't stop at anything, we look at everything. So that's just an indication or the value that we have brought to Stag and obviously, a key milestone there was drilling 49H, as Henning mentioned, and we'll be looking at another well. We are doing another well this year. Lots of work going on to continue work around reducing OpEx, so our manning, so we're actually, again, as we speak, looking at reducing a layer of management off the platform. And so again, on just logistics, sharing helicopters, sharing boats, all those -- all that sort of -- those opportunities, again, we're constantly looking at. This is a look forward, this is this year's budget. And again, the idea of this slide is to talk about opportunities. You see the big green chunk there is the Dampier Spirit, the FSO costs. So that's a leased vessel. We are looking at a step change there in terms of costs. So we're working with the owner of that vessel, Teekay in Norway, who has just been brought out and that becomes somebody else, Altera Infrastructure, I think it is. So we're talking with Teekay about how we come up with a different model, and it may be that we end up buying the vessel, maybe that we build our own vessel or we do a deal with Teekay around financing. So there's lots of opportunities there. OpEx at Stag is critical. It's a fairly modest producer. So every dollar we save has a direct impact on reserves. So we're working really hard to try and, again, look at a step change in our big bucket of OpEx here. And there's lots of other things we've done, workovers, reducing time, downtime. We cut out -- we changed from -- hopefully there's nobody here from Schlumberger, changing out from Schlumberger to Baker pumps, $300,000 saving per pump, 5 workovers a year. It's a fair bit of saving. And they're just as efficient and last just as long. So not rocket science. Other companies can do this, but they choose not to, and we get after it. So lots of opportunities. Is that out of context? No, Montara, so onto Montara. So this asset was transformational to us. This -- it put us in the ranks of a major operator in Australia. FPSO, as you know, fully owned. So our FPSO, we've already talked about the reservoirs and Henning's covered a lot of the wells in production. That's just a schematic showing the Skua wells up close and moving down to Swallow, Swift and then the wellhead platform in the distance. Just a nice picture, so that's what's in there. Good production this year. You can see the average production of 10,483 barrels. We're up as high as over 13x on Montara. We've only had this asset since August. So -- and I think that's worth remembering in terms of being the operator. So short history, added a huge amount of value in that time and a lot more to go. It's a long journey. We've got a lot of work to do, sort of improve our liability, increase uptime. That's already increased significantly since we have taken operatorship, but there's more to do. But a great facility and, as Henning said, huge upside with high potentials. Big chunk of our costs here are logistics, we'll talk about that in a minute. As Paul said, it's a light sweet crude. So we get a premium at the moment around about $7 on this. Many of you've seen this slide before. So this is basically showing the value that we've already added to the facility now. Overall, it's about $25 million in OpEx that we've reduced since we took operatorship of Montara. You can see that there are various buckets there, production optimization, just briefly, a lot of work gone into that with Henning and his team. I think one of the things, again, what differentiates us is the way Henning's team had a KL work with our operations team to constantly challenge production and optimize. So this is all around basically getting the subsea wells producing, even without gas lift that the previous operator just split languish. Uptime from 72% to around 80%, slightly over 80%, and there's more to do there. And I'm confident that now we have some operating history that we can reduce that even further and increase uptime. And I don't want to go into the rest, I think Henning's already covered a lot of the rest. So a huge amount of value already unlocked and more to come. Similar slide to Stag. You can see the reduction in -- I should say, the reduction in OpEx per barrel and the increase in production since we started influencing Montara. And the reason I say influencing is that, as you probably know, we actually owned the facility before we operated it. PTTEP continued to operate. However, we parachuted in 2 of our very senior people, operations and technical. And that was a conundrum to PTTEP after the facility was shut in to basically help bring it back to operation, remove enforcement notices that NOPSEMA had applied, improve reliability and do a lot of maintenance and integrity work on the facility. So from day 1, even before we took over former operatorship in August, you can see the influence of just having those key people in PTTEP made to that operation. And again, it's just by working harder, focus, lots of technical capability. And those people, of course, are in our business today, day-to-day operations and engineering. So we're continuing to look for value as we go on. You can see some of the buckets here. I won't go into detail. Sharing logistics is very important for us. Logistics are a big part of our costs, so our supply chain, again, even as we speak, are working with Shell at the moment to see whether we can do some sharing around helicopters and boats. Maintenance and integrity practices. We've gone to a campaign maintenance. So they had a lot of people sitting on the facility who weren't adding a lot of value. We've gone to a campaign maintenance stall, which has reduced costs enormously. I think from memory, our maintenance reduction alone is around $2 million or $3 million a year just on that basis and there's more to do. Shutdown frequency, pushing out from 2 years to 4 years, just through, again, smart engineering. Now we do this, we don't cut corners. As I said before, we've got an excellent safety record. So we're not cutting back on integrity or maintenance. We spend that money when we have to. We meet NOPSEMA's requirements, and they are stringent, as I keep saying as well as our own internal requirements. So yes, this is just a very smart operating practice. Again, a similar slide to Stag. Looking ahead on Montara at 2020 OpEx and the big bucket that stands out in gray is logistics. This is a remote facility. It's a long way, 650 kilometers west of Darwin, moving something from Perth to Darwin, it's a bit like moving something from Mexico up to, I think, it's mid-Manitoba. It's -- distances in Australia are enormous. But a big part of this is the fact that we run our own airbase. So we have an airbase on a remote island, Truscott Air Force, an ex-Second World War bomber base. It's about $30 million a year for us to maintain that. We're the only ones that use it. It's a lot of infrastructure. It's a necessity, but we're constantly, again, working currently on ways that we can challenge those costs, whether we find another base, whether we find somebody else to share in it. Henning mentioned the hub opportunities. They are critical for us, if we can unlock hub opportunities not only from a production point of view and using the existing facility, but also to reduce our logistics costs. Or do we move the base, do we put it somewhere else where there's an existing air force base or oil base. So lots of opportunities and lots of work to do. But again, that's just ongoing. Capability and innovation. We're not scared to innovate for small a organization. So mid-last year, we ran riserless -- I can't never get this right, a riserless light well intervention. Not something you want to say after a few beers. So it's been done before. However, this was the first time it's been done in Australia in conjunction with using an electrical and digital wireline package. Enabled us to unlock value in Skua 11 and Swift 2 and access further reserves in Swallow without bringing a rig in. Difference in costs there of $25 million, if we bought a full-scale rig in. So again, it's not with our innovation and capability because it's a sophisticated program and very successful. I must admit this looks like -- a little bit like the leftovers on our Italian restaurant table cloth. But if you focus on the green light -- I have to say that [ Chris Dan ] wanted me to make that joke. If you look at the green line, concentrate on that, this is our electrical and control system or circuit and our subsea completion at Montara. Now nothing particularly new or unusual about this. Most subsea completions have this. When we -- before we even acquired the asset, PTTEP, the previous operator, identified this as their highest business risk integrity to the system. It was about to fail. It would have brought down the whole subsea operation. So due to delays and transition, we ended up undertaking this work ourselves. Big program of work, we replaced that section and now we've basically returned the integrity of that field to beyond its current predictive field life. And an earlier graph, we showed a bit of a blip, where -- or might on the, where production was impacted and costs were up slightly, and that was while we were undertaking these major chunks of work. This and the rise of sidewall intervention was all within about 6 weeks of each other. I just want to stress again just our capability of delivering big programs of work successfully. Maari. So we're all very excited about Maari. Again, Henning's talked a lot about Maari. So I'm not going to go into any of the subsea value opportunities. Great thing about Maari for us is that apart from the upside, which we've already talked about is the synergies with our business. So Maari is essentially a sister ship of Montara coincidentally. The workover -- well, their platform, even though theirs is manned, Stag is unmanned, but it has ESPs. So it's a bit of a love child between Montara and Stag in a way. So we're very familiar with it, lots of synergies. We will have a lean team in New Zealand. And so we have about -- we're going through a transition as we speak. We probably have about 14 people operating this facility, not offshore, but onshore in the New Plymouth office in New Zealand. So I want to compare that with the current manning levels, which MODEC are the O&M operator. They have an onshore support base of around about 22 people. And I know from experience, which I'll touch on in a second, that OMV mirrored that, so they're the operator, obviously, of around 22 people. So they had roughly around 40-odd people and still do to operate this asset, and we'll be doing it with 14 with functional support from our KL and our Perth offices. So one of the reasons I'm looking after this asset is not only do I have New Zealand and Maari specific experience but obviously, a lot of the team supporting us will come from Perth. And so in terms of my experience at Maari, I was running a consultancy business for a couple of years before I joined Jadestone. And it's purely coincidentally about a year before Paul made the phone call, OMV brought me in to help restructure the Maari business. And in fact, the guy who is leading the transition for us at the moment was working for me. So he has also a very good experience and knowledge of the Maari facility, as do most of the team in New Zealand. So very experienced team who will be able to move -- hopefully, stay on with us and continue to operate once we take over operatorship. As I said earlier, when we looked at their very busy process slide, we do a lot of work upfront to identify opportunities. And in this case, we have identified over 20% OpEx reductions already that we know we can reduce, as Henning put it, low-hanging fruit. We can get those pretty much straight up. And then there's extra value after that, I'm sure we'll unlock once we understand the asset. Finally, continuing on another busy slide. Transitions are important and are a part of our business. As we keep acquiring new assets, then transitions are a key part of that. Delivering those successfully is critical. Emphasizing that we have that experience, we did it with Stag, we did it with Montara, we're in the process with Maari. We've got a very experienced team working in New Zealand who have experience and history. The current transition plan is going very well. We're in the process of going through our formal regulatory approvals. I have had nothing but positive feedback from our key stakeholders in New Zealand, including the government. Obviously, Paul may talk about the government view of oil and gas. I'm sure you've all read about it and the labor government's position on exploration. That is purely greenfield's exploration at the moment, which is not our cup of tea anyway. And they're being behind the scenes very supportive of us moving into the New Zealand industry and supportive of ongoing development in the existing fields. And as we said before, we see huge opportunity with Maari, lots of synergies with our existing business and really looking forward to getting our hands on it. That's it for me. So -- a bit rushed, I know, I'm sorry. Happy to take questions.

I'm Werner Riding, Peel Hunt. I'm just wondering whether you've identified or experienced any disruptions in your supply chain either with regards to physical operation, oilfield services, or from a personnel perspective as a result of the coronavirus?

Yes. Great question. Not so much in Australia. We certainly have looked at that. The biggest exposure for us were our tankers. So bringing tankers in, had they been to China, do we have Chinese crews and the Australian maritime, something rather ancillary anyway, are also keeping a close watch on that. So far, no disruption to supply chain or our people, but it's -- our Singapore office, particularly, with the focus here, and Paul might want to talk about it, have a close focus on it, and I think it's being really well managed from a Jadestone point of view.

Thanks, Werner. I think, overall, the business has not been affected, and that certainly includes all staff. And of course, thinking about Vietnam, Singapore, where there have been a number of cases. And we've responded the way many companies have in home working, and the key is all about no large groups, all sports events canceled, major -- that kind of practical stuff. The real test for us, I think, as a business, given what we're about, and we are in the middle of an assessment right now, is supply chain with respect to the Nam Du and U Minh project. And -- whilst practically speaking, just simply because it's Vietnam, most of the activity is in Vietnam by Vietnam for Vietnam. And the FPSO conversion will likely be in Singapore. We haven't finished this process of inquiry. The project team are going through this. Is there anything that's sourced back through the supply chain from China? So far, no impact. But that's the one area that we just -- we haven't quite completed.

David Round, BMO. Can you -- you just mentioned headcounts in New Zealand, can you just clarify MODEC's role going forward? And if they are going to be less involved, whether that is reflected in the OpEx savings that you've already put up?

I can. We're yet to have formal negotiations with MODEC. We have identified some opportunities in our operating model. We -- so again, we haven't started negotiations with MODEC, so, obviously, can't say too much. But definitely, that's an area that we've highlighted as an opportunity for us fairly quickly. There is -- I guess, what I can say is, it's unlikely that we're going to be making changes to the crew on the facility initially because, yes, operating advantages in keeping that crew on. Although, ultimately, as we did with the Montara, we'd like to look at a different operating model there. But certainly, in terms of onshore support, we've identified fairly quickly that we would like to look at that model differently.

Sorry, I'm supposed to be repeating these questions back as well, aren't I?

It's okay, one more...

It's all right.

It's Alex Topouzoglou from Stifel. So just as you did with Montara, have you been able to second any Jadestone staff on to the Maari vessel? Does that apply that magic touch in terms of cost savings and increased operating uptime and so on? Or should we wait till completion?

Well, it's both. So yes, we -- as I put up on my earlier slide, we sent 2 of our key operation technical people, a guy called Mark Craig, who is a bit of a genius when it comes to looking at squeezing every last drop out of production and OpEx; and Andrew Gibbons, who is our engineering manager, works for me. They went over, they went offshore. They spent a week in New Zealand. Because of the relationship that we have with the Maari folk and myself personally and with OMV, Maari have been fantastic in this process, very supportive. We were able to get a lot of information. So upfront, we already have identified a lot of the opportunity. Henning has talked about that with the reservoir, at least 20% probably low-hanging fruit around total OpEx. But I know there is a lot more to be had. They have a manned wellhead platform. We know we can unman that. We know we can remove 10-odd people off that facility with a bit of engineering. It might not happen in the first 12 months, but yes, huge opportunity.

But specifically, Alex, we won't be seconding people into the OMV organization.

No, no.

But to Owen's point, the corporation is strong enough that we can get around it.

And look, we will be, again, New Plymouth is a very small community. We've targeted people already around our permanent structure that have a lot of experience with the Maari. And interesting enough, and it's an interesting question, OMV have basically endorsed most of the opportunities we found, they've endorsed them. And you're sitting here and it's a key question. I got asked earlier. So why don't they do it? Why haven't they cut costs? And to be fair, they did start their process, which is why they brought me in, in a different life. But the reality is, as Paul have said, these bigger operators, they lose focus, they lose interest, they don't have the will to drive these costs out of the business. And we do, it's what we do and what we do well. So that's sort of gone here. Actually now we can see these savings. We agree with you, but we'd rather you do it and then I'll spend the effort.

How quickly do you think you can get those savings post taking up the assets?

There'll be a scale. Of course, some will become very quickly. Others, a bit like the conversation we just had, it might take a little bit longer, but most of the savings are going to be short term, pretty quick. Thank you.

Ha, sorry. I should have introduced you.

Thanks, Owen. Good afternoon. I got a very brief introduction, recognizing that I cannot compete with Henning, he set very high standard on that. So I'm Group Commercial Manager. 17 years of experience in business development, commercial and M&A, 10 of which is in Vietnam and very fortunate to be involved in some of the country major oil and natural gas development. So getting right into the business before going into details of U Minh/Nam Du project, offshore Southwest Vietnam. I would like to spend a couple of minutes to walk you through the market where we'll play into. Vietnam, if I can use a word to describe, it is a high-growth, energy-hungry country. We have a couple of macro data here to show. A very consistent GDP growth grade in the range of 6% to 7% over the last decade, outperforming neighboring countries. However, GDP per capita is still among the lowest in the regions, indicating significant room to further growth. To support economic growth, power generation has increased by about 8% on average over the last decade and is projected to continue at 7% going forward. However, energy supply still cannot keep up with demand, and that results in increasing public concerns over energy supply, to name a few, is a very tight reserve margin, especially in the South, which is the economic center of the country. So supply cannot meet peak demand and leading to brownouts from time to time. Capacity addition, the power generation is much slower than expectation. And in a worst-case scenario that it -- may lead to blackouts to the country. And finally, the increasing coal-fired power in the generation mix to over 50% last year, that put a lot of concerns from the public about pollutions. Moving on to the economic center of the country, the South, comprising 2 separate gas market, Southeast and Southwest. I'm not sure if I can use the -- here. So Southeast and Southwest, a majority of gas infrastructure and gas supply is in the Southeast, and there is absolutely no connecting facilities between the 2. In the Southwest, the area where we play into, demand is underpinned by the Ca Mau power complex. This complex is constructed in 2007 by Petrovietnam, own 100% and operates through its subsidiaries. The complex include 2 power station, 1,500 megawatt, supplying about 7% of the total country electricity and a fertilizer plant, 800,000 tonne per annum, meeting about 40% of domestic demand. These 2 clients requires a stable gas supply of about 200 million cubic feet per day. In addition, late '17, the Petrovietnam set up a gas processing plant to further process gas into higher-value products such as Condensate and LPG. During the first year of operation in '18, the GPP has provided about 8% of LPG to the country. And more importantly, it reduced reliance on import, given that Vietnam needs to import about 50% of LPG. At normal capacity, this plant will require about 30 million cubic feet per day. However, with the recent declining in gas supply, it's now running at a very low capacity to give priority to power and fertilizer. So that's the current demand and the end-users of U Minh/Nam Du gas. In addition, we see further upsides to demand from industrial users in the region. They are currently running on diesel, and we believe that if there is more gas available, then they will be happily switched to gas. Moving on to the supply side. To date, the only source of supply to Ca Mau is from PM3. Henning has talked a lot about this legacy Talisman asset when -- we have been working on that for years and years. On the commercial side, it sits in the commercial arrangement area between Vietnam and Malaysia on a 50-50 basis. The field started production in 2001, initially solely supplied to Peninsular Malaysia before Vietnam completed the construction of the Ca Mau pipeline and the power complex in 2007. So since then, Vietnam has taken almost full pipeline capacity of up to 215 million cubic feet per day. That includes the 50% equity gas and the underlift. Sharp underlift has been balanced by late last year. And now gas entitlement reverts back to 50-50 basis. So as such, PM3 supply shown in gray here in this graph on the left-hand side, start to show a steep decline from late '19 and even more going forward, and this is based on Wood Mackenzie forecast. Backfill supply to Ca Mau can only come from U Minh/Nam Du or Malaysian commercial pipe import gas, and we understand that Petrovietnam is negotiating with both to fill up this pipeline unit. Being domestic gas, U Minh/Nam Du offers substantial benefits to Vietnam that includes, as Paul mentioned, government tax, local contractor work, job creation, security of supply. Moreover, to me, I think it provides the offshore infrastructure in Vietnamese water. There is none available in the area right now. That can help to unlock stranded discovery in the area and furthermore to stimulate exploration in the future. In terms of competitor, to date, apart from Malaysian import gas, we see no other alternative supply to the Southwest in short to medium term. There has been discussion from time to time about LPG -- sorry, LNG to the region, and there was the first LNG project in the Southwest was granted investment certificate so that it can start preparation work. Now we don't view it as our competitor, not only because it is dedicated to new build power, but also given typical approval and construction time in Vietnam, we don't see first LNG coming into the region any time before 2026. So this brings me to the last piece of the market pictures, gas price. There is no natural gas markets in Vietnam, and price is set project by project based on market conditions and commercial negotiation. However, similar to other countries in the region, we observe common theme here that includes it's -- the supply gap, putting pressure on price and import fuels that -- to introduce headroom for domestic gas to increase. So in such context, our commercial negotiation for U Minh/Nam Du is centered around 2 things: firstly, pacing our project activities so that we can optimize on our commercial leverage. For example, an existing gap in supply will provide us with better advantage than a full pipeline situation. And secondly, we need to fully understand alternative supply price. And for our case, our insight analysis such as a range of $9 to $10.50 for Malaysian import gas. So following that strategy, we have started negotiation with gas buyer, Petrovietnam, in 3Q '18. We signed GSPA agreement for gas sales in April '19 and that have all key commercial terms, including contract duration, a daily contract quantity, a swing factor, a price formula and a take-or-pay level. That bring us to progress with a full-term gas sales agreement throughout '19. And gas price is included in the fuel development plan submitted to the government late last year, and it will be an item for the Prime Minister approval as part of the overall project approval. So we expect -- we'll continue expecting that the FDP approval will come shortly. And after that, we can execute the gas sales agreement in coming months after finalization of couple minor outstanding issues to the contract with Petrovietnam. Apart from the GSPA last year on the overall project, we hit all technical and commercial milestones, and we are progressing the FDP approval. There are 3 gates involved in the FDP approval process. We have passed 2 of that. We have endorsement from Petrovietnam and Ministry of Industry and Trade for our FDP, and it is now on the table of the Prime Minister waiting for his final stamp. To provide a bit more color as to where we are today, the bottom 2 boxes provide an outline of key commercial agreements and major contracts that are either in place now or in near-final form ready for project execution. On the commercial side, I have mentioned the GSPA. The tie-in service agreement is with PV GAS, which is a subsidiary of Petrovietnam, who owns and operates Ca Mau pipeline on 100% basis. It is in final form and ready for signing after FDP approval. On the contract side, 2 critical contracts are available. The EPC -- the facility EPC contract is with PTSC, another subsidiary of Petrovietnam, having more than 20 years of track record, delivering on almost all key offshore project in Vietnam. The FPSO lease and related O&M contract is with a consortium of PTSC -- sorry, Vietsovpetro, the first and largest in E&P operator in Vietnam in consortium with HBA Offshore comprising ex-management team of Bumi Armada. So both are in final form and ready for signing any minute the FDP is approved. The last pit is on drilling rig and long leads. We are under competitive tendering, and bids evaluation almost complete on that. Based upon the initial review, I think we have identified a suitable checkup rig for U Minh/Nam Du development drilling, and it is at a very competitive market price. This slide provide an illustration of the business shape. So in a very brief term, we expect stable operating cash flow from first production in late 2021. After the very short ramp-up period and Nam Du as part of phase 1 development is capable of delivering to -- up to 80 million cubic feet per day, which is the plateau contract daily quantity. Our stable operating cash flow is underpinned by a fixed gas price under the contract. And a majority of our operating costs will be on Southwest in the form of the FPSO lease rate and O&M rate. In terms of unlevered free cash, after initial 2 years investment in '20 and '21, we expect the project will be fully funded for phase 2 and become cash positive from 2022 onward. Moving on to how we are going to deliver the project. I believe U Minh/Nam Du stays in the safe hands of a very capable, highly experienced team in the country, with a lot of local knowledge and relationship. This is the organization structure that we'll put together for developing on U Minh/Nam Du. The project leadership team comprising both ex-pat and national staff. In combination, they have over 150 years industry experience and 76 years Vietnam experience. They have worked on delivering successfully 9 projects previously in Vietnam. Apart from that, the team is supported by a corporate team with deep regional knowledge and understanding such as what Henning has mentioned about his team working experience in PM3, and they also have trusted and long-standing relationship with key contacts at Petrovietnam and the government bodies. Working in Vietnam, that play an important role in getting to know who you should talk to, to progress the project along. So we believe that we have ticked all the box for that, being in the right position to progress the project. In addition to the team, we have planned to assign our staff into contractor size to supervise project activities. We already have now EPC contract at the PTSC yard in Vung Tau. And we have the delivery team with the FPSO contractors and the shipyard will be in Singapore. So we -- also, we have a supervisor on board of the drilling rig, the vessel -- installation vessel and the FPSO in due course. Those people will play an important role in cost and quality control in delivering on the project. In addition to an excellent project team, we have also worked on implementing a contracting strategy and a cost -- very intense cost control to make sure that CapEx cost overrun is minimized. So as can be seen from this chart, a large part of our EPC and FPSO contract is fixed. To provide a bit more details, the EPC contracts is all -- the manufacturing and engineering is all based on fixed -- predefined per price unit. The variable component is mainly related to the purchase of materials and equipment. And to mitigate this, we have full control of the tendering process to make sure quality of specification and competitive price. The contractor only provides services to us. In terms of the FPSO contract, again, as the typical FPSO, it's a fixed flat lease rate. The contractor will take all responsibility for the conversion of the vessel, and we only start playing -- paying lease when the vessel is capable of -- is accepted to be capable of producing and handling hydrocarbon. And as I mentioned in the previous slide, the -- that our team, our secondee in the contractor sides will play an important role in making sure that cost is fully under control. In addition to that, we'll have our budget built in an appropriate level of contingency, and this is based on a cost-risk review performed by our independent third-party, [indiscernible] International. So with all that in place, I think we have a strong belief that the CapEx cost overrun is under intense control to mitigate potential impact. This is my last slide to talk about the Project schedule to first gas. 2020 all workstream is underway. We have the EPC contract, FPSO in place and in light of the FDP progress as we are now certain engineering and procurement activities under these 2 have commenced based on the level of confidence that we have with the FDP progress so far, we are tendering the transportation and installation contract. And by the way, I forgot to mention earlier that this one is also based on fixed price lump sum basis, and we receive quite a good bits for this. The drilling, I have mentioned, both of these will be, what, in 2Q this year. So that form everything for -- to progress the key activity into 2021. In 2021, major work involve offshore activities and drilling, which will be planned in 2Q and 3Q during the typical monsoon weather window of March to late November. We also agreed with PV gas on weather window for the hot tap operations into Ca Mau pipeline, which is during the annual maintenance shutdown will be in August 2021. So with those 2 activity, we expect to deliver first gas from Nam Du in late 2021. There will be no other requirement up to the top level for us to start construction or to start production. There will be some permits required at the provincial level, but it's all like a day-to-day basis. There is no major obstacle that we have seen can impact first gas cap plant. So that's the end of my slide. My -- I'm happy to take question now before the later stage if there's any in the Q&A.

Based on the gas cap project, have you been able to give an IRR or projected IRR?

Yes. So we have -- our negotiation is always based on a view of what is the required -- return for us. I think we should be in a position to disclose gas price when the FDP is approved. And as Paul mentioned, I don't think that the market would disobey with that based on all the information today. So based on that, assuming that everything go ahead, we expect a return of mid-40s with the successful Nam Du Southern channel, and it will increase further if Nam Du Southern channel well come into pass, and we expect to drill that as part of the development drilling in 2021.

That's unlevered.

That's unlevered.