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Edited Transcript of LUPE.ST earnings conference call or presentation 31-Jan-20 10:00am GMT

Q4 2019 Lundin Petroleum AB Earnings Call and Capital Markets Day

Stockholm Feb 10, 2020 (Thomson StreetEvents) -- Edited Transcript of Lundin Petroleum AB earnings conference call or presentation Friday, January 31, 2020 at 10:00:00am GMT

TEXT version of Transcript

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Corporate Participants

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* Alexandre Schneiter

Lundin Petroleum AB (publ) - President, CEO & Director

* Edward Westropp

Lundin Petroleum AB (publ) - VP of IR

* Kristin Færøvik

Lundin Norway AS - MD and Director

* Nicholas John Robert Walker

Lundin Petroleum AB (publ) - COO

* Per Øyvind Seljebotn;Reservoir Development Director

* Teitur Poulsen

Lundin Petroleum AB (publ) - CFO

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Conference Call Participants

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* Al Stanton

RBC Capital Markets, Research Division - MD & Oil & Gas Equity Analyst

* Alwyn Thomas

Exane BNP Paribas, Research Division - Analyst of Oil and Gas

* Anders Torgrim Holte

Kepler Cheuvreux, Research Division - Equity Research Analyst

* David Matthew Round

BMO Capital Markets Equity Research - Oil and Gas Research Analyst

* Duncan Gregor Milligan

Goldman Sachs Group Inc., Research Division - Equity Analyst

* James Thompson

JP Morgan Chase & Co, Research Division - Analyst

* James William Hosie

Barclays Bank PLC, Research Division - Research Analyst

* Mark Wilson

Jefferies LLC, Research Division - Oil and Gas Equity Analyst

* Michael J Alsford

Citigroup Inc, Research Division - Director

* Robin Alfred Haworth

Stifel, Nicolaus & Company, Incorporated, Research Division - Director of European Oil & Gas and Research Analyst

* Sasikanth Chilukuru

Morgan Stanley, Research Division - Research Associate

* Yoann Charenton

Societe Generale Cross Asset Research - Equity Analyst

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Presentation

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [1]

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Good morning, everyone. Thank you very much for coming to the Lundin Petroleum 2020 Capital Markets Day.

We're going to follow the normal form, if you were here last year. I'll quickly go through the agenda, if I can. Here we go.

Alex will take you through the sort of strategic update and a bit of background and an outlook. Nick will then take you through the producing assets and the portfolio. Kristin will then come up and talk a bit about Sverdrup, and then Per Øyvind will take you through the organic growth strategy and the exploration strategy for this year. Then there will be a coffee break of 15 minutes, and then we'll have Nick back again to talk about the decarbonization strategy. And then Teitur will come up and talk about the financials for last year with the Q4 and looking forward to this year. Then Alex will come up and do some concluding remarks.

We're going to do Q&A right at the end. So if any of you have got questions saved until the end, we'll do Q&A from the room first, and then we'll do Q&A from the web and the lines. And then there'll be a lunch just outside afterwards.

So thank you very much indeed for coming. Oh, one other thing, at the back of your presentation pack, you'll see a QR code, which, if you click on it, will download the new Lundin Petroleum IR app, which will give you all the latest information and worth downloading.

Everybody, so thanks very much for coming. I'll hand over to Alex, and kick things off.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [2]

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Right. Thank you. Right. Well, good morning, and great to see you all this morning, and I hope we're going to have an interesting morning. I will give a really an overview and the lion's share of the presentation really will come from my colleagues who will really have a deep dive into the content of my first few slides. But hopefully, I hope by today, when you come out of this meeting, you'll have a pretty good idea of where we're heading in '20 and certainly also in the long term.

So let me start with this slide. I thought it was interesting before I dive into the company, just to give a brief perspective on the energy sector. I mean, we could spend the days and days on that subject. But I thought just to put few, few numbers that sometimes we kind of forget.

But I start with the central part of the industry color in red, just basic thing. But today, the world is consuming or using the energy usage. It's 285 million barrels of oil equivalent per day, probably most of you are well aware of that. And today, fossil fuel is about 80% of that equation and pretty much spread between hydrocarbon, coal and gas. And not surprisingly, oil has right now, their lion's share with 33%. But surprisingly, still today, 26% comes from coal. And then you have the remaining 20% on other sources and renewables, and 10% is really very much linked to wind and solar.

So still oil today play a very or fossil fuel play a very important role on the energy usage. And then if you look at on the left-hand side, obviously, that growth comes very much driven by the population growth we've seen. I mean, when I was born, we were just above 3 billion people, and I'm not that old. And today, we are more than double. So we've seen -- it's not exactly the same, it is -- more in the 60s for me, but we've seen a tremendous growth in population over the years. And of course, population came with tremendous growth which has been then translating into a strong oil demand, and we've seen since the '70s, and people tend to forget the 50% increase in oil demand, which is leading today to the numbers I quoted you in terms of total energy usage.

And of course, we've seen also tremendous growth, world economic growth since the '70s, fourfold on an uninflated basis. If you actually inflate the numbers in terms of currency and others, you'll see that, that growth has been up to 30x. So what has happened since the '70 has been absolutely phenomenal.

But of course, what we do find today and what we knew and starting from the, I guess, the first industrial revolution in the 1800 is that the carbon footprint of this energy usage is significant. And just to put things in perspective, since the '70s, we've seen a 120% increase in CO2 emissions. So really today, the challenge, the energy industry is facing is how to meet world demand while decarbonizing the energy system. But that's a very complex equation, and it will really require across the whole industries efforts and new approaches to really find a solution. It's not just about oil and gas.

And of course, on top of that, there is a fundamental growing demand for future energy sources and nutrition. And really, this can only be met by the resource sector. If you look at -- in terms of the -- and those are estimates. And of course, you have to take them with a pinch of salt. But by 2050, in general, the estimate assumes that the energy usage in the world will increase by 50%. And that is very much driven by an increase in population of about 25%. And it's no surprise that, that energy usage and population growth mostly comes from non-OECD countries, about 70%. So in one way, we have to decarbonize a society, at the same time, we have to deal with growth.

And the other challenge we have is that we talk a lot about renewable. And we fully support renewable. And as you know, we're also investing in renewable ourselves. But the challenge for renewable is scale. In actual fact, under any scenarios you take today, the most optimistic one or technologically one advanced the energy transition will take decades. And actually, despite the recent rapid advances, the reality, the brutal reality today is that the technology does not yet exist to cost-effectively replace many of today's essential use of hydrocarbons.

And so my main message, I guess, in this slide is you have to be factual at times, and we certainly strongly believe that oil and gas is there to stay, and it will play a very important role in this transition. But as we realize that, I think we, as oil and gas, we need to take responsibilities and put our priorities in the right place and also provide these energy sources in a more sustainable and best possible way. So my main first message to you is that responsible oil and gas will definitely play an essential role in these energy transitions and sustainability risk definitely needs to be addressed.

So moving on in terms of strategy and priorities. So what are these strategy and priorities. I think on the financial side, definitely, capital discipline is on the forefront of our mind. And that's something we -- every day, we looked at very careful because that leads to, obviously, strong free cash flow generations. And the knock-on is obviously, what we call a sustainable annual dividend growth. And I think you've seen certainly from the past and have certainly in '19 and going forward, that's very much a strong focus and priority for us in Lundin Petroleum.

In terms of operation, of course, organic growth production or organic production growth has been a key factor. It has been a successful factor for us over the years. And is still something we're focusing, and that's within our existing assets, but also, obviously, outside our assets. And I think this fast-moving world when project, low breakeven price project is important. It's the best way to be resilient to any changes. So we'll continue to look at the most profitable project to be resilient over the years. And of course, it goes without saying, innovative, efficient and technology driven, I think Lundin has shown many, many times that we are driven by these 3 factors. And we continue to be and continue to try to be ahead of the curve. That's true from organic growth, through existing operations and others. And that's certainly forefront of our mind.

And finally, the carbonization strategy, you've seen our press release on Monday. It is part of our business. And I think over the years, is going to be part of your license to operate. And is going to play an important part and will have actually impact on values. So my second message to you is capital discipline, organic production growth are 2 definitely key strategies for Lundin.

Just a brief glance on the past where -- and really, we're going to focus on the future. But it's interesting to look. If you look at since 2015 to end of last year, we had a tremendous growth. And I think this was really driven by 2 things: one was the successful organic growth strategy; and the second one, I would say, I would call it the Edvard Grieg era. I mean, Edvard Grieg has been a phenomenal assets for us. It has provided us, obviously, the growth that we've seen from '15 and has provided us the cash flow to fund Johan Sverdrup and it continues. You will see from the presentation from [Nick] that the Edvard Grieg and the area around Edvard Grieg, still there's still a lot of potential, so tremendous growth. And if you -- and this is my last slide in terms of the past. But if you look at what that translate into value. If you look at just in the last 9 years, we redistributed to shareholders about $3.8 billion between shares and cash. And that, if you look at since the beginning of the Lundin Petroleum story, that accounted for a compounded growth rate of 35%. So that strategy and the growth has had a tremendous impact on Lundin and the shareholders. But my message -- and I guess, my fourth message is that what we've seen in the past and what's ahead of us is as exciting. We call it the Johan Sverdrup era and beyond the Johan Sverdrup era. And I hope you will see that through also the presentation from my colleagues.

So let's move on now to more the present almost -- I mean, the highlights you've just seen the fourth quarter results. I would say, overall, you've seen the numbers. I'm not going to go through all the details here, but certainly, from my point of view, the fourth quarter has been a very good quarter, I would say, quite exceptional. We continue to see outperformance on Edvard Grieg. And you also -- you see that also on the operating cost. We're now, for the whole year, we have announced about $4 a barrel, and you'll see that these figures will continue to improve. And generating, obviously, we're close to the upward guidance of the production. So high production, low operating cost, it obviously translates to stronger financials. And of course, the key, a full quarter, although it's old news now has been Johan Sverdrup. And it is a key event because Johan Sverdrup is truly transformational for Lundin Petroleum. And you will see that and you've heard already that so far so good. (inaudible) has been -- the performance on Johan Sverdrup has been very good, and we're very pleased with what we see. And I would say, in general, ahead of expectations. And then increase in reserves and then organic growth, I think I'll leave the thunder to my colleagues. So I would say my fifth message to you is -- fourth message, sorry, it's -- '19 is another year of great performance and 18 quarters in a row at above guidance. So very pleased with that.

So what to expect in 2020. For me, 2020 is definitely a transformational year. You will hear about the production. We're currently guiding for 145,000 to 165,000 with the midpoint of 155,000. Now remember, last year, this time, we were guiding you that we will exceed 150,000 by 2020. But since then, we actually sold 2.6% of Johan Sverdrup. So if you compare apples with apples, you would have had to expect a certain reduction on guidance in the long term, but that hasn't happened. In actual fact, we've increased our guidance. And so -- and that's very much driven by the performance at Edvard Grieg and you will see later on also on Johan Sverdrup. So really pleased with that.

Again, on operating costs, very pleased with where we are. $3.40, I would say it's really leading the patch and very, very much ahead of the games when it comes to operating cost. And we're actually guiding now operating cost between $3.20 to $4.20. So not only we are excellent on operating costs, but this is something we're going to sustain over the time.

Obviously, the key highlights in 2020 will be also reaching Phase 1 plateau, and Kristin will say more about it later on. And you'll see also in terms of organic growth, I do know that '19 was not the perfect year for us. Although, I have to say, when it comes to new field discovery, we've been very successful, but it's fair to say we haven't found this other Edvard Grieg, but I would say that organic growth has got a lot of focus on us. And we've done a lot of work and you will see through the presentation today. We have, first of all, 4 projects ongoing as we speak. And this year, we will have 10 exploration wells across the Norwegian Continental Shelf from the bands all the way into the south. And those wells will target unrisked resources of over 650 million. I've been in this game for a long time. I'm actually myself an explorationist really by background. And I'm absolutely convinced that Norwegian Continental Shelf has got all the ingredients to be successful. And I think it's a long-term game. And it's also related to our ability to be ahead of the curve also, in particular, in technology. A good example, [CRI], for me, was a vision of subsurface people, but it was also our ability to improve the subsurface resolution and that led to the discovery and the story we know.

Decarbonization strategy, I think I will leave the thunder to Nick, he has a few slides. As I said, it's not -- all I would like to say, this is not something we've decided today or 3 days ago, when we put the press release. The decarbonization strategy really started back in 2010. At that time, we started to make the first investment to prepare Edvard Grieg for electrification. In 2015, then we decided to go ahead with electrification in Johan Sverdrup, and just a few months ago, the board approved the full electrification of Edvard Grieg.

And so what we want to do with the decarbonization strategy was really to explicitly explain what we're doing and what was our overall strategy. But the pillar of that strategy is the electrification of both platforms, Edvard Grieg and Johan Sverdrup. The most important thing is to reduce reemissions, and then you have to deal with what remains. So I'll say I'm really pleased with where we are and where we're going, and you will hear more later on. The name change is, to me, it's simply a logical step towards not just what we do and how we do things and in relation to the decarbonization strategy. On a personal note, I much prefer Lundin Energy than Lundin Petroleum, actually, we should have called Lundin Energy from day 1, but that's a different story.

On the dividend side, you've seen we've increased, as we always said, we want the dividend to be sustainable, and we want to increase it over time, and that's exactly what we've done. And you've seen a 22% increase in dividend from what used to be $1.48 per share, moving now to $1.80, and which is giving you an excess of 5% yield. So we are at par with the majors in terms of yields, but we're actually also providing tremendous growth and opportunities. So definitely, I guess, my fifth message is definitely 2020 will be a transformational year, and very pleased with where we're going.

Capital allocation, I would say, only one thing is, if you look at this slide, this is over an average. It's obviously -- we obviously have flexibility, but it is -- we had a lot -- I had a lot of question on capital allocation, so I thought useful to give you an outline. I think from this slide, what you see is that about 1/3 of our capital is dedicated for growth. So spread between CapEx and exploration and appraisal. And the remaining 3 [quarters] really is dedicated to redistribution of cash to shareholders and debt repayment. So of course, that can change. It's not set in stone, but I think it gives you a good overall idea. And I think Teitur has later on, a more detailed slide on the subject. Yes.

And then production, I think it's -- that story fundamentally hasn't changed, but it gets better and better. We've seen from 2015 to 2019, a quadrupling production, very much driven by Edvard Grieg. You've seen now the guidance of 145,000, 165,000, which is higher than what we guided last year at the same time at the Capital Markets Day, driven really by Johan Sverdrup and continued performance of Edvard Grieg. Sorry, on the -- and then the long-term 160,000 to 170,000, which is really driven by Phase 2 of Johan Sverdrup. Our target of 200,000 is very much based on our existing assets, and the assets are currently under development. So a tremendous growth ahead of us, and that doesn't take into account any future discoveries. So we're going to invest time and money on organic growth. And certainly, my expectation is that we will do better than that, particularly with the new discoveries. So my sixth message to you is that production to more than double over the years with the existing assets and development.

Organic growth strategy. We've been -- as I said, we've been very active last year, perhaps, we haven't delivered what we were hoping to deliver. But we've done a lot. We -- first of all, we've increased our core areas. We are now involved from the very north in the NCS to the south with 7 different core areas. We are focusing a lot in recoveries and maximize recovery and step-out within their existing assets. And then obviously, we're also focusing on mature basin with lower risk. And then also frontier area. So we really have 3 pillars on the organic growth, and each one of them can have significant impacts on the future and our ability to grow even more than what we show you. So I guess, my seventh message to you is there are definitely multiple organic growth opportunities. And I definitely believe they are significant yet to find resources. And finally, organic growth opportunities are definitely far from over. There's a lot to do, and I think there will be quite a lot of surprises over the years.

The capitalization strategy, as I said, it's been a long -- it's not something we decided a week ago by issuing the press release. It's something we started long ago. And as I mentioned, the pillar of this decarbonization strategy is the electrification of the platforms. We also made a step, a commitment, that we will replace all our electricity consumption in Utsira High, i.e., Edvard Grieg and Johan Sverdrup by investing in equivalent project on the renewable. And that has got a business angle, too, because by being both on the producer side and on the consumer side, we actually have a natural hedge to the electricity cost. And since we're using a lot of electricity on both Edvard Grieg and Johan Sverdrup is not insignificant. And then there is obviously a smaller part, which is the offset, so what we cannot -- because we can already reduce down to 0 as the natural carbon capture. So this makes the pillar of the carbonization strategy with the ultimate objective to become carbon neutral by 2030. And -- but as I said before, the key is to have the lowest possible emission that has to be #1 priority. So I would say my eighth message to you is Lundin is definitely committed to ESG, and we definitely have a long-term ambition of being one of the leading company in the industry in terms of emissions. And moving to carbon neutrality by 2030. But all this while still delivering significant returns or superior returns to our shareholders.

Safe and responsible operations. I have to say, the Norwegian team has done a fantastic job. When you look at the track record in terms of serious incidents and safety process, we're absolutely at the very top. And if you don't have safe and responsible operations, you don't have a business. So it is an absolutely key element of the Lundin operations. And I have to say, a lot of Norwegian people are extremely focused on this. And that goes of the same with ESG ratings. If you look, I'm not going to go through them, but you'll see that the company tracks very well when measured on ESG ratings. And this is my final slide.

So in summary, on the high level, we have a long-term guidance of 160,000 to 170,000 barrels of per day. Our ultimate target is to achieve above 200,000 with our existing assets and with our existing developments. In terms of OpEx, I said it, we are industry-leading, and we have a range between USD 3.20 to USD 4.20 per BOE, and this is not just in the near future, it's actually in the long term. Obviously, good production and low operating cost that leads to strong financials, and we maintain $1 billion of average free cash flow over the years, which is over 10% yields despite the fact that actually, we sold 2.6% on Johan Sverdrup in our last summer. And dividend, we maintain our policies and strategy, which is to have a sustainable dividend and growing over time. And this year, we've announced a 22% increase.

Along this, I think the carbon -- becoming carbon natural (sic) [neutral] is, in my view, part of the -- eventually, the license to operate as an oil and gas company. And of course, as I mentioned before, we have to continue to be safe and responsible. Otherwise, we will have no business.

So with that, I think I'll leave it to Nick next, and who will really dive into the details. So okay. Thank you, and over to you, Nick.

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [3]

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Well, thanks, Alex, and good morning, everyone. It's really nice to see you all here at our Capital Markets Day again here in London. I'd also be happy -- I'm excited to give you an update on our business today and also be keen to answer your questions later.

Our business is underpinned by world-class assets and that provides us a reliable low-cost growth trajectory as we look forward. And what we're going to do is we'll talk about our business outlook, how it's evolved since last year. We're going to update on the guidance targets that we -- updated guidance targets that we announced this morning, and we'll also take a deeper look at the key assets that underpin the business and drive that strong performance. And when Per Øyvind talks later, we'll have a look at the growth opportunities that keep that going into the future.

So first of all, 2019 production. Last year, we produced 93,300 barrels a day. That was above the midpoint of our updated guidance of 90,000 to 95,000 barrels a day. And if you recall, we sold 2.6% of Johan Sverdrup last year. And if we back that out, actually, we are right at the top of our guidance range that we set at the beginning of the year. So a good year on production. You can see that we're now 18 quarters that we've met or exceeded guidance, and we aim to continue to do that and do what we say we're going to do, and we've set our guidance for 2020 with that in mind as well. And this has been underpinned by continued strong performance both at Edvard Grieg and Alvheim, both on the reservoir front and on the facilities front. And you can see here the stellar production efficiency metrics that we achieved last year, 98% at Edvard Grieg, and 97% at Alvheim. Those are world-class metrics. And of course, last year was an important year for the start-up of Johan Sverdrup, which happened in October 5, ahead of schedule, and we've seen the ramp-up go better than expected. And that's resulted in a step-change in production in Q4 to 135,000 BOEs per day, and we exited the year at around 155,000 BOEs per day. So doubling our production from the beginning of the year to the end and Johan Sverdrup is going to continue to ramp up into 2020 to plateau during this year.

So in summary, stable, reliable, consistent quarter-on-quarter production from Edvard Grieg and Alvheim, and then with the start-up of Johan Sverdrup and ramp-up ahead of expectations, driving that step-change in production that we see going into this year.

So we now take a look at 2020 production, and Alex said, our guidance is 145,000 to 165,000 BOEs per day for this year. And this is set around the variability of the assets and the timing of the ramp-up of Johan Sverdrup Phase 1 to plateau. Edvard Grieg, we're going to see a plateau through this year, and we'll talk more about the outlook for Edvard Grieg in a while. But we do have a 2-week maintenance shutdown in Q2 for Edvard Grieg, and I'll touch on that later.

At Alvheim, it's the new wells that we drilled last year. And the wells to come on this year will arrest the decline. But we also have a cut back in Q2 and Q3 for maintenance of the terminals, gas terminals in the U.K., which impacts those 2 quarters. And then key point is we'll see Johan Sverdrup Phase 1 ramp up to plateau. It's expected in the summer of this year, and we need to drill a couple of extra wells before we get there, and Kristin will give us some details on that later. But of course, we need to see long-term stability at Johan Sverdrup, and we need to test the facilities upside. But so far, that's looking great. And again, Kristin will cover a little bit of that, but I'm quite positive to seeing some upside here on facilities capacity. But it's going to take some time to see that come through. So we put a range around all those factors, and that's what drives our production outlook of 145,000 to 165,000 barrels a day. And you can see we've got off to a great start this year averaging so far in January, about 155,000 barrels a day. So a great start so far.

So next I want to spend some time on the cost side of the business. We've continued our trend of industry-leading low operating costs, as Alex showed. You can see the benchmarks to industry averages in the U.K., where we're about 1/4 of the U.K. average and about half of Norway average, and we see that trend continuing. It's underpinned by our quality assets, early life assets that where the facilities have fallen we see that -- you'll see that going forward too. Our 2019 [out term] was $4.03 per barrel. That was 5% below guidance. Cost was bang on, and it was driven -- the better than guidance outcome was based on additional production. And for this year, we're guiding $3.40 per barrel, that's below 2019 levels. And the impact there is we're now getting an impact of Johan Sverdrup, which is incrementally lower operating costs and when Johan Sverdrup reaches plateau will be below $2 per barrel there. So that drives the outlook. And we're also improving our long-term guidance beyond 2020 to a range of $3.20 to $4.20. So I think you can see truly leading low OpEx. It provides resilience to our cash generation of our business title we'll talk about later.

So now step into the assets. We'll start with Edvard Grieg. And these assets provide that growth trajectory. And over the last few years, we've talked about our aim to keep the Edvard Grieg facility full in the long term. And I think you'll see we continue to have success in our objective. We see upside reserves at Edvard Grieg and the sanctioned infill drilling program there, which we'll talk more about. We drilled some step-out exploration wells around the fringes of the field last year at Tellus East and Jorvik met success there. And those 2 areas can be developed from the platform. We sanctioned Solveig Phase 1 development and the Rolvsnes extended well test and those projects are moving ahead, full steam ahead, and we see upside around those, and we'll be testing that as well. We drilled a successful appraisal well at Lille Prinsen, and we're discussing further appraisal now. And we also have a significant exploration upside position here, which we'll touch on, and we will continue to drill in this area for a long time. So I think you can see we're building this conveyor belt of opportunities to keep the facilities full in the long term. And I think this is a story you'll see us come back to over the years because I think there's a lot more to come out of this area.

So looking a little bit at the Edvard Grieg operation. It's been very strong operating performance. I mentioned world-class production efficiency of 98%, but we don't plan on that going forward. We take a slightly more conservative look. And I also mentioned that we have a 2-week planned shutdown this year, which does impact production output from Edvard Grieg. This is the first planned maintenance shutdown we've had since start-up. And we're also using the opportunity to do the tie-ins for the 2 tie-back projects so that we don't have to have a shutdown in 2021. So when you put that together, we're planning on an average production efficiency this year of 93%. The other side of this is that we share capacity with Ivar Aasen at Edvard Grieg. And we plan this based on that we just have our contractual capacity, but there is potential upside here when Ivar Aasen comes off plateau, and that is expected, perhaps later this year or early into next year, and we see potential to expand Edvard Grieg production when that happens. But our outlooks don't assume that. So that's potential upside on what we're showing.

So in summary, a stable, reliable production at plateau Edvard Grieg, with the exception of these 2 weeks of shutdown through the year. Now looking at the reservoir, it just continues to outperform. Ultimate reserves now stand at 300 million barrels gross and counting. That's over 60% above the original PDO. And we continue to see reservoir outperformance, the capacity of the wells now is still significantly above the facilities capacity that we have and 4 years into production, we're seeing minimal water production. So it's less than 5%. So going great, and we see further upside. You see we have 3P reserves, and we have 2C contingent resources that could take this up to around 380 million barrels. But I think we really need to see a water production trend before we can -- we start to calibrate the models. We'll get some more information this year. We're shooting another 4D seismic survey, which we did a few years ago, and got great results from. So that's going to be exciting to see when we get the results in the summer. And we'll be drilling our infill wells, which will also be useful calibration points.

We did sanction an infill program this year, 3 wells and that added 18 million barrels. And you can see that it has tremendous economics, a breakeven oil price of less than $30 a barrel and rates of return greater than 30%. So a project you would do any day. And we have the Rowan Viking rig on contract to do this program. That's the rig that drilled all the development wells so far in Edvard Grieg, that will come to us and start drilling in Q3. And we have 3 firm slots on that with some option slots. So it's going to be exciting to see that program come forward, and it's going to give us a lot of flexibility on the platform.

So I think there's tremendous reservoir performance. I think there's more to come. And I'm actually quite positive about seeing some reserve progression this year, and I know Per will probably kill me for saying that, but that's what my view is. And so I think it's very positive, and we'll see more coming out of this area.

So now stepping out a little bit away from the Edvard Grieg platform. We'll have Solveig Phase 1 and Rolvsnes extended well projects that we sanctioned last year, and these are now going full ahead. They're being done, there's basically 1 project together with the same contracts and same people, the top size modifications are ongoing at Edvard Grieg. Subsea installation will be in the spring, and we'll start drilling in the second half of the year using the rig that you can see here, the West Bolster and both projects are on track, and we should see Solveig first oil in the first quarter of '21, and then Rolvsnes extended well test is going too from a quarter later in the middle of 2021. These hybrid projects have tremendous economics. Really, it's limited CapEx. It's a subsea infrastructure. It's the wells, and there's minimal OpEx, additional OpEx here. So you can see the Phase 1, Solveig Phase 1 project, has great economics to breakeven less than $30 a barrel and the rate of return greater than 25%. So the more of these projects we can do, we can add a lot of value. And Solveig has quite a lot of upside. The Phase 1 development wells are aimed to test that. So I'm hopeful that we'll see further phases of Solveig in the future. Rolvsnes extended well test is also an important project for us. It's going to derisk the basement play that we have here. We drilled a good horizontal well there a couple of years ago and had good rates out of them, very excited to see that. And there's quite a lot of potential in the Edvard Grieg area around this, so it's going to be exciting to see the results there. And that we'll start to see in 2021. And we've put this together in a flexible way so we can scale up, and really, it's about just adding wells to gather the extra resources. And so it makes follow-on developments incrementally lower cost, and we aim to build over time, so that we develop all of the resources in the area.

Now stepping on to -- outside of that, there's actually a lot more to come. We -- it's a very prolific area, and there's significant upside beyond what we've discovered so far. Under production or under development, resources now stand at 360 million barrels gross. And you can see that we have the potential to double that to over 750 million barrels with the upsize, and we see upsize at Edvard Grieg, Solveig future phases, Rolvsnes for developments and significant prospectivity remaining in the area, and we'll be drilling 1 well this year, which is the Merckx well just off to the west of Solveig there.

So I'm optimistic we're going to be drilling here for many years to come, and I'm optimistic that we're going to find a lot more resources. And these are hugely valuable barrels, as I say. CapEx is low because the facility is in place, and OpEx is also low. And we aim to phase this activity, so we keep the facility full in the long term, which is what you see on this chart, which is what that all adds up to. We continue to extend the profile and plateau at Edvard Grieg and see the original plateau at the PDO time for Edvard Grieg was around 2 years. Now with current Edvard Grieg reserves and Solveig and Rolvsnes extended well test with -- and 2P reserves, we're moving this to the end of 2022, which is a 4-year extension. And then when you see the 3P upside and the 2C contingent resource, we can move this to 2025, so that's an 8-year plateau from where we started out. And then there's prospective resource on top of that, and I'm confident we'll be pushing this out further. And as I mentioned earlier, this is based on contractual allocation of capacity through Edvard Grieg. And when Ivar Aasen comes off plateau, we have the capacity to accelerate some of these volumes and that's not built into our outlooks. And that could come as late as sometime late this year, early next year. So it's an evolving story, and I think it just keeps getting better and better. And I think if we come back in a few years, you'll see this is going out further.

So now going to the Alvheim area, which has been a tremendous asset for us over many years. It's actually a bit more mature than Edward Grieg, but it's the same story, really. We're 10 years in, and we keep pushing reserves out and plateau out and adding reserves. So I think if you look at this, it's a good analogy for how I think Edvard Grieg will look in the future. You can see reserves now close to double the original PDO level. And we keep finding new opportunities. In 2018, we made the Frosk discovery. And then we followed that up last year at the beginning of the year with making 2 discoveries in the vicinity of Frosk, which is the Froskelår and Froskelår Northeast discoveries. Frosk is now online through the boiler subsea facility. So we got that online within a year of discovery. And it's the sort of thing we might be able to see happen for future infill opportunities. Now we have the subsea facilities in place at Edvard Grieg. And we're now thinking about an area of development around Frosk, including the Froskelår discoveries, and that's something being evaluated.

Also last year, we made -- we drilled a multilateral pilot holes in Alvheim to set up some infill wells, and that was successful. And leading some of the wells that we're drilling this year and the development thinking around the Kobra and Gekko discoveries is being progressed. So it's a continuous story of reserve growth and arresting the decline which you see on the next slide. Again, continued strong operating performance. And last year, we produced 14,800 barrels a day net to us, which is around 15% of 2019 production volumes. And we've got good results from the 2 new wells that we brought online in 2019, arresting the decline. So you can see in a mature field, it was flat production through the year. And hopefully, we can keep that going.

Looking forward to this year, I mentioned that we have some maintenance shutdowns on the gas terminals in the U.K., which results in cut back in Q2 and Q3. And other than that, we continue to see a reliable performance through this year. We're going to be bringing -- drilling 2 new wells this year. One will come online this year. One will come online in 2021, and those wells are in Alvheim and Volund, and hopefully, they will arrest the decline. So whilst this asset has a reduced impact in our overall portfolio because the growth with Johan Sverdrup is still an important and quality asset for us and continues to perform.

So now bringing some of that together with our reserves results. Our growth trajectory is underpinned by our significant reserve base. Two weeks ago, we announced our 2019 year-end reserves, which I hope you've all seen, and we increased reserves again. Our 2P reserves now stand at 693 million barrels. And we added around 52 million barrels last year. And that came from the sanctions of the project Solveig Phase 1, Rolvsnes extended well test and the infill program at Edvard Grieg. And you can see it's a similar story for 3P reserves at 857 million barrels, again an increase.

We have a long reserve life index, it's 20 years. So that means it takes 20 years to produce out our 2P reserves and that ranks higher than most of our peers, and I think it demonstrates the long-term nature of our business that we have. And if we looked at the track record, we have a strong track record of adding reserves over some period of time. You can see our 2P reserves replacement ratio last year was 150%. That means we -- for every barrel we produce, we have 1.5 barrels, and that's the sixth consecutive year we've managed to do that. Sixth consecutive year with a reserve replacement ratio greater than 100%. And we've done that at the same time as increasing our production by 4x. So it shows we've been growing the business in the long term. And that's come from multiple sources. It's come from increased reserves, but it's also come from bringing contingent resource into development. But this is going to get harder looking forward. We're now doubling our production this year compared with last year. And so the task is going to come harder. And -- but I think we have a good flow of organic growth opportunities that Per Øyvind is going to go through to help drive this forward, but it's going to be a bigger challenge for us to keep this going.

And then when I put that together, that reserve growth underpins our production outlook. And for the fourth year running, we're increasing our long-term production guidance from the business. As Alex and I already stated, our 2020 guidance is 145,000 to 165,000 barrels. And that's -- and our 2P reserves, long-term guidance, we're now updating to -- from 2020 onwards to the range of 160,000 to 170,000 BOEs per day, and that's from 2P only reserves. Previously, you will have noticed, we had a step-change in the profile in 2023 when Johan Sverdrup Phase 2 came online. But what we see is with the extension of the plateau at Edvard Grieg, and the sale of 2.6% in Johan Sverdrup, they offset each other, and so we end up with more or less a flat profile through there in the range of 160,000 to 170,000 BOEs per day. But I think we've seen a good progression of upside from the assets, and we see upside in the 3P reserves and 2C resources in the existing field base that has the potential to get us over 200,000 barrels a day. And you can see what that might look like if those things come to fruition. And we could get there as early as 2022 if things go in our way and the fields perform well.

So in summary, it's a strong, reliable, low cost, long-term growth outlook, and that underpins our strong cash flow generation. And I have an expectation that we're going to do even better than this looking into the future. And I'm now going to hand over -- this is my final slide for now. I'm going to hand over to Kristin, who's going to talk about on Johan Sverdrup, which is also key components of driving this forward. So it's going to be -- I think that's an interesting area to look at.

Thank you.

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Kristin Færøvik, Lundin Norway AS - MD and Director [4]

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So a very good morning to you all. It's my great pleasure to share the Johan Sverdrup story with you all this morning. And the headline, In a League of its Own, couldn't be more accurate to this field. Johan Sverdrup is simply an amazing project. There's something so complex. The time from discovery to submittal of the plan for development and operations and until first oil has simply been very, very short. Added to the share size in both volume and aerial extent, what's the need to find an area solution for power from shore as well as unitization across several licenses. And here, we are looking back at a very, very successful project execution by operator Equinor and a phenomenal production start-up phase.

Some of the headline figures describing the project are shown on the screen in front of you. And they are familiar to many of you. The development is -- it's unique in so many ways, and we are particularly pleased with the low carbon emissions from this giant. Incredible savings have materialized since project function, contributing to a full field breakeven price of less than $20 per barrel. Not to mention that Johan Sverdrup is hugely important to [Norway Inc.], contributing some NOK 900 billion to the Norwegian state. And it has been and still is very important to the Norwegian supply industry.

It all began in 2007, or rather probably with a license award in 2004. But the Edvard Grieg discovery well confirmed the idea that there could be remaining petroleum deposits in this area. Although at the time, it was not possible to identify in seismic. The Edvard Grieg discovery gave us the confidence to move on to Avaldsnes, which is now Johan Sverdrup. And prior to the 2011 Aldous well, Lundin had drilled a further 3 wells on Avaldsnes, and we were starting to understand that we were chasing an elephant. Reserves kept growing and now sit at the range of between 2.2 billion and 3.2 billion barrels of oil equivalents.

The development itself is truly remarkable and is one of the largest industrial projects in Europe. 71 million man hours was used in Phase 1, 30 sites across the globe and use of groundbreaking technology, of which the use of installation vessel, Pioneering Spirit is just one example. The field has been powered with electricity from shore since day 1. And Johan Sverdrup is also the catalyst for electrification of the Utsira High at large.

To give you a little taste for the scale and complexity of the project, we have compiled a short video. So please enjoy.

(presentation)

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Kristin Færøvik, Lundin Norway AS - MD and Director [5]

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Now the first few months of production have confirmed that this is indeed an extraordinary field. Our assumptions about connectivity across the reservoir have been proven by excellent field-wide pressure communication. The distance from the injector in the south to the injector in the north is 17 kilometers, and it's not hard to see that 2 are well connected. Whilst we said a few months back that we would need between 2 and 4 additional producers drilled from the new drilling platform to reach plateau production of 440,000 barrels a day, we are now comfortable the 2 new producers in addition to the 8 predrilled wells already onstream, will be sufficient to reach plateau this summer. And to put the field in perspective, Johan Sverdrup was Norway's largest oil-producing field, when the third well was put on stream, and it is already producing more than 3x as much as #2 and 3 on the list.

Furthermore, if you assume the midpoint of the resources range of 2.7 billion barrels of oil equivalents, divide that by the number of production wells outlined in the 2 PDOs, every producer is expected to recover, on average, more than 70 million barrels, truly remarkable. Rest of our performance to date has been excellent and has confirmed the drill stem test data, which from the appraisal wells were limited to certain parts of the field. The drainage strategy is ambitious. And the goal of recovering more than 70% of the resources in place was set before start-up. Experience to date confirms what we assumed in the strategy. And therefore, that the chosen development solution was indeed the right one. Permanent reservoir monitoring cables have been installed on the seabed. And this [TRM] system is expected to give accurate images of how the fluids move over time in the reservoir as annual surveys are shot. And it will be a very effective tool for reservoir management and eventually, identification of infill drilling targets.

Water automating gas injection, WAG for short, is enhanced oil recovery mechanism that will be tested out in a few years' time. Full field WAG could be tangible -- of tangible value when Solveig comes off plateau. But the pilot will be running 2023, when a water injector will be turned to gas injection and an observation well drilled to see how the (inaudible) performs to gas injection. Equinor has made Johan Sverdrup the poster child for data sharing with the other licensees, and there is no lack of data to share. That's probably the understatement of the day. The fiber cable in each of the wells provide an enormous amount of information that allows us to understand not only the condition of downhole equipment, but when we get it across the reservoir, will act as permanent production logging, so that we can get a very detailed understanding of well performance. And Lundin is making the most of this real-time data sharing and thereby continued contribution to the value creation of the license and for the operator, less time can be spent on reactive reporting when everybody's got access to the same information.

For Lundin, this also holds valuable learning that we can transfer to Edvard Grieg, where we are considering installation of fiber cables in the upcoming infill program.

Phase 1 of Johan Sverdrup was gigantic. And Phase 2 is by no means a small project. By global offshore standards, it's a very large project, indeed. Capital expenditure is estimated to NOK 41 billion, several subsea structures will be installed on the seabed, a new processing platform added to the field center to weight 25,000 ton topside. We will also add a 6,000 ton module to the riser platform and module that in aerial extent will be close to a [football pitch].

The Norwegian supply chain that delivered so well for us in Phase 1 is hard at work also in Phase 2, and continuity of technical solutions and suppliers from Phase 1 has enabled an early construction start for Phase 2, and also reducing -- thereby, reducing execution risk.

So there's now a high activity level on all Phase 2 sites, construction sites, both in Norway and elsewhere.

So Johan Sverdrup is well on track for plateau reduction from Phase 1 this summer. Phase 2 is also well on track and progressing really well towards -- in accordance with its schedule. Carbon emissions are a fraction of the global average. And on top of all that, the operating costs are 1/4 of the average for the Norwegian Continental Shelf. So what other conclusion can you possibly draw than Johan Sverdrup is truly a field for the future. Thank you.

And now I'll hand over to Per Øyvind.

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Per Øyvind Seljebotn;Reservoir Development Director, [6]

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Well, good morning, everyone. I will now talk you through our organic growth strategy. And first, an introduction. At the core of organic growth strategy is also subsurface expertise. It is the understanding of the subsurface that creates the opportunities and where the risks are, and it is what creates the exploration opportunities and what creates the increased recoveries on our fields.

We're applying cutting-edge technology in exploration phase and to maximize recovery on our existing fields, and I will show some examples of that. A key component of Lundin Petroleum's success has been our ability and willingness to chase new plays and new reservoirs. We've had the guts to believe in our own ideas, and we have been successful in chasing them, and we will continue to do so.

Our post-filing cost -- post-tax filing cost now stands at $0.80 a barrel. Through the last couple of years, we have increased our number of licenses from 50 to 90. We've expanded our footprint significantly, and we're now pursuing exploration opportunities in 7 core areas from -- mostly being focused on the Alvheim area, Utsira High and the Barents a few years ago. We'll keep a good balance between mature areas with smaller, low-risk, high-value barrels, new infrastructure and the frontier explorations -- exploration areas that can give large volumes. This year's exploration program consists of 10 wells, targeting gross prospective volumes of more than 650 million barrels, more on that later. There are 4 projects underway and 4 in the pipeline. We see a significant potential on the Norwegian Continental Shelf and the Norwegian Petroleum Directorate has estimated a yet to find of more than 15 billion barrels.

On to our organic growth opportunity set. Our gross resource space consists of more than 1 billion barrels. Our 2020 program will target a net 150 million barrels, net risk of prospective resources, and we have another 0.5 billion barrels of net risk prospective resources that we are now working actively to mature exploration wells to target. Our organic growth strategy focus is on 3 areas. We have maximizing recovery and step-outs. And over the last 4 years, we've increased our 2P reserves with more than 150 million barrels on our existing fields. These values are of very high value. The recovery factor on Edvard Grieg has increased from 38% to 55%, including the sanctioned infill program. The Alvheim has been a tremendous field, and we are sure that Johan Sverdrup will perform.

In 2019, we found more oil in the Eastern part of the Edvard Grieg field in the Jorvik and Tellus discoveries. We now increased our footprint in mature areas outside of the Utsira High and Alvheim areas. We believe there is significant exploration potential in these areas, like Northern Sea -- North Sea, where we are building a presence. And we're testing high-value barrels and their infrastructure in the Northern part of Utsira High with the ongoing Iving and Hasselbaink wells. We continue to generate new prospects in Utsira High, even though, that has been a very -- there has been activity there all the time since the start of the oil industry in Norway in 1960s, and we've had it as the core area, since we entered Norway in 2004.

This year, we'll drill the Nose prospect there, and next year, we plan to drill the Fleece prospect there.

There are still significant frontier areas in Norway, areas with few or no wells, significant potential exists in these areas. We have several wells in that category in our exploration program this year.

Exploration in frontier areas is a long-term game and it requires persistence. Technology is a key driver for us, and here are some examples. We are a front-runner in the seismic technology. We've a long history of creating value from improved seismic imaging. Edvard Grieg was hardly visible on seismic before discovery. Continuous improvement -- focus on improved imaging has resulted in tremendous uplift in imaging and is a key driver for the increased recovery that we've seen on Edvard Grieg.

The first large-scale GeoStreamer was shot on Utsira High, the first large scale Broadseis was shot on in Utsira High and we've gathered the first large-scale top-size survey over our Loppa High area. It's helped us better define the resource potential in Alta/Gohta. It is what we mapped the Bask prospect on and a test for the next-generation of top-sized was shot across the Utsira High last year, and it's now helping us better define the Solveig Reservoir.

We are continuing to improve imaging technology. We have in-house processor, interpreters and programmers that work all the time and delivers new technology, to develop improved processing sequences that we believe will bring down cost and time and improved seismic imaging. We're using artificial intelligent techniques in the recreation of undersample [wave fields] that this improves imagery, and we use it to improve processing sequences and develop automated seismic interpretation techniques.

Some value-adding technology for our reservoirs. Here's a couple of examples. Two of the infill wells on Edvard Grieg is now planned with fishbone technology. This technology enables 50 small holes, about an inch in diameter to be drilled out of the main bore, 12 meters into the reservoir. We've modeled significant potential to increase recovery and rates in the conglomerate reservoirs on Edvard Grieg with this technology. Two installations previously on the Norwegian Continental Shelfs. We've supported this technology with our R&D funds always. This started in 2012, and are very happy to be able to install it in our own field.

We also have an example here of technology in the R&D phase. In-field control valves that prevent -- preferentially choke back water and gas has been applied very successful in the Alvheim field, but the existing technology cannot be applied, for example, to Edvard Grieg because of the oil characteristics on Edvard Grieg. We're now supporting R&D project to develop the next-generation of in-flow control technology and that will work independently of oil characteristics.

As it significantly lowers water and gas production, it also reduces the need for injection on the facility and energy's consumption. In addition, it has the potential to significantly improve recovery.

4D seismic has been driving the infill drilling at Alvheim. We have successfully acquired a 4D on Edvard Grieg and the results are excellent. We can clearly see how the oil is being displaced by water in the reservoir and have identified the bypassed areas, where we will -- which we will target with the infill program at Edvard Grieg. It also improved reservoir models, volume estimates and forecasts. This is an oil field that was hardly visible on seismic before it was discovered.

So now on to our contingent resource base. We are, of course, very focused on maturing resources into reserves. And this year, we managed to mature 49 million barrels of contingent into reserves, and that's what's driving our 2019 to be 150% reserves replacement ratio. The main part of this being -- sanctioning was tooled by an infill campaign on Edvard Grieg. Our challenge is to add to our contingent resources with new discoveries. Exploration in 2019 did not give significant volumes to backfill our contingent. We only booked small volumes for Jorvik/Tellus discovery and a WAG project on Edvard Grieg.

The -- we also had a negative revision on Alta/Gohta, which we will get back to later. It is, of course, in the front of mind all the time to grow the resource base, and we're hoping for success in the 2020 program and beyond, which can provide significant volume additions to the contingent.

More on maturing resources to reserves. We have 8 projects in our portfolio. Four of these has been discussed before: the Sanction 1 Solveig; Rolvsnes; Edvard Grieg; and the Frosk. We made the Goddo Tellus discovery in 2019. The potential in those areas can be significant, but the exploration wells themselves only proved small volumes. Given our successful Rolvsnes EWT proving the basement play to be commercial, they will be evaluated for further appraisal drilling and potential production well drilling from Edvard Grieg.

The Kobra East/Gekko Project is a possible project for sanctioning this year, a very interesting project in the Alvheim area. The mainly a gas discovery, but learnings and technology transfer from using inflow control valves from Alvheim can make it possible to develop for only 6 meters [take] oil column below the gas there. Volume potential of 31 million to 56 million barrels. The Lille Prinsen appraisal confirmed the western extension of the discovery, but did not move the volumes significantly, but an appraisal well is expected next year.

I'll talk about Alta/Gohta on the next slide. In total, we have 8 potential projects, targeting 100 million to 300 million barrels net to Lundin.

On to our Southwest Barents strategy. On Alta/Gohta, the extended well that showed that we have an excellent reservoir. We have excellent productivity and very good communication laterally in that reservoir. That was the main objective of that EWT. Unfortunately, the EWT, together with top-sized [interpretation] showed that the in-place volumes are lower than we hoped for. The gross resource range now stands at 70 million to 225 million barrels of oil or 110 million to 330 million barrels of oil equivalents, if you include the gas. We don't see a good enough economy in a stand-alone field development on Alta with the current volumes, but we see a profitable tie-back into Johan Castberg, when capacity is available there, but it's not expected until 2030.

We'll now switch back to the exploration mode on the Loppa High. On the exploration side, I'll start with the Bask prospect, 250 million barrel potential prospect, and it's located around 30 kilometers West of Alta/Gohta. Given success, this can trigger a joint stand-alone development together with Alta/Gohta.

Polmak targets a new play on the eastern flank of the Loppa High, success in the Polmak very well can prove this play and a significant upside of 700 million barrels exist in that area. Both of those wells are operated. Further on, we'll participate in the Equinor operator century well. This prospect also carries significant volumes, around 360 million barrels, with targets at multiple levels and with a significant follow-up potential of more than 1 billion barrels in the area. To the South, we'll participate in the Equinor-operated Spissa well, targeting 200 million barrels, with also a significant upside, should we have success.

We're building new core areas in the Northern -- North Sea. We acquired a modern regional 3D survey. We have established a significant license position over the last 2 years. We are now evaluating prospectivity and expect to develop drilling targets next year.

In the Norwegian Sea, this -- have established a presence in the West Froan Basin gas play through our (inaudible) into the Balderbrå discovery. The Balderbrå appraisal is ongoing on 110 million barrels equivalent gas discovery. The transaction also includes options to acquire working interest in other licenses in that area. And to the South in the Norwegian Sea, we will be drilling the Melstein prospect, with 160 million barrels of potential, again, with follow-up potential in the area.

In the Central North Sea, we continue to find opportunities in this very prolific area, and Iving and Hasselbaink is ongoing on the Northern part of the Usitra High. These are prospects [near] infrastructure and can prove very high-value barrels. Merckx, immediately West of Solveig, with a prospective resources of 152 million barrels, can be a possible tie-back to the Edvard Grieg facilities, and we will drill a very interesting well on the Sele High, called Dovregubben, with more than 200 million barrels of potential.

I've talked you through the expansion program for 2020. We will drill 10 wells, 5 of these are operated, 9 are exploration wells, 1 appraisal on the Balderbrå discovery. The program targets mature areas and frontier areas. Several of the prospects are quite similar to the prospect that was drilled on Usitra High and ended up as Edvard Grieg and Johan Sverdrup in terms of being drilled in under-explored area, target new places or extensions of existing places. The program target 650 million barrels net unrisked and more than 150 million barrels prospective resources.

A huge part of Lundin's success has been driven by success in exploration. We have a very good program for 2020, and we are actively building a program for 2021. And with these slides, I hope that it has come across that there are large underexplored areas on the Norwegian Continental Shelves, with few wells and untested prospectivity, only part of the NCS is mature, and we also see significant potential in the mature areas. As long as there are underexplored play areas, the chance of finding big material discoveries exists.

In summary, we have 3 legs underpinning our organic growth strategy: frontier exploration; mature areas; and maximizing recovery of our existing fields. As we've shown in this presentation, we will target all of these 3 different areas with our 2020 program.

Thank you very much for your attention. I believe we're up for our coffee break of about 15 minutes. So see you back here in 15 minutes. Thank you very much.

(Break)

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [7]

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Okay. Well, welcome back to our Capital Markets Day.

I'm now going to spend a little bit more time talking about our decarbonization strategy that we announced a few days ago, and Alex set out the roadmap at the front end of this towards achieving our targets of carbon neutral by 2030.

The roadmap that Alex showed had 4 elements to it. It was around reducing emissions, reduction from energy efficiency. Electrification was a big part of that, with power from shore and then replacing the power we use with renewables. And then on top of that, natural carbon capture as an element to it. So there's 4 elements. And what I want to do is provide you a little bit more background on what we've been doing and the actions that we're taking towards our pathway of carbon neutral.

So this first slide gives you a sense of the journey that we've been on. And as Alex said, we started this actually a decade ago, when we prepared Edvard Grieg for electrification around the PDO time. And then in 2015, the Johan Sverdrup PDO included full electrification and power from shore. And then last year, we committed to the project to fully electrify Edvard Grieg. So today, we sit in a place where Phase 1 of Johan Sverdrup is fully powered from shore. And then by 2022, we will have Johan Sverdrup Phase 2 and Edvard Grieg also powered from shore. And with that, we'll achieve a carbon intensity for those assets below 1 kilogram of CO2 per boe, and that's around 1/20 of the world average, and I'll show you some benchmarks later as to how we stand.

So it moves those assets and those are the bulk of our assets and they are in a great place. And just to reassure you, not only are we're reducing carbon, but actually, this is pretty good business as well. We see that we get -- we're going to get improved uptime. As a result of this, most of the downtime that we see at Edvard Grieg is around our power generation and electrification should improve uptime. We'll reduce maintenance costs. We have, obviously, reduced our carbon taxes, which are set to go up over time. And we increase our gas sales, which then we have to offset with power purchases. But the net result of all that is it gives a good economic return on these projects as well as reducing our carbon footprint. So it's a good business from a lot of perspectives.

We've also additionally said from 2018, and we're doing this, which is going to offset all our business and operational, air travel, including helicopter travel, with natural carbon capture which is a [3 party] project that we're involved in, and we'll continue to do that. But when you put all this together, we're also buying a lot of power, and we get our power from Nord Pool, which is the Nordic Electricity Transmission System, about 2/3 of that, when you look at it, is renewable power, but the other 1/3 is from other sources.

And what we set out in our strategy is that we wish to replace all of the power usage that where power purchases that we're making with renewable projects, investment -- direct investment in renewable projects that then offset and replace the power that we're going to be using. And so we plan to fully offset that by the time Johan Sverdrup and Edvard Grieg are fully powered from shore. You can see that our level of investments along the top of this chart. So our investments in power from shore and our investments in renewable projects to fully replace the power we're using by 2023 will cost us around $750 million, of which, we've spent around 1/3 so far, 2/3 of that actually is the power from shore cost, and around $250 million relates to renewable investments to support our power usage.

And you can see, on the bottom of the chart, the impact we get from this. Back in 2015, we had a carbon intensity for our business. This is net average across our -- all of our assets of 9 kilograms of CO2 per barrel. We're about 5 kilograms this -- in 2019, and you can see that by the time we're fully electrified, we go below 2 kilograms per CO2 per barrel, and I'll show you where this sort of benchmarks us in terms of the industry in a few moments.

And so we've set the target of carbon neutral by 2030, and that's from our operational emissions, that's the emissions that we generate through our production. And when you look at the terminology, Scope 1 and Scope 2 and the direct operational emissions associated with Scope 3 that we can have an impact on. And you can see that we actually have further to go to get there. So you'll see that we'll have to invest in some natural power. That's some natural -- some further offset projects to get there.

So now looking at our power usage and how we're going to replace that with renewables. The chart on the right shows the amount of power that we're going to be using on a net basis for the company, when the Johan Sverdrup Phase 2 and Edvard Grieg are fully powered from shore from the end of 2022 onwards. And you can see that our power usage is around 500 gigawatt hours per annum and it's not a small amount of power. And our aim is to build a portfolio of renewable investment to replace all that usage, and we can do that with projects that generate good returns. So we're making returns on the power from shore business, but we're also making good returns on the -- on delivering the power to fuel that.

We have completed 2 deals over the last few months. Firstly, we announced a deal for a hydro project, for Leikanger Hydro Project, in Midwest Norway in our Q3 results. That's operated by Sognekraft, so we're really just a financial partner and it doesn't take a lot of management time. We'll see first power from that in a few months and then it can be fully operational in 2021. And that project gives us about 20% of our ultimate requirements to -- so a 100 gigawatt hours when it's fully running and that investment costs about $60 million, which we'll spend over this year and next year.

And the second project, which we announced this morning and we actually closed yesterday, is the MLK wind farm project. I won't try and pronounce it, it's too difficult. But we've just done that. We'll see first power from the end of '21 or early '22. We have taken a 100% of that project. It's operated by OX2. They have a good reputation as a developer of wind farms in the Nordics, and -- but our intent is to farm that project down to 50%. So the figures that we show here are only half of it, and we're talking to a number of parties. And the reason we want to farm down is not because it's not a good project, it's actually a great project, but we'd just like to diversify our opportunity set. So you'll see that we do some other projects to make sure that by 2023, we have a generation capacity of around 500 gigawatt hours per annum to replace the usage that we have.

So with the projects we've done and 50% of MLK, we get to about 60%. You can see that's the red line on the chart there, and as I say, we'll have to do some more projects.

And as Alex mentioned, there's actually another component to this. It's a natural hedge to our business. So we spend quite a lot of our OpEx -- is on buying power. We have 15% of -- Johan Sverdrup OpEx is around 15% is power purchases and 10% to Edvard Grieg when we get there. So it's not an insignificant amount, and I think, balancing these 2 with generating power and buying power is a good natural hedge. And as I say, we need to spend around $250 million in total to achieve our goal of having 500 gigawatt hours of generation capacity, and we'll spend that money over the next 3 or 4 years, and these 2 projects will be spent between over 2020 and 2021.

So that sets the details of the actions that we're taking. And then, I have a chart to show what we get for this. So we are, I think, in an industry-leading position on carbon emissions. You can see how -- here our 2019 outcome, which is around 5 kilograms of CO2 per boe, and you can see that's about 1/4 of the world average. And then looking forward, it gets even better. We set out our guidance on this. So from this year onwards, for 2020 to 2022, we're guiding below 4 kilograms of CO2 per boe. And then when we've got our assets fully electrified from '23 onwards, to go below 2 kilograms of CO2 per boe. But we'll need to do some further investments to get to our target of carbon neutral by 2030. So you'll see us do some further offsetting projects to get there. But I think the set of activities we've got gets us a long way there. These are concrete activities that are happening and gets us a very long way there by 2023. And so we'll do some further actions, and I think, over the next year or so, I think, you'll probably see us do some things to move this forward and get us closer to the goal of carbon neutral.

So that's the final slide on this, and I look forward to answering your questions later, and I'm going to hand to my colleague, Teitur, who's going to talk you through the financials. Thank you.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [8]

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Thank you very much, Nick, and good morning, everyone. Who'd have thought a few years ago the financials would follow a decarbonization strategy, but that's a sign of the times, and I'll do my best not to get my EPS confused with the -- my ESGs.

So financial discipline. My presentation, it'll be a little bit backward-looking, given that we announced our Q4 results this morning. So we'll go through the key highlights of that. But then, perhaps, more importantly, there'll be quite a lot of forward guidance within my slides.

So looking at the key highlights for Q4. As announced this morning, we've been through the production numbers, you see them here, a very good performance. And in terms of Brent price, we had $64 for the full year, $63 for the fourth quarter. And as you will see a bit later, our realized oil prices have been extremely good, both for the full year and also for the quarter. We've realized prices above where the Brent price was. Also in the fourth quarter, you see here very clearly, the impact from Johan Sverdrup coming onstream, a big milestone for the company, of course. So driving down unit cost of $3.50 a barrel. And as Nick has already showed, that is industry-leading metrics by some distance.

And also record-generating EBITDA, $700 million; and for the full year, $1.9 billion. So we'll come back to that, but those are both record-setting numbers. Free cash flow, $155 million for the quarter. We had quite a large working capital build during the quarter, given the ramp-up of Johan Sverdrup. So if you exclude working capital, it would be $290 million for the quarter and $1.27 billion free cash flow for the full year, which obviously, includes a big contribution from Johan Sverdrup sale that we completed.

Net results and adjusted net results for the quarter, $155 million and just below $80 million with the adjusted net results, where we take out the one-off items. And for the full year, $825 million, also positively impacted by the sale of Johan Sverdrup and $255 million for the adjusted net results. So really across the board a very strong performance for the group, both in the quarter and for the full year.

Looking at fourth quarter and comparatives to last year, remember, this is the first quarter we're reporting on our reduced share count. As you know, we canceled 16% of our shares during the summer. So our per share metrics here are looking even more impressive than the absolute numbers. But just looking at the absolute numbers, you see realized sales price down 7% and the sales volume is up 50%. We had a little bit of inventory build in the fourth quarter, given that we were filling up the Johan Sverdrup pipeline. So that equated to around about 2,700 barrels a day of inventory build, which is why you see here, the sales volume was slightly lower than what we produced. And EBITDA generation on a per share basis is actually up 73% this quarter versus last quarter last year, with the absolute numbers up 45%.

As I said, free cash flow generation was also good, $155 million for the quarter, down 11% on last -- same quarter last year. But as I said, within that, there's $135 million working capital built. So if you add that back, we generated $290 million free cash flow generation in the quarter, which will be 73% up on the same free cash flow number fourth quarter last year. And then net results. There were a few one-off items here which impacted. We took an impairment on both Gohta and (inaudible) in the Barents Sea $128 million pre-tax. That's, of course, all non-cash. And we also had an FX gain, mostly non-cash as well, of $106 million.

But all in, $155 million as reported on the face of the P&L. And when you adjust for these one-off items to reflect the underlying operations, we generated $80 million of post-tax net profit.

And same story on the full year numbers. You can see EBITDA is relatively flat year-on-year. Price is down 10%, production up 11%. So it sort of cancels out. And internal free cash flow generation, $1.3 billion free cash flow, up 92% on free cash flow in '18. And of course, the sale of Johan Sverdrup impacted this number quite significantly, $959 million is what we cashed in, in proceeds from that sale. So if you take that out and look at the organic cash flow generation, if you like, we generated $312 million free cash flow, excluding our working capital with $193 million. So if you add that in, we were at over $500 million of organic free cash flow. So very strong free cash flow generation for the company.

And then full year net results numbers here, up 265%, actually on the '18 as profit of $825 million. And you see in the box to the right there, the one-off items we are adjusting for to get to the adjusted net result of $253 million.

I'll talk about realized oil prices. Our marketing department in Geneva is doing a great job in terms of marketing our crudes. We now, of course, have 3 blends to market, Johan Sverdrup and Grane blend where Edvard Grieg is a part of and the Alvheim blend as well. And you can see here in the fourth quarter, the top of this bar is the realized oil price we had on all our liftings in the quarter, just below $65 Brent realized price compared to Brent, as I said, of $63. And if you then add in the gas and NGLs we sold as well, our blended boe realized price is $60.75 for the quarter. As you can see, generally, the trend has been very good over the year. Out of the last 5 quarters, we've actually [achieved] a higher price than Brent in 3 of those quarters. So that has been very positive. And for the weighted average for the full year, you can see in the bullet point on the left there, $51 -- sorry, $0.51 a barrel premium to the average Brent for the year. And of course, it'll be also interesting now to see how Johan Sverdrup will trade longer term. It's still early days. The crude is sort of finding its place in the marketplace.

We have sold most cargoes off to China, whereas some have been sold within Europe. And I think in due course, some cargoes are going to go West as well, is our expectation.

On operating cost. As we have disclosed already, the unit costs are coming down. You can see the picture of the previous 4 quarters, a very stable operating cost there. So the operating team in Norway is doing a great job on keeping costs in control. And of course, when Johan Sverdrup comes on stream, you'll see an absolute increase in costs of around about $52 million for the quarter, but the unit costs keep coming down. So as we said, $3.54 for the quarter. And as you've seen already, our guidance for this year -- with a full year worth of -- with Johan Sverdrup contribution, we are estimating $3.40 for the full year. And that guidance is, by the way, based on all our cargoes being sold FOB, so free on board at the terminals in Norway. But there may be scenarios whereby we actually take on the tanker charter as well and deliver the crudes directly to our customers. And in that scenario, you would incur also the transportation costs of those cargoes. So that could impact the unit cost for us.

But similarly, it would also lead to a higher realized sales price. So it's a serious [long gain].

And then the buildup of the free cash flow. We talked about earlier for the full year, just over $1.55 billion of cash flow from operations before working capital, and we had a working capital build of $193 million during the year, and cash flows and investments amounted to just over $1.05 billion.

So that's where we get the free cash flow -- organic free cash flow generation of $312 million. So as we said, we sold 2.6% of Johan Sverdrup, $960 million are backed in proceeds from that. And during '19, we paid out 3 tranches of our 2018 dividend, amounting to $355 million in total, and we paid the fourth tranche out in early January.

So in total, for the year, we paid out $460 million in cash dividend during the year. And then the share redemption. We canceled 16% of our shares outstanding in August through the deal we did with Equinor. So that led to 1.5 -- just over $1.5 billion share purchase, which then were canceled. So we've been drawing on debt to fund these activities, $630 million during the year, and we've had a small cash -- net cash build of just below -- just below $20 million.

And then looking at comparison to what we guided upon this time last year in terms of the 2019 outlook. And you can see here, on all metrics, we've outperformed. As such, also been demonstrated by Alex and Nick already. Production up 10% on the midpoint guidance at Capital Markets Day. And EBITDA, although, oil prices are, obviously, up compared to our guidance, but even, allowing for that, our EBITDA is significantly up 18%. And also free cash flow up over 100% and over 260% to fee adjust for working capital build. And the cash OpEx, as we said, $4 a barrel. That actually includes $0.13 a barrel in transportation costs that I talked about. Some cargoes we lifted in '19 we actually delivered straight to our customers. So if you net that out to really get it on a like-for-like basis, our true costs were actually $3.90 for the full year. And then capital spend has fallen significantly, both because of a weaker NOK and also because of partial sale of Johan Sverdrup, but there's also been some good true savings in our capital expenditure.

And now we are moving into looking ahead and just to set the scene a little bit in terms of what we will be guiding on over the next few slides. You can see here cash funds from operations on top left. We are now focusing a $65 Brent, which is our budgeted price for 2020. We estimate to generate around about $2 billion of cash flows from operations. So a good increase on the 2019 number. And EBITDA is heading off to over $3.4 billion on this $65 Brent price. So also a very good increase on the previous 2 years.

In terms of free cash flow generation, again, I think we need to adjust for the sale of Johan Sverdrup. So as I said, it was $312 million in '19. And at $65 Brent, we expect to generate around about $670 million of free cash flow. I'll come back to the build-up of that number later and these numbers are all pre-dividend payments.

Dividend, to the bottom left. We have already announced a proposal this morning to be verified at the AGM at the end of March, but we are hiking dividend 22% up to $1.80 a share, which would equate to around about $510 million of absolute dividend payout for the year.

But before we get into the nitty gritties of the numbers, just to look at the financial model as we look at it internally. I mean, we've been through the portfolio and it's, as we've said, world-class assets performing really, really well and that is generally leading to an exceptional cash flow generation from the portfolio. I mean, we have our EBITDA margin of over 90%, with the low OpEx that we have. And most of the reserves are oil and good quality oil. We've seen the realized prices we get on that oil above Brent in most cases. And also now with Johan Sverdrup Phase 1 being onstream, most of our reserves are actually behind pipe and on production.

So when we look forward in terms of remaining CapEx, we need to incur to realize fully these 2P reserves we have. We only need to spend around about $3 a barrel, based on remaining CapEx, to produce the 690 million barrels of 2P reserves we have booked.

In terms of capital allocation, Alex touched upon it, and we'll come back to it, but we have very good flexibility around those items. Really what is locked in is the CapEx on the 2P profile relating to Edvard Grieg and Johan Sverdrup mostly. But other than that, we have very good flexibility on what sort of level of E&A we want to spend going forward. But on our planning assumptions, we're spending $250 million a year on E&A. On $65 Brent, we expect our net debt-to-EBITDA to come down below 1x by the end of 2021, and probably, edging towards 1.2x at the end of this year.

And the free cash flow generation, we will also come back later on in the presentation on what that picture looks like going forward. But at a high level, we can say that the portfolio will be cash flow breakeven at an average Brent price of around about $20 Brent from 2020 out to 2026. So obviously, with an OpEx number of $3.40 or there about only $3 per barrel on CapEx, you would expect a very low free cash flow breakeven number.

Dividends are very resilient, and we plan to sustain the dividend policy we've laid out, even if Brent price goes below $50 Brent. So there's ample scope to increase that dividend as we go forward. And also, remember, the Norwegian tax regime is such that we have a very good protection on downside in case oil prices fall, or similarly with the way the tax regime works, it's symmetric. So on the higher oil price -- the upside to the higher oil price is somewhat capped because of that tax regime.

So the key highlight number for us, for 2020, I've been through most of this already, but the cash flows from operations, as we said, $2 billion generation, which will be a record for the company. And as I alluded to, our net debt, we do anticipate to pay down debt as we go through 2020 and even more so from 2021 onwards.

Oil & Gas CapEx of $1.1 billion. We will come back to the makeup of that a bit later. And as Nick said, in 2020, renewable CapEx of $100 million, with some additional CapEx to come in 2021 on that as well.

So in our normal fashion, we give you quite a lot of netback guidance on the numbers themselves. I'll just focus on the mid-case here of $65 -- $65 Brent and with the revenue we expect to generate there per barrel will be just over $63.50, which includes the gas and NGLs. But with the Johan Sverdrup becoming a heavier component of the mix, there's very little gas in Johan Sverdrup stream. So that leads to a higher or a better realized price versus Brent compared to, for example, what we saw on our guidance last year. And you see the cash operating costs here. We've talked about the $3.40 a barrel. So that gives us a cash margin of just over $60 on a $65 Brent.

G&A continues to screen very low. Absolute numbers of around about $32 million in G&A for 2020. That's roughly the same number as we incurred in 2019. And I think, if you screen this on a per barrel metric, I think, we screen better than all of our peers in terms of having a very low G&A cost.

So EBITDA netback from that, just below $60, $59.54, which equates to an EBITDA margin of 94%. So fantastic margins on this and this will generate -- on the midpoint of our guidance of 155,000 barrels a day, this would generate $3.36 billion of EBITDA generation in 2020, assuming a Brent price of $65.

And then going further on, on the P&L and looking at the net profit itself. Our depletion rate is also coming down quite significantly. This time last year, we guided a depletion for '19 of over $14 a barrel. But clearly, with Johan Sverdrup now coming into the mix and with the low unit CapEx on Johan Sverdrup, that's dragging down the blended depletion rate for us. So it'll be below $11 a barrel during 2020 and going forward as well.

The G&A. We've talked about financial items, just over $4 a barrel. We will capitalize less of our interest costs going forward, given that Johan Sverdrup now is Phase 1 and Johan Sverdrup now is onstream. So more of our interest costs will now be charged directly to the P&L as opposed to being capitalized. And within the finance items as well, we are assuming our interest rate swaps are going to be slightly out of the money. So costing us $5 million. And also our FX hedges, we are budgeting on NOK/USD 8.75 exchange rate. And if that exchange rate holds true, then our hedges will be slightly out of the money for 2020 to the tune of minus $8 million.

For profit before tax, with those assumptions, $44.50. Tax -- as a team we will come back to a bit later, but we are going to incur a significantly higher current tax charge this year compared to what we did last year, given that now are out of all SPT and CT tax losses available to us in Norway. So just below $30 a barrel in current tax, and that equates to an absolute number of $1.7 billion of current tax. So that profile is changing dramatically as we go forward, but -- which we also have guided on previously. So it's not a surprise. So profit after tax with a total tax charge of $35.90 will lead to $8.61, which in absolute numbers is just below $500 million. And our guidance here is based on no impairment, further impairment charges or no exploration write-offs. So this will be a clean P&L without any of those more hard-to-forecast items impacting. And the current tax charge as a percentage of EBITDA, which is something we have guided on previously, at $65 Brent, it'll be around about 50%, which is in line with what we have previously guided for 2020 current tax.

So coming on to tax. As I said, we are out of tax losses in Norway, but we still have a material tax asset sitting on our balance sheet in terms of future depreciation against the tax base in Norway. So the value we have here on -- the tax value of this depreciation profiles amounts to $1.4 billion. When we showed this slide at this time last year, it was $2 billion, so -- which included the tax losses we had available at that point in time. But this is the reason effectively why our current tax charge is only 50% as opposed to closer to 78%, which is the marginal tax rate we have in Norway. It's because we still have certain tax shelters available in terms of depreciation schedules going forward.

And this is our other business line, but I think it's a very important one. So if we split this into 2 halves, the upper half and lower half. Looking at the upper half first. What you see here on top left is the total current tax charge we incurred in the income statement during 2019. And you can see, during the first 3 quarters, it was at relatively modest levels because we still had SPT tax losses available to us during those 3 quarters. But in the fourth quarter, we entered the fourth quarter with a net SPT tax loss of around about $60 million. So that was very quickly consumed by Johan Sverdrup volumes, which is why you then see a big hike in current tax charge in Q4, up to $325 million. So making the total current tax charge for '19 to $405 million.

So that is what we have recognized in the income statement. And then to the top right, you see the actual tax installments we've been making through 2019 and which we will be making in 2020. All these are now firm and locked in. So if you look at the dark purple pieces of the bars there, first, those are tax installments we made in 2019, which actually related to the current tax in 2018. And the light purple bars you see here are tax installments we made in 2019 and we'll be making in 2020 relating to the current tax charge from 2019 of $405 million.

And you'll see in our balance sheet statement, this morning, that we still have a tax payable of $345 million. So that means that out of the $405 million current tax charge, we've only paid $60 million of that during 2019 and the balance will then have to be paid in 2020. And those installments are now locked in. So independent of what oil prices do in 2020, those numbers will not change.

Then looking at the bottom half of this slide. This then is a forecast on what current tax charge we are likely to incur in 2020 based on the guidance you saw previously. And if you take the $65 case, in the bottom left, you will see that the total current tax charge will amount to roughly $1.7 billion, which will create roughly 50% of the EBITDA generation in 2020. And then in the bottom right, you will see what the tax installment phasing of that current tax charge will be. We will start making installments on that from the second half this year. So we will provide a projection to oil taxation office in the summer this year, where we are -- have a better idea of what the actual 2020 number will be, but this will at least give you an indication of what sort of quarterly tax installments we will make as we go through each quarter in 2020, and indeed, into first half of 2021 as well. So these numbers will then filter through in our cash flow statements as and when we report them when we go through the year.

In terms of debt and liquidity, we preannounced the net debt number at year-end '19 of $4 billion, but what we're also announcing this morning is that we have entered into an additional credit facility with SEB, effectively to fund our renewable business. It's a facility of $260 million. And it's effectively guaranteed by the company owning our oil and gas assets, and we are achieving our margin on that new facility of 1.25 basis points over LIBOR, so we're pleased with those margins.

But what you also see here on the top left is the available credit lines we have as we go through 2020. And as previously communicated, our RBL will start to amortize in the summer this year, initially by $250 million and then $750 million by year-end. Whilst the renewable facility will stay flat at $260 million during the year. And then on the right-hand side of the slide, you'll see our projected net debt-to-EBITDA metrics going forward.

As I said, on $65 Brent, we would expect to be around about 1.2x at year-end this year. And if you extrapolate that into 2021, we would expect to be potentially below 1x at the end of 2021. So these metrics are clearly heading towards investment-grade sort of territory. And in light of that, we are very likely to commence our refinancing exercise on the RBL at some point this year to take advantage of our improved credit metric outlook.

And then this is the final detailed slides on numbers, I promise. This is just to show what the liquidity position of the company will be given a $65 Brent case. I talked about the cash flows from operations round about $2 billion or $1.94 billion to be precise. And here, you have the capital items that we will incur during the year. Oil and gas, as we announced this morning, $895 million, $100 million from the renewables and $225 million on E&A . And then we have some decommissioning costs on both Brynhild and Gaupe, amounting to round about $50 million .

So the cash flow available for dividend payment based on these expenditure items will be $670 million. And on the dividend, we are guiding on -- or proposing to the AGM of $1.80 per share. That will amount to an absolute number $511 million, but because it's paid quarterly, the last quarterly payment of that dividend will fall into 2021. Whilst looking at 2020 liquidity, the last quarterly payment of the 2018 dividend will fall into 2020. So when you calculate the numbers here of $8.61, that equates to $485 million in dividends. And you can see on $50 Brent, we will be slightly cash flow negative post dividends, but still a very healthy number.

And you can see at the very bottom line here, even though we are losing some liquidity with the RBL amortizing, and this assumes no refinancing having happened, which is an unlikely scenario. But even if you assume that what this shows is that on all the scenarios, the company has full liquidity to execute on the [work] program and dividends during 2020.

On CapEx, 2020 will be the peak year of CapEx. And this is just modeled on our current 2P reserves. In addition to 100% of the hydropower -- sorry, 50% of the hydropower project we owned in Norway and assumed 50% of the MLK wind farm in Finland which, in total, will equate around about $160 million of renewable investment, of which $100 million will be spent in 2020. So you can see the split on 2020 expenditure and as has been the case over the last few years, it's dominated by Johan Sverdrup expenditure, around about 1/3 goes to that. And then there's a split between Edvard Grieg and Alvheim and then the renewables.

We also showed this graph this time last year. The total CapEx for the same period of time has increased slightly because last year, we had not clouded the infill wells on Edvard Grieg, whereas now we do include those wells since we have booked those -- the 2P reserves associated with those wells. And there's also some additional electrification costs on Edvard Grieg included now in this profile, whereas that was not included fully last year.

And as I said earlier, when you look at the cumulative spend here, it amounts to just over $2 billion. And when you then spread that across our 2P reserves, it's less than $3 a barrel of CapEx spend, so very low indeed.

The capital allocation, Alex touched upon this in the beginning. And as he said, 1/3 of it's -- around about 1/3 is allocated to future growth. The CapEx basically reflects the profile I showed you on the previous slide. So that's fairly locked in, but on the E&A metric, we are assuming $250 million of spend every year from 2020 to 2026.

But of course, there's plenty of flexibility around that assumption because we haven't locked anything in much beyond 2020. There is some drilling locked in for 2021, but beyond that, there's not much locked in. So we have good flexibility on that. And then you'll see the remaining 2/3 here are split between debt repayments and dividend repayments. And these -- this dividend is modeled on the assumption that we get approval for the $1.80 a share dividend. And what we're also assuming here that right out to 2026, we are increasing the dividend year-on-year, every year for over that period.

And this is then the free cash flow profile we generate from our 2P computer source profiles. As we have previously guided, around about $1 billion of free cash flow generation for these 8 years from '19 to 2026. Of course, on a per share basis, this is looking better than it did last year, given that we have counted 16% of shares outstanding. And what you also see here is the relatively good protection we have on the downside, even if prices average $50 Brent in 2020 numbers and escalating 2% over the period. We are still generating over $730 million on average per year in free cash flow generation.

These numbers are all pre-dividend payments. And at $80 Brent, you can see that we are over $1.11 -- $1.15 billion annually in free cash flow generation. So extremely strong solid free cash flow generation and which means that we are trading currently as a free cash flow yield of over 10%.

Alex showed this slide previously. It's just to remind you, the shareholder returns we have provided over the years, and we feel pretty proud about this, and with the dividends we have announced this morning, that trend is set to continue. But it's also to remind you on the right-hand side of this slide that we did cancel 16% of shares last year. So shares in circulation now is 285 million -- 285.9 million shares. We have 1.9 million shares still in treasury. So the shares that we have to pay dividend to will amount to 284 million shares. We're not paying dividends to ourselves. So it's just to keep these share count numbers in mind when you model forward on the portfolio.

So my last slide here, just a quick recap. As we said, it's a fantastic, high-quality portfolio, mostly good quality crude oil selling after above Brent prices. And that obviously generates significant free cash flow, and we have to delever the balance sheet as we go forward. And the dividend as announced this morning, 22% increase. And in our guidance, we are assuming year-on-year increase even from this level out, right out to 2026. And in terms of capital allocation, as I said, there's pretty good flexibility within how we want to look at that going forward.

But obviously, return to shareholders will be a key metric within that. So with that, I will hand back to Alex.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [9]

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Thanks. Okay. You've been very diligent. I'm sure you're very eager to ask a lot of questions. So I only have 2 slides. Just -- actually, you've seen this slide again. And just to recap on the 2020. I think you've seen all these numbers. I think, obviously, the highlight is going to be us achieving, Equinor to Equinor, the plateau production on Phase 1. That's going to be a key moment, of course. And also, in terms of productivity and capacity, there's quite a lot of moving parts in the [Johan] Sverdrup and also achieving good uptime in Edvard Grieg. So all this will be key events during the year. You've seen the low operating cost. We'll continue that trend. And certainly, with the Johan Sverdrup moving up towards the Phase I. And then on organic growth, I hope you had a feel through Per's presentations. We've been very active. A lot of work has been going on behind the scene.

And hope you're going to -- you will see -- I'm actually convinced myself that over the coming months, and certainly, this year, there's going to be some really interesting outcome out of all these activities. I think the carbonization strategy, Nick went through quite a lot into details. And obviously, if I do have a message, it's that in terms of dividend, our policy -- our strategy to have a sustainable dividend and growth over the years is definitely there to stay, and we feel even stronger today than we did certainly a year ago.

So really in terms of definitely long-term value creations, we've seen tremendous growth over the years until now and I'm certainly very excited and proud of what the team has put together in terms of what the vision is beyond -- now in the Johan Sverdrup era and also beyond Johan Sverdrup. We're guiding now our long-term guidance between 160, 170, which is higher than the guidance we gave you in excess of 150 despite the fact that we've sold 2.6% in Johan Sverdrup. We have a firm -- a very solid target to achieve over 200,000, you've heard from Nick. And that's really based on our existing assets and our current development assets. And long-term target in OpEx is not just last year or this year. It's in a long-term remaining between $3.20 and $4.20, which I think is key in terms of metrics to achieve good financial numbers, but it's also key in this -- will be very resilient to any changes on macroeconomics.

And $1 billion of free cash flow, you've heard from Teitur, so I won't go into too much details, but it's worth mentioning, above 10% yield, so really outstanding and also when it comes to dividend, I think in today's market, [capital] dividend is about 5.3%. And certainly, I'm convinced that these yields will strengthen and will continue to return cash to shareholders and yield higher -- high yields for the -- on the company.

Carbon neutral, we talked about it with a target of 2030. Again, I would like to emphasize the key pillar of this is really the electrification of the platforms. Once you got very low emissions, it's a lot easier to achieve carbon neutrality to than if you have to actually deal with a lot of winning of residual emissions and, of course, as I said before, safe and responsible. It's key to continue in a very sound business. So I think it's time for more, and I -- you take over the -- you take over from that.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [10]

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Thanks very much. Thanks very much. Can I ask the speakers to come up? And what we might do is we'll take -- what we will do, we'll take questions from the floor first. And then we'll take them from the phones, and then we'll take them from online. So we've got a roving mic around?

Right. Yes, should we start here?

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Questions and Answers

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Michael J Alsford, Citigroup Inc, Research Division - Director [1]

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Hello, everyone. It's Michael Alsford from Citi. Thanks for the presentations. I've got a couple of questions, if I could. Firstly, I guess, with new facilities coming online, and you talk about debottlenecking, I think, the average in industry as a standard is to target maybe 5%, maybe even 10% upside from those facilities.

I just wondered if you could put that into context, whether that's the potential from Johan Sverdrup? Or is that too big?

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [2]

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I mean I think it's a bit early days. I mean we need to drill the wells to get to plateau, which will come by the end of the summer, but during the summer. And we've got a couple of wells to go to get there. I think through that process, we'll be able to test the facilities and see the upsize. I said when I talked that I'm quite positive from what we've seen so far, but it's really a bit early to say. But there's definitely potential for some upside here. Just as we saw at Edvard Grieg when we were able to test the facility, and I think I feel quite positive that we'll see some. I don't want to go beyond that at this stage.

It's a bit early to really sort of give any sense of where it might go.

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Michael J Alsford, Citigroup Inc, Research Division - Director [3]

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All right. And then just a follow-up on the decarbonization strategy. Arguably, it's becoming a license to operate for the industry, particularly in Norway, to have a strategy around this. But I was wondering if you can talk a bit about in the context of the investments you're making around infill for Edvard Grieg, it's a 30% IRR. So what is a good economic return, Nick, that you mentioned earlier as to the sort of investments you're making to that area?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [4]

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Do you want to -- yes, and you're talking about the renewable investment, IRR.

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Michael J Alsford, Citigroup Inc, Research Division - Director [5]

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Yes, exactly.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [6]

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Well, first of all, it's not just a Norway issue. I think it's an issue that will -- that it's a global issue. And then I think this license to operate you mentioned, is going to be -- it will impact all oil and gas companies. So I think you need to be ahead of the game on that one. When it comes to IRR, of course, we're only going to invest in projects that have got good returns. And I think to give you an indication, good return for us means, on a leverage basis, double-digit rate of return. And that's what we're targeting. We will not go beyond that.

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Michael J Alsford, Citigroup Inc, Research Division - Director [7]

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Sorry, just one final one to finish off. So on the exploration portfolio, clearly, it's been a bit mixed this year in terms of -- sorry, 2019 has been mixed. And I'm just wondering whether you could elaborate a little bit more whether you're taking on more risk in terms of the drilling program. The company is getting bigger, are you targeting sort of higher risk prospects to try and refill the resource base?

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Per Øyvind Seljebotn;Reservoir Development Director, [8]

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I think that's not a sort of trend there. I think we did, also last year, drill a mix of some high risk and some low risk. I think maybe a couple of more targets on the low-risk side there, this year. I think, in general, we still maintain this mix of high-potential, high-risk in the undermature areas. Let's start with Anders and then go down.

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Anders Torgrim Holte, Kepler Cheuvreux, Research Division - Equity Research Analyst [9]

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Anders Holte from Kepler Cheuvreux. Thank you for a good presentation. Concise as always. Just if you could quantify a little bit, Nick, on the actual impact in terms of barrels for the Alvheim reduced output in 2020. And also the reserve replacement ratio that you touched upon is rightly going to become a bit of a larger challenge going forward as your production now increases. Now is there any chance that we will see Lundin Petroleum venturing outside Norway again? If the organic opportunity set does not improve during the year of 2020.

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [10]

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So I'll get the first one. I mean we are seeing some cutback in Q2 and Q3 from the terminals. We don't guide on an individual basis on individual fields. But it's not a huge component of Alvheim production that's been cut back.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [11]

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And then the question outside Norway. I think right now, I would say, clearly, our focus is Norway. I mean we feel there are plenty of opportunities in Norway. We still believe very strongly on the potential on the NCS. So you've seen our acreage position, growing quite substantially. You've seen our core areas growing substantially. And actually, also, we have to realize within the assets themselves, being Edvard Grieg and Johan Sverdrup and around those assets, we see also a lot of potential. So right now, we're very focused on Norway now. Never say never. There may be one day that we decide we want to go on the -- maybe outside Norway, but I would say this is not the case right now.

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Anders Torgrim Holte, Kepler Cheuvreux, Research Division - Equity Research Analyst [12]

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And finally, we have to talk about Johan Sverdrup just a tiny bit. You're now guiding on 2 new wells before you reach plateau, according to my watch here, it's 5 months away. Surely, you will reach that before end of Q2.

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Kristin Færøvik, Lundin Norway AS - MD and Director [13]

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We all know the first well of a brand-new drilling platform. So of course, it's taking some time to get to run in. But hopefully, that platform will perform as well as the other installations on Johan Sverdrup.

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Alwyn Thomas, Exane BNP Paribas, Research Division - Analyst of Oil and Gas [14]

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It's Alwyn here from Exane BNP Paribas. And just a couple of questions from me. Firstly, Nick, on the production slide you put out, there was a decent amount of headroom there on 3P reserves. I just wanted to clarify is that based on whether the facilities themselves have more uptime or possibly whether (inaudible) comes off where that relates to the gap there?

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [15]

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We don't include the gross in potential in there, but there's a range of -- there's a range of things that go into this uptime but also capacities, but also reserve range is in there. And overall, it's reserve range that drives this.

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Alwyn Thomas, Exane BNP Paribas, Research Division - Analyst of Oil and Gas [16]

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No, that's fine. What I meant was currently the capacity estimates are largely fixed and you're producing, let's say, you're producing your capacity level there for Grieg and, say, Sverdrup there. You've got a decent amount of headroom on that production guidance, which seems to have [kept you whole] for the next 2 to 3 years.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [17]

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Yes, I think it's on that slide.

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [18]

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Yes, that's correct. Yes. I mean a lot of this is around 3P reserves. So I mean less decline at Alvheim, less decline on Edvard Grieg and then upside capacity, potential capacity, at Johan Sverdrup and also of 3P resources there. So there's a range of things that make that up. And so we'll have to see where we get to. But I think there's a good sense that we've got the right things happening to see if we can realize those opportunities.

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Alwyn Thomas, Exane BNP Paribas, Research Division - Analyst of Oil and Gas [19]

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I guess just thinking a little bit more on capital allocation. It seems like the group is now a little bit more sort of steady state and capital allocation, you plan to grow the dividend going forward. Depending on exploration success, if you are perhaps less successful in finding, say, the next Edvard Grieg, would you consider other methods, either M&A or potentially even buybacks like you did last year as a potential means of changing the capital structure of the group?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [20]

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Yes. Buyback is not necessarily on the forefront of my mind. Now exploration. Of course, now certainly, this year, next year, we have a clear focus, and we have a clear plan, and I don't think this will change. But of course, as we go along, we have flexibility and we're only going to do invest and do things, which we really believe this will generate a good return to shareholders. So there may be a time when we will have to reconsider certain ratios. So that's an open question, I would say. For now, we still -- when it comes, really, to E&A, we think we've got a good balance. In actual fact or exploration spend this year is lower than what it was last year, if you look at it. And then it also depends if we are successful, and then we have to spend more in appraisal. So I think I'll leave it as a flexible approach. But of course, if days will go by, right now, we are in a free cash flow, that I tried to show you and there are an E&A spend of $250 million year after year for -- until 2026, if I'm correct. So that may change. But it's -- so we do keep our option open.

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Alwyn Thomas, Exane BNP Paribas, Research Division - Analyst of Oil and Gas [21]

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Okay. And one last tongue-in-cheek question from me here. You're making move into offshore wind or upstream wind -- onshore, actually, yes. Perhaps in our basis on a longer-term basis, something you might consider pushing harder into in the longer term, given the direction of travel at the moment?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [22]

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In terms of renewable?

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Alwyn Thomas, Exane BNP Paribas, Research Division - Analyst of Oil and Gas [23]

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Yes.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [24]

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Yes. No. I mean right now, it's very clear. I think we -- one of the reason we issued a press release last Monday was not to say, "Oh, all of a sudden, we're starting doing something here."

It's just withheld. We were doing a lot of things and we want to get clarity. And I think it's -- as I said all along, the electrification of the platform is #1 priority for us because the #1 priority is to reduce our emissions. Now the renewable is very much today linked to operations, which is -- we are conscious that we are using a lot of renewable energy to power both Edvard Grieg -- well, (inaudible) Sverdrup and then later on Edvard Grieg. And so we make the commitment that for net consumption, we will offset it with renewables. I would say, for now, this is the strategy.

And there's a business angle, as Nick mentioned, which is natural hedging. We're going to use a lot of electricity. And that's also our commitment to the fact that we realize that we're using a lot of this renewable energy. We would like to redistribute it to the network. But I think for now, that's where we stay.

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David Matthew Round, BMO Capital Markets Equity Research - Oil and Gas Research Analyst [25]

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David Round here from BMO. Sticking to the renewables, just quickly, are there opportunities to scale up the assets you've already acquired? Or are you reliant on going back to the market in order to let's say, fill the shortfall to get to the carbon neutral position? A slight follow-on there is just the rationale for farming down, just interested in the thoughts there when it looks like you're adding? And then maybe just on M&A, you say not a big focus right now, but presumably you are still screening assets. So just wondering if you're seeing anything interesting in terms of valuations for the cleaner barrels, which are obviously the ones you'd be after.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [26]

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Yes, I can take -- I mean, your first question is in terms of -- I guess, is, I guess, learning on the way and using the knowledge you've acquired by the, particularly, this MLK project. I mean we team up with the company called OX2, which is a Swedish company. And it's probably one of the best operators in Scandinavia. They're very active. And of course, as we move to these projects, we don't want to reinvent every time the wheel and if we think there's a very strong partnership, it's definitely something we want to piggyback on. And then with the aim to improve returns.

Now your second question is a good one because, actually, MLK, it's a good project, and we debated ourselves internally, if we should or should not farm out. I think we came to the conclusion that we wanted to spread the risk. And our objective to get to the 500 gigawatt hour, it's clear. But we thought, okay, we -- if we farm out 50%, and we partner with a strong partner in that, perhaps we can actually do other joint ventures together. One is we spread the risk and maybe that will allow us to even do a better project than the one we have today. So it's -- I would say it's a risk profile. And then your third question?

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David Matthew Round, BMO Capital Markets Equity Research - Oil and Gas Research Analyst [27]

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M&A.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [28]

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M&A, yes. M&A. No, I mean, let's be clear here. We have -- and Kristin can tell you, we have a team, a dedicated team in Norway. And we're actually very active ourselves.

But it is a dedicated team just that's turning every stone. I don't think there's a hidden stone in Norway in terms of what's available. And we go beyond what is on the market. We actually approach people that are not selling and of course, most of the time, they had to tell us not to -- we're not selling or they have high expectations. So we're very active. But I would say I will qualify this as an opportunistic approach. And -- but of course, if we can use it as a catalyst for organic growth, we will. And if the right opportunity comes, provided it has the right returns, we will definitely be active. And we've done a lot of things, but they are really under the radar screen because there were more like licenses. We entered into some other areas where we're drilling an [iron] appraisal well, where there was a discovery. But those are not big M&A deals. But if there is, one day -- and we have the means. So definitely, it was something we're very active.

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Al Stanton, RBC Capital Markets, Research Division - MD & Oil & Gas Equity Analyst [29]

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It's Al Stanton from RBC. Apologies for the simplification. But you're halving your carbon intensity, but you're doubling your output. So your emissions are unchanged. So in terms of your carbon offsetting, what costs are you associating with that in future? And is that reflected in the numbers?

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [30]

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Yes. I mean, I'd say, that's a good observation. But ultimately, we're going to be driving it down. And we're going to have to do some more offsetting to take it below the 2 kilograms down towards 0, and I think when you start to look at the things that you can do, the cost of offsetting that, I think, are relatively modest. We don't -- things like tree projects we can -- it's not a huge cost to see us get to carbon neutrality, and we're still thinking through how to get there and the right path to that. But we don't think it's a large number to achieve that.

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Al Stanton, RBC Capital Markets, Research Division - MD & Oil & Gas Equity Analyst [31]

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And just expansion on that. I mean I get it, it's a license to operate, but it's also a sort of voluntary carbon tax. So it's your argument, it's not a material impact on the numbers, but it is a work in progress.

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [32]

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Yes. Yes.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [33]

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If I may, I mean, it's also, internally, for us, it's the objective to be as efficient as one can be and a lower emission is part of that efficiency, and we will push our organization to actually find any possible ways to reduce those emissions at the lowest possible cost. And maybe in our benefit, particularly in Norway with the tax regime we are in. I mean the decision -- let's be clear, the decision we made to fully electrify Edvard Grieg was a business decision, it was improving the returns to shareholders by fully electrifying the platform.

So the objective, really, as I said, it's really to bring down to the lowest possible. I take it -- our volumes are increasing. And #1 is to really reduce our emission to the lowest possible and then we'll deal with the offsets for the remaining.

And as Nick said, even today, they're not -- by the time Edvard Grieg is electrified, there are no companies who will have such a low number. So it's a lot easier to approach the subject. And if you have standard, normal or low band, you've led to offset a lot more.

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James William Hosie, Barclays Bank PLC, Research Division - Research Analyst [34]

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It's James Hosie from Barclays. Just your capital allocation outlook to 2026 appears to suggest that you plan to pay down the vast majority of your debt in that time frame. So is becoming debt-free part of the longer-term strategy?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [35]

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No, that's not really the strategy, and that all depends on what your top number is in terms of cash flows from operations. So within our assumptions, we will still retain a fairly significant component of debt on the balance sheet, even by 2026, but still sort of staying within the onetime net debt-to-EBITDA ratio, although that's not an official sort of guidance we have given, but in the way the numbers are turning out, we will still save at 1x net debt to EBITDA.

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James William Hosie, Barclays Bank PLC, Research Division - Research Analyst [36]

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Okay. So I look at the slide. If you say your E&A spend is $250 million a year, that chunk is smaller than the debt repayment chunk, you're going down sort of at least below $1 billion net debt.

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [37]

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Yes, but we are $4 billion now. So this is nowhere near that level.

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James William Hosie, Barclays Bank PLC, Research Division - Research Analyst [38]

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Well, you'll be halving, at least, 2.

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [39]

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Yes, we will pay down debt, for sure. Yes, but not down to 0.

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James William Hosie, Barclays Bank PLC, Research Division - Research Analyst [40]

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Okay. And then the question on the -- your carbon neutral policy, does that in any way limit your opportunity set in terms of exploration going forward?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [41]

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No, the straight answer is no. I mean I think actually, organic growth fits very well that model because when you find your own resources you then, in care success case scenario, you will be able to use the latest technology. And you will always have to use what's best out there, so it will be the most efficient.

So in terms of organic growth, that strategy works really well. Then when it comes to M&A, if I -- when you talk about, let's say, mature assets, I said it all along last year and 2 years ago, the mature assets is not the forte of Lundin Petroleum and we -- that's an area where we're probably not going to focus. And that -- when it comes to carbon neutrality, [that also] is a problem. But that -- it was driven already years ago because we felt this was not our area of expertise.

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Robin Alfred Haworth, Stifel, Nicolaus & Company, Incorporated, Research Division - Director of European Oil & Gas and Research Analyst [42]

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It's Robin Haworth from Stifel. A couple, if I may. So just going into the refinancing you've guided to this year. How are you thinking about headroom versus interest cost? Or can you actually increase headroom and decrease cost with a de-risked Johan Sverdrup development?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [43]

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Yes. I mean the headroom we have at the moment is around about $1 billion of liquidity and in terms of the M&A strategy we have, we want to retain some flexibility on that front if we want to move quickly. So I think even though we are [rejecting] to repay debt gradually over the next few years, we will still size the new credit facility, such that we will have half a facility, and you pay some commitment fees on that, but normally, it's a very low option cost as we see it. And within the Norwegian tax regime, we can deduct most of those interest costs and commitment costs. So on a post-tax basis, that cost is not material in the big scheme of things.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [44]

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Let's be clear. I mean the refinancing, it is definitely to (inaudible) lower our cost. I hope there's not too many bankers out there.

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Robin Alfred Haworth, Stifel, Nicolaus & Company, Incorporated, Research Division - Director of European Oil & Gas and Research Analyst [45]

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And just a quick follow-up. Just on the graph where you show what power you'll be generating from your renewables business and what you will be needing. It looks like it goes up quite substantially in 2023. Sort of more than I'd expect from Johan Sverdrup Phase 2 coming online.

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [46]

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Well, there's just 2 things. We have 20% in Johan Sverdrup, and we get Phase 2 of Johan Sverdrup in 2022, '23, but also, we have 65% working interest in Edvard Grieg, which is also going to be a power from shore at the time. So it's that disproportionate increase in working interest, of course, to step up that much.

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Robin Alfred Haworth, Stifel, Nicolaus & Company, Incorporated, Research Division - Director of European Oil & Gas and Research Analyst [47]

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Got it. And just a final one. And it feels like you could sort of achieve your power generation or carbon offsetting requirements using financial investments. So other than the people, resources, capability, improving aspects of owning the assets directly, is there any other reason to own them directly rather than achieve those ends using some kind of financial structure?

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [48]

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Yes. I mean I think our point to that -- this is actually we wanted to take real action that actually had an impact. And that's why we wanted to have direct investments in some renewable power projects. Just putting some money into offsets didn't feel like the right way to go. We wanted to be able to say the money that we've invested actually has reduced the carbon footprint. And that's why we've taken that last step.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [49]

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As another thing to say, I mean, that the renewable will generate carbon certificates, which we could use.

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Duncan Gregor Milligan, Goldman Sachs Group Inc., Research Division - Equity Analyst [50]

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Duncan Milligan, Goldman Sachs. And just talking about the crude realizations in Q4, given that Johan Sverdrup starts it up and typically new crudes have a fairly meaningful discount most of the time to achieve meaningfully above Brent. Can you just talk about what drove that? And what kind of realizations you have seen in Sverdrup today?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [51]

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Yes. I don't want to go into specifics on exactly what we are selling each cargo for Johan Sverdrup. But just as a parallel when we started marketing the Edvard Grieg crude our first few cargoes sold at, I think, around about $4 discount to Brent. And then as IMO approached and certain issues in Europe, et cetera, we then started to get a premium on the Edvard Grieg crude and through most of '19, we've actually sold it over $1 premium. And when you look at the compounds of the Edvard Grieg crude versus Johan Sverdrup, they are not that different. So of course, it's higher volume, so Edvard Grieg, we mostly sell into Europe. JS will go globally. So there are different -- slightly different dynamics on that. And we need to factor in tanker freight rates, et cetera, which could impact positively or negatively depending on the tanker market. So there are quite a few moving parts in that. But so far, we've been very happy with the realized price we have achieved.

But I think it's still -- I mean, we see some refiners just buying cargoes, just to have a run of it, test it through their systems and that will probably take a few months before everyone has got comfortable, and then we will have more of a steady state, I think, on the pricing on that.

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Duncan Gregor Milligan, Goldman Sachs Group Inc., Research Division - Equity Analyst [52]

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And just a secondary on the Edvard Grieg area. Last year, you drilled a number of wells and found a lot of resource in the kind of surrounding zones. This year, there's a far more limited exploration campaign. Is this a function of the fact that plateau is now being extended so far. And so operating on a just-in-time basis isn't quite so urgent, whereas last year, there were some suggestions that there may come a plateau much earlier. Can you just talk about the -- where you see the kind of exploration strategy in Edvard Grieg? And then also if there are any parallels in Sverdrup?

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [53]

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I think there's a lot of factors that drive when you drill and -- on what you're going to drill in. This maturity of opportunity is getting partners on-site, it's license issues. So there's lots of factors that drive it. And it's not that we're not excited by the opportunities that we're only drilling one well. We have lots of opportunities, but we have to bring the work along. We have to bring our partners along. And then we have other opportunities, and we wish to balance the opportunities in other parts of Norway. And you can see that we've got Edvard Grieg full for some time. So actually, we don't need to find new opportunities today. I think we can wait and see how the current ones we've got will mature. And things like Solveig, for example, I mean, there's upside in there that we will test with the development wells on Solveig, which could potentially lead to further opportunities. The same goes for Rolvsnes, as we test that -- the extended well test, it will lead us to other things. So I think there's a range of factors that drive where we're at. And the reality is that we're going to be full on Edvard Grieg for some time. And so we can afford to pace our activity here to keep it full in the long term.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [54]

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That's the objective, to keep Edvard Grieg full as long -- for as long as possible and everything will turn around that ultimate strategy.

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James Thompson, JP Morgan Chase & Co, Research Division - Analyst [55]

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James Thompson from JP Morgan. Just got a couple, if I may. First of all, I'd like to just start with the wheel of cash that you showed, Teitur. And like James, I've kind of done a little bit of my analysis of it. And it looks to me like it's around about $12 billion of cash flow from operations over the next 7 years, which would imply a dividend of about $5 billion, $4.5 billion, $5 billion or $4 billion or $5 billion, something like that, which is actually a very meaningful increase in dividend. I know you said you're confident, Alex, in raising the dividend over the next few years, but that -- it implied some of these $600 million, $700 million on average for that time period, which I guess you won't commit to in terms of a number, obviously. But in terms of just what it's saying, it implies you're kind of focused more on capital returns than you are on growth now. Is that a fair conclusion?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [56]

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Well, not really. I mean, of course, we are very focused on capital discipline and free cash flow and redistributing cash to shareholders. We never made that a secret. I think that the 1/3, we dedicated to growth. If you look at it historically, it hasn't changed that much. And there's several things that have happened also. First of all, take the rig rates. I mean in 2012 or '11, where we're drilling wells in the Johan Sverdrup [and pairing] all this, we were spending 3x more money just on the rigs and really exploration is driven by rig rates. And so today, we're actually getting a lot more for the money we're spending. And if you look at our activities, historically, we were drilling -- I looked at it, in average, 3, 4, 5 exploration wells, and the number was skewed because we were drilling a lot of appraisal in Johan Sverdrup and they were all as one part of the exploration and appraisal.

In actual fact, the activity of last year, this year's are the highest activity we ever had in the history of the company. So I think it's not only because we're spending more money, actually, the opposite, but it's because we can get a lot more for a buck today. So I wouldn't say we're scaling back, and we still believe we strongly believe on the organic growth and the potential in Norway. But yes, I mean, there's definitely a focus also to reach good [cash] for shareholders, and we want this to be sustainable. The growth -- depends what growth means. The most important one for me is that whatever we say is sustainable, and we're never going to go back. And then how we -- how this is going to grow. I think there's several factors. One of them is also the oil price, of course.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [57]

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I think also within that calculation, you've got to remember the taxes you have in Norway, because even if you increase spend on CapEx or E&A, that feeds back into the cash flows from operations in terms of lower cash tax.

So you have to look at that on a more of a post-tax basis. So really, we can add quite a lot into both CapEx or E&A or take out and they won't really, materially, change the balance of that ratio of allocations.

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James Thompson, JP Morgan Chase & Co, Research Division - Analyst [58]

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And just sticking with that. In terms of the kind of growth and obviously, you focused a bit on 3P reserves, which is kind of the stuff you can going to go get. And I think there's reasonable visibility on that. Contingent resources, though, I mean it's kind of one of the things I'm worried about. If you ex out Alta/Gohta there's only a couple of years really of contingent resources on your 155,000 a day base. Is there a real urgency to build that now? Because otherwise, that 25 to 30 program becomes a little bit light.

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Per Øyvind Seljebotn;Reservoir Development Director, [59]

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I guess we've shown the exploration program and its mission is to try to fill in on contingent resources. I think we're active, and we're doing a lot there, and we're hoping for success. And it's, of course, a major task, and we didn't manage really to fill backfill last year, but it's the main focus, I think, everything else. I mean, this is very, very good. I would really like to be able to show backfilling on contingent resources and make that part successful and sustainable as well.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [60]

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Just, if I may, it's far from a lucky game. I mean the success in the Utsira High was very much into the vision and what Per shows or mentions, the ability to better view the subsurface. I think in my view, the next wave of discoveries, which will then move into prospective resources and eventually be contingent is going to be our ability to continue to be on the forefront and continuously improving the imaging of things because that will lead, in my view, into the next wave of discoveries. And there's plenty to find, but it's getting -- you'll have to be -- technologically, you have to be really on the forefront to really see things. There's still a lot of hidden things in the NCS.

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James Thompson, JP Morgan Chase & Co, Research Division - Analyst [61]

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Thanks, Alex. And just one more, if I may. And I'll pass it over. Nick, in your comments, I just wanted to understand, you're talking about Edvard Grieg reserves. And you made a comment about water [card], obviously, it's been very low, much lower than you expected. How much of a challenge is that to your reservoir model? And what do you kind of need to see to have kind of confidence moving forward? I mean is it the case that actually your EG numbers are fairly conservative because, actually, you don't fully understand this water cut still? Or is it a case that we just need to see it increasing and then refine it.

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [62]

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I think this is a trend. I mean we just have oil production today and we don't have much water. And until you know that it's going like this or like this, I think we need to see that. And once we get that, I think we'll be able to calibrate the models.

But the longer it goes on, actually, it's a good news. Because -- so it makes me feel more and more positive about it. And I think we're going to get some really interesting calibration points. The 4D seismic that we're going to shoot. We had really good results from a couple of years ago. I think we showed it and we had some really good results from that. We could see the movement in the flood front. And when you looked suppressed. And I think when we shoot it this summer, I think it will be really interesting, and we'll be able to calibrate the model to that. And then the infill wells we're drilling will also be useful calibration points and because we'll get some real data from the reservoir that's after production. So I think it's a little bit early, but the longer this goes on, it's really positive news, in my view.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [63]

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In other words, it's great to get it wrong every year.

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Sasikanth Chilukuru, Morgan Stanley, Research Division - Research Associate [64]

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It's Sasikanth from Morgan Stanley. I was just referring to this free cash flow projections that you have given now. You talk about or you base your cases on $65 oil, it seems to be a real price as well. Last year, you gave the projections on a $60 oil. I was just wondering, has there been any change in conviction probably what we've learned over the past 1 year? And so far as -- oil prices have been extremely volatile, I was just wondering, what the rationale was for this increase?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [65]

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No, I mean, the $65 really is really pinned on -- that's our budgeted price this year, and we are saying approximately $1 billion, clearly. There are a few things changed from last year. We did a big share buyback. Which was not embedded in the numbers this time last year. We've added some infill drilling. And we've added some CapEx with that. We've added a few other things as well. So the guidance is that the absolute number is still around about $1 billion. I think what you should look at is on the per share number with the 16% lower share count.

So that deal has been accretive in that sense in terms of profile and per share, free cash flow.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [66]

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Yes. So I guess, the inflation of the oil price for the year. So the -- what we showed last year.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [67]

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Yes. $65 [last year] is now, $61.

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Sasikanth Chilukuru, Morgan Stanley, Research Division - Research Associate [68]

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And related to the 2020 projection, the variance between 145 to 165. I was just wondering to achieve 165, what are the underlying conditions? Does it require Johan Sverdrup to produce more than its nameplate capacity of Phase 1?

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [69]

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Well, we've got a range of things in there. All the assets we have, we look at the range of uptime. We look at the range of potential shutdown times. We have capacity upsides in all of those. And we put all of that together. So it's not -- we have ranges on Edvard Grieg, Alvheim and Johan Sverdrup, which build into that. And we don't sort of show the details on that, but it's putting all of that together, ends up with that range.

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Mark Wilson, Jefferies LLC, Research Division - Oil and Gas Equity Analyst [70]

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Mark Wilson from Jefferies. I'd like to come back to the organic growth and exploration, which is your original calling card. And just dive into the exploration for 2020 outside of the Utsira High. It did sound to me very much like a portfolio approach. But you talked to your technology and the seismic. So I'd like to ask which of the projects you're targeting or the prospects do you think have the highest chance of geological success, which ones you're really looking to? And in parallel to that, I'd like to ask about the Barents campaign in the southwest. And are those prospects linked towards trying to build an Alta/Gohta hub development? Or are they stand-alone prospects on their own feet?

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Per Øyvind Seljebotn;Reservoir Development Director, [71]

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I think to answer the last question first, Alta/Gohta in the nearby area of Alta/Gohta, it's really just a successor bask that can really change Alta/Gohta in 2020 program, as it's only 30 kilometers away. When you look at the entire sort of frontier exploration portfolio, I'm not going to comment on the individual chances of success, they all got different elements to them. But I think they're sort of focused around -- and if you go Loppa High, the Bask, Polmak, it's in the areas where we've been active for a long time, and that's an idea that's been matured over large amounts of time. And looking at the Barents, the Loppa High really, has been proven to be the place to find big volumes, even though Alta/Gohta is a little bit small for stand-alone development. They are good discoveries. And you have the Johan Castberg there and so forth. So it's more of expanding that footprint, been active in the balance for a long time. And the Shenzhou is further north on a Loppa High, and we saw more sort of isolated down there. But it's a combination of growing where we're at, where we know things and then taking steps into other areas.

And I really don't have a favorite, yet. I only been in the job for 2 weeks. So I haven't really understood the details of all these prospects, to be honest.

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Mark Wilson, Jefferies LLC, Research Division - Oil and Gas Equity Analyst [72]

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Okay. And then can I ask on the renewables and the direct investments versus nondirect? Should we consider these direct investments come into the P&L down the line?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [73]

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No. We are under joint venture account, assuming we go down to 50% in MLK, it will be just an equity investment into those subsidiaries. So it will be a one-liner coming into our P&L.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [74]

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We've got any other questions on the floor? Yoann?

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Yoann Charenton, Societe Generale Cross Asset Research - Equity Analyst [75]

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Yoann Charenton from Societe Generale. I mean it's clear, you have not been shy in setting your carbon neutrality road map, which has to be praised. And at the same time, it looks like you're becoming more contrarian on the Barents Sea given the trend in that area from the rest of the industry or do you reconcile both angles? So basically, the share of the Barents Sea in your exploration program to this commitment to achieve carbon neutrality by 2030. And I guess, maintaining this beyond 2030.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [76]

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Yes, your question is how --

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Yoann Charenton, Societe Generale Cross Asset Research - Equity Analyst [77]

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Yes. Just simply how do you think about the Barents Sea in the context of this road map to carbon neutrality?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [78]

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I mean, first of all, for me, the Barents really is no -- I'm talking about the Southern Barents Sea now, in particular, the Loppa High, that area. It's no different from exploring elsewhere in terms of cost and facilities. There is 1 difference, you have to winterize the equipment during -- because of the cold temperature. But in general, there are no difference be the only, I would say, the only thing that we don't have in the Barents is we're not close to facilities. So you'll have to have a shuttle tanker, most likely a single shuttle tanker for development until we reach critical mass. But I -- we did -- we looked at -- it's not that we just pick up numbers. We looked at the sensitivities, if we -- let's say, we own 100% of Castberg and how would that impact or -- also a carbon footprint. And certainly also over the years, I mean, if we make a discovery today, by the time you use the latest technology, we bring this in production, it will take 6, 7 years in the Barents. And by then, I think also technology will improve, and we think it's absolutely feasible, and it's not contrarian to what we're trying to achieve.

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Yoann Charenton, Societe Generale Cross Asset Research - Equity Analyst [79]

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Okay. And maybe more on the financials and the dividend outlook.

It's clear that there is a quite an eye-catching step up this year in the dividend payments, and we are looking at a growth of more than 20%. And you presented, so again, sort of vision or, let's say, a sort of trend for cash flow going forward over the next few years. And you say that it builds in basically a growth in dividend. At the same time, you comment on your debt sort of management ambition, and with this ideas that you're [adding] toward investment grade. So at which point, basically, your balance sheet becomes a pillar for supporting this dividend growth?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [80]

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Well, I think -- I mean, it's the portfolio, which supports the dividend and the cash flow generation we have. So as I said, we do intend to retain debt on the balance sheet. Long term, that we will reduce our weighted average cost of capital as we see it. But because we are heading towards investment grade, and therefore, are going to achieve lower margins and also because of the Norwegian tax regime where you get good interest deductibility against tax. So for us, it makes sense to retain a level of debt and where it's headed at the moment is sort of below 1x net debt to EBITDA, as I said, but that depends on other opportunities we have within or without, outside the portfolio. So the net debt-to-EBITDA 1x is not a set in stone kind of ratio, but that's consequential to what the portfolio looks like today, but it may change going forward.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [81]

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Have we got any other questions on the floor? No.

Operator, have we got any questions from the lines?

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Operator [82]

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(Operator Instructions)

And we have no questions on the telephone lines at this time.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [83]

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Good. Thanks very much, operator.

We've got one question from the web, which goes into a little bit on the Sverdrup pricing. And is there a -- are we looking to get a premium for Sverdrup because of its carbon impact -- emissions?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [84]

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Well, I guess it's a very clean barrel as we've seen there. So who knows how that picture will evolve and there may come a point in time where barrels are certified as being greener than some other barrels, and that should [interior] be reflected in the pricing. But in the end, there will be a supply-demand equation that will set the pricing on that going forward.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [85]

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Okay. Thanks very much. So with that, we'll draw to an end. Thanks very much for attending from the lines, from the room and from the web. Those in the room, please join us for lunch. Thank you.