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Edited Transcript of LUPE.ST earnings conference call or presentation 2-May-19 7:00am GMT

Q1 2019 Lundin Petroleum AB Earnings Call

Stockholm May 13, 2019 (Thomson StreetEvents) -- Edited Transcript of Lundin Petroleum AB earnings conference call or presentation Thursday, May 2, 2019 at 7:00:00am 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

* Nicholas John Robert Walker

Lundin Petroleum AB (publ) - COO

* Teitur Poulsen

Lundin Petroleum AB (publ) - CFO

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Conference Call Participants

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* Alwyn Thomas

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

* Christopher Kuplent

BofA Merrill Lynch, Research Division - Head of European Energy Equity Research

* 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

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Presentation

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Operator [1]

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Hello everyone, and welcome to the Lundin Petroleum Interim Report January to March 2019. (Operator Instructions) I will now hand over to VP of Investor Relations, Edward Westropp. Please go ahead.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [2]

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Thanks very much. Welcome, everyone, to the Q1 2019 audio cast. For the normal forum, Alex Schneiter will take you through the highlights and operations, and then he'll hand over to Teitur Polson to take you through the financials, and Alex will summarize at the end, followed by questions. So without further ado, I'll hand over to Alex.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [3]

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Yes. Thank you, Ed, and good morning, everybody. Very happy to be here at this -- for the first quarter. Another strong quarter for Lundin Petroleum, very much led also by the continued outperformance of Edvard Grieg and also you will see later in my presentation, great progress on our new projects. And of course, Johan Sverdrup also progressing very well and as expected.

So starting with Slide 2. As we stated on the press release this morning, we are on the upper end of our guidance range, close to 79,000 barrels of oil equivalent per day. This was very much led by the Edvard Grieg performance and a very, very good uptime. We continue to provide low operating costs. We were just below our forecast at 4.6 -- USD 4.5 per barrel equivalent. And of course, the high production and low operating cost has given some, again, strong financial numbers. We generated close to USD 96 million of free cash flow. And as you all know, during the last AGM, $500 million of dividend was approved, dividend that we will pay on a quarterly basis. Johan Sverdrup, it's fair to say that Equinor is doing a really good job. We are now on track to achieve November 1 oil, and we are Phase 1 is now over, 85% complete. And very pleased with installation, which is now completed and all the modules, all the bridges are installed, that was achieved by end of March.

I think what is also important is the new projects. Since the last Capital Market Day, where we have provided -- we presented 7 potential new projects for new development. We, since have moved on a very satisfactory with 4 projects underway and 3 will be going through an appraisal. So very pleased with the progress on these new project. And then on the exploration side, it's fair to say that the second and third quarter will enter the most active period of this year in exploration. We've already drilled 4 wells in Q1, 1 discovery and -- but we would like 13 more wells to go. And as you've seen in the press release, we've had 2 new exploration wells. Moving on to the next slide. I think I talked about the production. I think the 2 items in this slide I would like to highlight. Number one is the guidance. Of course, the guidance between 75,000 to 95,000 barrels of oil equivalent is very much driven by Johan Sverdrup first oil. And the range is very much driven by the -- either the stretch target of early October or more production in Johan Sverdrup this year. And that's really what's driven our guidance in production. But as I said before, I feel very comfortable that the most likely November date will be achieved. The second point I'd like to make is the -- this is the 15th quarter in a row that actually we are delivering guidance at guidance. So really pleased with the performance of the team and of course led particularly by Edvard Grieg.

On the next page, in terms of industry-leading operating performance, it's fair to say that this has been a very good quarter. If you look at Edvard Grieg, uptime of production efficiency, 99% and Alvheim 97%. Those are definitely leading industry numbers. As I mentioned, also operating costs are up $4.5 and is still trending on track for the full year guidance at $4.25. And over the long run, as we presented at the Capital Market Day, we still anticipate a range between USD 3.2 to USD 4.2 per BOE. So very, very pleased with where the company is in terms of operating cost and also in the long term.

I think also importantly, not only we have low operating cost and high efficiency, but we're also very efficient in terms of carbon intensity. Edvard Grieg for the quarter actually achieved 1/4 of the world average. And we all know that this number, by the time Johan Sverdrup comes onstream, will go even lower, so achieving world-class carbon intensity emission. So very pleased also with that.

On the next page, it's more our focus on Edvard Grieg. And several things are happening in Edvard Grieg. Number one, we obviously continue to see high performance in the reservoirs. And it's fair to say that's still exceeding expectations. And that's very much driven by the fact that we still see very limited water production.

We're also now committed to our infill drilling program. We have sanctioned it. We've actually committed to the rig and this will be a 3 -- a minimum of 3 firm infill wells targeting 60 million barrels of oil equivalent, and those wells will be drilled in 2020. And by Q3 2019, we will firm up the locations. But I'm very confident that at the minimum, we will be drilling 3 infill well and possibly more. And really, my view is that Edvard Grieg, it's slowly but surely moving towards that field of over 300 million barrels of oil from the outperformance of the reservoir and infill drilling program, and also the updated model that is currently ongoing. So I'm very optimistic about Edvard Grieg.

And I guess beyond Edvard Grieg itself, we see the area growth opportunities. And I'm thinking that obviously Solveig Phase 1 and Rolvsnes extended well tests. Both of them have been submitted for final sanction. We submitted the plan of development last month in Solveig, and also for the Rolvsnes, we had submitted the plan for the external well cap.

And also, so both of them will be tied into Edvard Grieg. And in addition, we also are drilling several wells, Jorvik/Tellus, which is the northern extension of Edvard Grieg, and those -- this is ongoing and we should have results soon. And we're also going to drill the Goddo exploration well, which is really an extension of the Rolvsnes discovery in the basement and towards further north, Lille Prinsen, which is a discovery which will be appraised. So a lot of activity around the Edvard Grieg area. And not only Edvard Grieg is growing in itself, but we also see a lot of opportunities to extend the production platform of Edvard Grieg by filling in the capacity for as long as possible.

The next page is really a zoom towards the Solveig project, which we anticipate to have the sanction of the PDO in the second quarter of '19. The picture really show there the subsea tied back to the Edvard Grieg platform. Solveig Phase 1 will consist of 3 producers and 3 injectors. And you see, it's a little bit further north, the Rolvsnes subsea tied back into the platform. Significant resources, Solveig Phase 1 is 40 to 100 million barrels of oil equivalent. And the Rolvsnes, and assume a Goddo success, has a resource potential over 250 million. So those 2 alone actually can make up, on a gross basis, another Edvard Grieg. And I'm very pleased with the progress. And we anticipated first oil on Solveig in early 2021 and then followed by the Rolvsnes expanded well test.

Moving onto Alvheim on the next page. Alvheim has been, it's fair to say, Aker BP as an operator, do an excellent job. In terms of production, very good uptime. And of course, across 4D seismic, the main game plan was to do infill drilling and continue to address the decline and that's been done very successfully. We just completed an infill well, the Goddo infill, which will start coming production on the second quarter of '19. But we continue to see good performance on the field. The second story really on Alvheim has been the Frosk area. We've seen a field discovery last year, the Frosk discovery, between 30 to 60 million barrels of oil equivalent. And that was followed early this year by the -- a new discovery called Froskelår. And that whole area on Frosk, Froskelår including Rumpetroll, which will be drilled later this year, has really the potential to exceed 200 million barrels of oil equivalent. And a lot of activity ongoing. As you also know, we will be putting one of the Frosk well into an extended well test this year already. And so very pleased that after 10 years, we still find quite significant resources in the Alvheim area.

Moving onto Johan Sverdrup. I think the key numbers that you see on the slide are very well-known by all of you. And perhaps to repeat that at the time when Phase 1 will be up and running, we will reach a plateau production of 440,000 barrels of oil per day and with the full field at 660,000. I think one thing I would like to emphasize is that actually the picture you see here, it's a real picture. It's not anymore a design. And you will see how Johan Sverdrup looks today and so the oil installation is completed. It was completed very successfully towards the end of March. So right now really there are 2 things mainly to achieve is the commissioning phase to get this to first oil and the completion of the existing wells. But very, very pleased with the progress and Equinor has done an excellent job. So we are fairly on track to achieve the November 1 oil date. Cost wise, we're currently at NOK 86 billion for Phase 1. But I anticipate it will continue to perform, as we perform that there is room to further reduce the cost in Phase 1. The second -- the next slide is really showing you the timing in terms of first oil. So the hook-up and commissioning, as I mentioned to bring us the first oil in November 2019. By then also tying back all the existing 8 wells that were predrilled. And by the end of this year, most of the wells, the 8 wells predrilled will be commissioned, hook-up and producing. And then to reach plateau, we will need some 2 to 4 new wells to reach the 440,000 barrels of oil per day, but very pleased with the progress to-date.

In terms of pipeline of new project, I'm really pleased with the progress. If you think back in end of January when we presented to you the new projects, we talked about 7 new projects. And today, out of the 7, 4 are now very committed. Solveig, PDO submitted; the Rolvsnes extended well test has been sanctioned, we have also committed to rig to do the infill drilling. And Frosk, we already see that the first discovery in Frosk will be tieback and will be on the production test this year already. So 4 out of 7 well on track to be executed. And then we have 3 remaining, which is the Lille Prinsen, which will go through an appraisal phase this year; and Gekko also; and then the Alta/Gohta, which now we see an appraisal in early 2020. But -- and this is really -- those 7 projects with the Johan Sverdrup is what is going to take us in excess of 200,000 barrels oil per day by 2023. But very pleased with the progress the team has made today. Finally, on the exploration side, you see the sequence of the well. We have 13 explorations remaining. We've added 2 new wells that you can see here in the slide in Q4. But as you can see on the slide, really Q2 will be the most busiest time of the company in terms of exploration. Q1, we drilled 4 wells, we made 1 discovery and -- but is -- so pleased with that discovery. And now we're currently drilling Jorvik/Tellus and Froskelår North. And we also -- the Vinstra/Otta is ongoing and then moving on towards the other wells. Mostly in the North Sea area, mostly in trend with the Utsira High Area or closer to the Alvheim area. So essentially a really, really exciting period coming ahead of us. So with this, I think I pass onto Teitur, who will present the financial highlights for the first quarter. So over to you, Teitur.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [4]

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Okay, thank you, Alex, and good morning to everybody. Yes, so as Alex says, I will run through the key highlights for the fourth quarter in terms of the financial performance of the company. And I think we can characterize on this very robust set of financial numbers, really continuing the good trend that we've seen through 2018. So the key highlight numbers on this page. Production we've been through already ahead of guidance 78,800 for the quarter. Brent prices, as we know, have recovered as we've gone through the quarter. So the average was $63 a barrel. And actually we will touch upon that later in the presentation, but our realized oil price has been really good in the quarter. That has been very pleasing. Cash operating cost continues to be extremely low, and we even came in below our forecast, 5% below at $4.51. We will come back on that number later in the presentation as well. So this generated operating cash flow and EBITDA of $385 million and $406 million, respectively. Also we had a strong free cash flow number in the quarter of close to $100 million, and [$96 million reported] and a net profit after tax of just below $55 million.

If we then go to the next slide and look at EBITDA and operating cash flow compared to the same period last year. You can see here EBITDA, starting with that $406 million is down around about 11% on Q1 last year, and there's really 2 drivers for that. One is that our realized hydrocarbon price was roughly 6% lower than Q1 last year and production is down 5% compared to the same period last year. The Edvard Grieg is running relatively flat, so this is a slight decline on the Alvheim hub assets.

In terms of operating cash flow, as I said, $385 million in the quarter. That's down 17%, so slightly more than EBITDA. And the reason for that is that we have accrued for a current tax charge in Q1 this year of $26 million versus Q1 last year, where we effectively had 0 current tax as we had the corporation tax losses in Norway available this time last year. Whereas where we sit today, we only have tax losses available at the SPT level was at corporation tax (inaudible) utilize our tax loss (inaudible) last year.

If we then go to the next slide, looking at free cash flow and the net result. The free cash flow number is down, sort of 44% on Q1 last year. You can see in the table above here the cash flow we generated from operating activities was $345 million, which includes our working capital build of $20 million. And then we had cash flow from investing activities of $260 million in the quarter, $160-odd million on CapEx and the remaining spend was on -- an expenditure.

The net result, this time last year, we had a big non-cash FX gain, which filtered through onto our net profit in Q1 '18 of $160-odd million; whereas in the quarter this year, we effectively had 0 FX gain or less than $1 million of FX gain. So this obviously skewed the headline numbers on total net profit. But if we then adjust for these non-cash FX swings which arise through our Dutch financing structure, then our underlying net profit is down 19% at just below $55 million compared to $67 million in the same period last year. So the main driver for that is, of course, a slightly lower oil price and a slightly lower production volume.

Then going to the next slide and just going through the line items on the income statement itself. These numbers exclude the third-party revenue and costs that we already have announced to the market of around about $40 million of revenue and cost of sales, so no margin on the third-party marketing activities in the quarter. But looking at the headline numbers, excluding the third-party marketing, we generated around about $450 million of revenue and have a realized oil price of $60.88 per BOE equivalent. Production cost of just above $40 million, so this generates a very healthy cash margin of over 90%. Depletion was just below $100 million, which equates to around about $14 a barrel, which is below what we have guided. And the main reason for that is the we have seen a weaker NOK in the quarter compared to what we based our guidance on. We -- our guidance is based on NOK 8 (inaudible) quarters we had (inaudible) so that drove down the unit [expectation] rate in dollar terms.

Exploration costs of just over $37 million pretax. This was also preannounced to the market, and that gave us a gross result of $274 million. G&A is trending very much in line with the guidance and what we would expect, just over $7 million, and net financial items of $31 million. We had around about $8 million gain on our interest rate swaps, so that contributed positively to the financial items. So as I said, $31 million of net (inaudible). The tax rate on the face of the income statement came out at 77%, which is in line with what we have guided at Capital Markets Day on these oil prices, so that triggered a total tax charge of $181 million, of which, as I said earlier, $26 million is current tax charge and the remaining balance is then a deferred tax charge. And this then gives us a net profit after tax of $55 million.

I mentioned in my intro that we had a very good oil price realization during the quarter, and that's what you see on this slide. But just to get your eye in, the bar is what we have actually realized in oil price over the quarter, and horizontal stipulated line is the average Brent price in the same quarter. So you can see that our realized oil price here is actually above the average Brent price at $64.78, and this has really been driven by a number of things. We've seen the usual discount on the Grane blend, which Edvard Grieg produces into has narrowed over the quarter. Globally, we have seen supply disruptions on the heavier crudes around the world, be it in the Middle East or Venezuela. And that really is creating more demand for our Grane blend, which has allowed us to narrow the discount to Brent. And in fact, this is the trend that we have seen also come into Q2 so far. So that is a positive development for us. We were also for Q2, in terms of the timing of our liftings through the quarter, each lifting is priced over the 5 days following the lifting itself. So you're always subject to when in the quarter you have your liftings. We had 3 Edvard Grieg liftings in the quarter. And as I said, that contributed also positively to the realized oil price. And the third point to mention here is that we have changed our sales arrangement on the Alvheim crude so that we are now pricing the Alvheim crude at the refinery as opposed to free on board at -- out at the FPSO. So what that does is it increases our realized oil price, but it also increases our tariff and transportation costs. So net-net, that comes out in a wash. But when we report headline numbers on realized oil price, it helps our numbers somewhat. And when we then add in the NGLs, liftings and the gas we produced in the quarter, our blended BOE price came in at $60.88 (inaudible).

On the operating cost side, things are running very stable here, I will say. You see the base OpEx, the dark green part of the bar here, around about $25 million of costs we incurred as space operating costs, which is very much in line with what we have seen in previous quarters except for Q2 in '18 when we had this Brynhild reversal impact, but generally running as we would expect. And similarly on OpEx projects, around about [$38 million]. But we have seen a slight increase here in tariff costs and the one reason behind that is this change in Alvheim sales arrangement, as I touched upon on the previous slide. But we have also seen a slight increase in cost on the Sture oil terminal where we produce the Edvard Grieg volume into. So that's something we're looking at to see the net impact of that going forward. Then looking at cash flow generation. As I said, we had a very strong quarter of free cash flow generation of just below $96 million. We paid down debt of around about $71 million and had a cash build of $25 million. So that left us with a net debt position at the end of the quarter of $3.3 million. This excludes any IFRS 16 impact. But as you can see on the footnote here, the impact from IFRS 16 for our numbers at the moment is very minimal, only $36 million, which effectively relates to the office lease we have in Oslo for our office in Oslo. So it's a minor item of $36 million in the context of our balance sheet of over $6 billion. So this net debt gives us an available liquidity headroom of 2 -- sorry, $1.7 billion, given our facility size of $5 billion. So we continue to have ample headroom in terms of any funding needs we should have going forward.

Just a recap on guidance, there's no news here really. This is all just reiterating what we guided at Capital Market Day earlier in the year, 75,000 to 95,000 barrels oil equivalent per day is the guidance and that's very much driven by the Johan Sverdrup startup. Midpoint of that guidance, as we said, is based on startup in November of Johan Sverdrup. Our operating cost, you saw we reported 5 -- the $4.50 in the quarter, whilst our full year guidance remains at $4.25. So there's various phasing items within our operating cost in Q1. And of course, also with Johan Sverdrup starting up in the fourth quarter, that will help to drive down the full year average cost for us as well. And CapEx and E&A remains also unchanged at $930 million and $300 million for the full year, respectively. And my final slide is on the dividends. We had the -- we guided on the dividend at the Capital Markets Day of $500 million and the AGM approved that towards the end of March. And in fact, we have already paid out the first quarterly installment on the 5th of April, as you can see in this table. And just to remind everybody, that dividend (inaudible) has been set in the context of the company forecast to generate $1 billion of free cash flow pre-dividend for the next 8 years at $60 Brent. And we have communicated that the $500 million dividend is sustainable even below a $50 long-term Brent price. And given the conservatism within that 50% payout ratio free cash flow, we feel we have ample room to grow this dividend over time.

So with that, that concludes my presentation and I'll hand back to Alex for final remarks. Thank you.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [5]

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Yes, thank you, Teitur. Really, 1 slide and just to reiterate our key messages in terms of the company. Leading production growth trajectory, absolutely by the -- once Phase 1 is up and running, to remind you, we will be exceeding 150,000 barrels of oil per day. And by the time Phase 2 will be completed, we will be reaching in excess of 170,000 barrels per day. This gives us a compound annual growth rate of 20% from 2018. So and we are well on track to achieve that. In terms of the growth strategy, we talked about the 7 projects and 4 already committed and moving very well and very satisfactory. And this will allow us to exceed over 200,000 barrels oil per day by 2023. In terms of the long-term free cash flow, as we mentioned already at the Capital Market Day, so from 2019 to 2026, the company at $60 will be generating $1 billion of free cash flow, and that includes an average forecast of $250 million of exploration appraisal spend. And obviously, that leads to the sustainable, as Teitur just mentioned, and dividend, which we are aiming to actually increase over the year. We started today this year with $500 million set on a quarterly basis. And the aim is, obviously as the markets stays and the current environment stays as it is, to increase the dividend over time. And finally, obviously excellent production, excellent performance, and this, along with the excellent industry-leading low carbon footprint, well below the world average. And this number will only improve by the time Johan Sverdrup will come onstream, which Johan Sverdrup alone will emit less than 1 kilogram of CO2 per barrel produced, which will be over 20x lower than world average. So very pleased also with that number. So overall, really on track and very pleased with the progress the company is making and also very pleased with the major project, Johan Sverdrup.

So with that, I will leave it to the operator to -- for any questions. So over to you, operator.

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Questions and Answers

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Operator [1]

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(Operator Instructions) And the first question is from the line of Sasikanth Chilukuru from Morgan Stanley.

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Sasikanth Chilukuru, Morgan Stanley, Research Division - Research Associate [2]

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This is Sasi from Morgan Stanley. I had 3 questions, please. Just first thing on the deferral of the appraisal well in Alta/Gohta, I was just wondering if you could provide more color as to what is the reason behind that? You kind of mentioned there's some additional time to complete technical work. But I was just wondering whether this was any deflection on the feasibility of the project or the timeline? I do see that you have not changed the timeline until 2025 start up at somewhere around that. Some color on that would be helpful. The second one, it seems like on the guidance, you kind of left everything unchanged. I just wanted to check whether your current tax guidance for 2019, that was left unchanged as well, 4% in a $60 oil environment and 14% in $75 environment? And finally regarding the wells -- the exploration wells in Vinstra/Otta and JK, just wondering if there was any specific timeline as to when we can expect that result?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [3]

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Yes. Okay, I take the first question and last question and I'll let Teitur take the second question. Your first question is regarding the deferral of Alta/Gohta. No, really nothing has changed since we presented at Capital Market Day. I would say it's more an opportunity. As we stated at the Capital Market Day, we had a lot of data to digest there, particularly after we shut this top size, and incorporating all the knowledge and the information. So there have been no changes from that thinking. The only thing came is that we have this opportunity to drill these 2 extra wells -- exploration wells, which are operated by ConocoPhillips and that pushed back by 2 wells, so to speak, the Alta/Gohta, but nothing fundamental. It's purely an opportunity we took, and also that's giving us slightly more time to finish all the work. But no changes whatsoever since we presented to the Capital Market Day. So we're moving towards this project, but of course, we have a lot of data to digest. So that's the -- I would say, the main reasons.

On the second question maybe, Teitur, I'll leave it to you.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [4]

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Yes. So on your question on current tax guidance. So what we have guided is at, we have $60 guided current tax to equate to roughly 4% of the EBITDA generation for the full year. And if you look in Q1, our current tax was around about $26 million, which is 6% of the EBITDA generation, so slightly higher. But that's driven because by the fact that we have lower OpEx in the quarter than we had forecast, and it's also driven by the fact that Brent has been slightly higher than $60, it's been $63. And on top of that, as I said, our realized oil price has been better than we had forecast in our guidance. We had assumed a $1.25 discount to Brent on our Edvard Grieg volume, whereas in the quarter, we actually realized only $0.35 discount to the Brent price. So there are a few moving things there, but we're roughly still in line, 6% of EBITDA versus 4%, is not a big variance.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [5]

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Yes, yes. And I think your third question, I think I picked up the name. I wasn't -- the line was a bit difficult, but I understand you were looking at the timing for the Vinstra and Otta exploration well, which is ongoing. And that really, we should see results towards the end of second quarter. And before that, obviously we're going to expect the result of Jorvik/Tellus, and then at the same, then later on moving to Goddo.

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Operator [6]

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The next question comes from Alwyn Thomas from Exane BNP.

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Alwyn Thomas, Exane BNP Paribas, Research Division - Analyst of Oil and Gas [7]

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Couple of quick questions for me. Firstly, on Edvard Grieg and the infill drilling. Is this more targeting the sort of 3P reserves now? And perhaps are you able to give a little bit more color on whether you just plan to keep infill drilling progress continuing really in conjunction with the projects around the Edvard Grieg field? And secondly, I'd quite like to ask just for an update on Johan Sverdrup Phase 2, if I could, what you're seeing there and maybe overlap that with what's happening at Phase 1 as well.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [8]

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Yes. So question number one, Edvard Grieg infill. I think currently, as we've stated, we have committed to the rig. Currently, the firm program, it's 3 infill. But we have the optionality to decrease the infill drilling to more than 3 wells if we wish so, that's something we will define at a later stage. But the 3 infill wells in terms of giving a little bit more color, we are targeting net-net now $60 million barrels of oil equivalent. And as I stated, we plan to drill those wells towards mid of 2020. But of course, as we complete all the work, until we shuttle our 4D seismic over the field, which is very, very high-quality, we're currently digesting all this data. That will allow us, first step, is to define the 3 infill targets. And if we see more opportunity, of course, we want to look at it. And we have the flexibility on the rig side and also in terms of equipment to go beyond that if we wish to do so. But it's work ongoing. So for now, that's why we stayed with 3 infill wells. But of course, we've seen Edvard Grieg performing over every year and over every quarter, so it's fair to say that we see quite a lot of opportunity in the Edvard Grieg. The second thing also to keep in mind is that we're currently drilling Jorvik and Tellus fields, which is really the northern extension of Edvard Grieg. And what we hope, obviously, is to see that both Jorvik and later Tellus fields are connected with the Edvard Grieg field, for which we know, obviously, there are not currently [they're not in order of] 2P resources. And so in terms of the Edvard Grieg that's what I say. I'm very confident that Edvard Grieg will exceed 300 million barrels of oil because of the current performance of the field, the infill drilling that is coming and also the exploration for the new [offices] of Tellus and Jorvik. And then I think you mentioned the tie ins. As I mentioned, those are really 2 things going in parallel. One is the field itself and really optimize as much as possible the field and recovery. And the second one is obviously to keep that capacity full for as long as possible. And because eventually Edvard Grieg will go in decline and -- also, which we will provide services for. So we need to preempt that and find other candidates such as -- and this is why we are moving now with Solveig and Rolvsnes and potentially Lille Prinsen. So but overall it's a very, very, very good picture for Edvard Grieg.

The second question is on Phase 2 on the Johan Sverdrup. I think we are on the early stage. We, as you know, we submitted the Plan of Development for Phase 2. But the Phase 2, we already sanctioned or awarded the key contract. And I think it's fair to say today the project is going according to plan. So very pleased with that, but we are really on the early stage. And it is anticipated that Phase 2 will come onstream towards the second part of 2022. And Phase 1, as I mentioned, I think that people need to realize is that all the main risk of -- the key risk of Phase 1 are really behind us. The installation was a key element and this is completed, and it was completed very successfully. That's one thing I can add is that because we installed these modules using the Pioneering Spirit, we managed to install them in as 1 platform, which reduces the commissioning phase offshore. So hence, we're very -- now that the installation is completed, we're very confident that the November 1 oil definitely is achievable. And so yes, I think at this moment, at this phase, no more to add.

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Alwyn Thomas, Exane BNP Paribas, Research Division - Analyst of Oil and Gas [9]

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Okay. Maybe I could just ask then on the CapEx. Obviously, it looked pretty low during the first quarter. When do you expect the -- in terms of completion CapEx, Sverdrup to ramp up sort of in second half of the year?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [10]

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Yes, the main reason of the CapEx -- lower CapEx this quarter was its phasing. And so we expect -- at this moment, we expect the numbers we gave at the Capital Market Day, we maintain those numbers. So we expect those to ramp up towards the second and third and fourth quarter of this year. Now it is also possible that along the way, as we complete Phase 1 in Johan Sverdrup, there will be further saving and that could impact the final CapEx profile, but it's too early. We're still on the commissioning phase. So for now we maintain the CapEx profile as we state in the Capital Market Day. And some of this situation is pure phasing, which will -- so we should see some variation towards the second and the third quarter.

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Operator [11]

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Next question is from Robin Haworth from Stifel.

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Robin Alfred Haworth, Stifel, Nicolaus & Company, Incorporated, Research Division - Director of European Oil & Gas and Research Analyst [12]

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A couple if I may. So just on marketing, I mean this quarter, very good effort from the marketing team. I was wondering how you're thinking about selling Johan Sverdrup crude? Is that something you're going to be leaving to the operator? Or is there a possibility to sell some of that crude yourself? And also about -- it's going to be a big production stream, whether that might sort of fold into the Brent blend, how you're thinking about that at the moment, please? And then a second one, if I may. You referenced an increase in cost at the Sture terminal. I was just wondering if you could talk a bit more about that and what you're seeing and how reversible that may be?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [13]

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Yes, I think, Teitur, I'll let you take those 2 questions.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [14]

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Yes, I can take those questions. So starting with the marketing on Johan Sverdrup. So obviously, we are quite excited about getting barrels those onstream and to start to market those barrels ourselves, just as we are doing with the Edvard Grieg and all line crudes we are producing. So that will all be done in-house. And we actually feel fairly well positioned in that regard because if you look at the partnership within Johan Sverdrup, we are really the only sort of independent producer, if you like. If you assume Aker BP being part of the BP sort of refining system, then our barrels will be the ones that will be completely independently marketed out to the market and that could provide certain advantages. We have to wait and see how that will go. In terms of whether JS -- Johan Sverdrup will be part of the Brent blend, we don't really have any further news on that at this stage, so I can't really comment any further on that. And then in terms of the Sture tariff increases, I can't really provide any more color on that just at the moment. We are looking into, at the moment, what has caused this increase and whether that is reversible or not. But if you look at it in the big scheme of things, the numbers are not that material. But our run rate on tariffs has been around about $1.20 or thereabout, and this quarter we had $1.55. But as I said, $0.15 of that relates to this Alvheim sales arrangement. So the net-net impact is around about $0.20 a barrel or thereabout. So we need to look further into that to see whether that's a one-off or not.

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Robin Alfred Haworth, Stifel, Nicolaus & Company, Incorporated, Research Division - Director of European Oil & Gas and Research Analyst [15]

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Okay. Just a follow-up on marketing point. I think Sverdrup is a medium crude as well. I was wondering if you expect that to maybe benefit from some of the trends that you're seeing with Edvard Grieg crude this year or if you think those crude streams are sufficiently different or the dynamic sufficiently short lived that, that won't be the case?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [16]

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No, I think we see the Johan Sverdrup crude as having very similar properties to the Grane blend. So if all other things remain equal, then we would hope we should see similar metrics. But let's wait and see. Let's get it online and then see how it markets -- in the market.

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Operator [17]

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Next question is from James Hosie from Barclays.

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James William Hosie, Barclays Bank PLC, Research Division - Research Analyst [18]

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Just digging into your comments about the potential further savings in Sverdrup Phase 1 budget, I mean do we need to wait until first oil or year-end to get this confirmed or could we hear about it sooner? And is it simply just releasing contingency or is it also driven by whether you need to drill 2 or 4 more wells to get onto plateau there?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [19]

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Nick, why don't you take this question from your side.

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [20]

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Yes, James, so I mean the cost estimate that came from the operator last August was NOK 86 billion. And so which is a 30% reduction from the original PDO before FX changes. I think we're getting towards the end of the project, everything is going very well, but -- and there is still contingency left in the estimate, but there's still a lot to go on offshore. So we got to see how that pans out before we see any progress there. So I think we need to be patient and see how the offshore work goes. And -- but in any event, we're getting towards the end of it, we're at the end of the -- we're getting toward the end of the project. So there's not big numbers to be had here. So I think that's where we're at. So I mean overall, it's a fantastic performance, over 30% saving as we sit today.

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James William Hosie, Barclays Bank PLC, Research Division - Research Analyst [21]

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Okay, that's clear. So not expect too much in the way of change then. And then is it all down to whether you drill 2 or 4 more wells for the plateau?

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [22]

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Well, that doesn't have any bearing. I mean we have a fixed number of wells planned within the PDO and we'll still continue to spend money after first oil. So there's more than -- 2 to 4 wells gets us to plateau, but there's a series of production wells to come beyond that to sustain plateau and achieve recovery factor from Phase 1. So all of that's part of the Phase 1 cost estimate, which will continue drilling for a number of years after we start production.

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Operator [23]

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Next question is from Mark Wilson from Jefferies.

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Mark Wilson, Jefferies LLC, Research Division - Oil and Gas Equity Analyst [24]

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Your production efficiency numbers continue to be astonishing at Alvheim and Edvard Grieg in the high 90s. Can I ask what efficiency numbers you include in the 440,000 plateau for Edvard Grieg projections?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [25]

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Yes. Nick, I think that is a good question for you.

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [26]

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So I mean we do get extremely good results out of Edvard Grieg. It's driven by the high-quality facility design. We've now been operating it for a little bit of time, so we've been able to iron out the issues and we also have a tremendous operating team. So it's at the sort of top end of performance of the sort of business in Norway. We sort of run our forecasts on Edvard Grieg on 96%, so that's what we maintain. Of course, we strive every day to do better than that. Now turning to Johan Sverdrup, I mean it's been designed as a high-quality facility. It's going to be run to a high degree of performance. The expectation is that we get towards -- in the sort of upper end of performance into the high-quality fields in Norway at the front end of the life cycle. So we haven't guided a number, but it's going to be in the sort of higher level of performance for the sort of industry of high-quality new facility. And it'll take a little time to get there. It's a big facility. I mean just like Edvard Grieg, it took us a little time to get there. We should expect there's a sort of ramp-up in terms of performance as we start up and everything becomes stable.

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Mark Wilson, Jefferies LLC, Research Division - Oil and Gas Equity Analyst [27]

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Can I ask then what would be considered the industry norm in Norway for a facility efficiency? And can I also ask how does 440,000 compare to the nameplate capacity of those facilities at Johan Sverdrup?

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Nicholas John Robert Walker, Lundin Petroleum AB (publ) - COO [28]

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You would expect in the mid-90s just like we got -- because we're targeting 96% at Edvard Grieg. I mean it's mid-90s, so you should expect around that level. I mean we're not guiding any particular figure. And in terms of nameplate capacity for Johan Sverdrup, the design capacity of Phase 1 is 440,000 barrels a day. And just like most fields, there's usually some design margin in there. But again, we have to see how the whole facility performs when we switch it on. But 440,000 is what it's designed for of oil, there's some gas on top of that.

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Operator [29]

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Next question is from Christopher Kuplent from Bank of America.

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Christopher Kuplent, BofA Merrill Lynch, Research Division - Head of European Energy Equity Research [30]

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I just wanted to ask one more question on Q1. With OpEx per BOE trending a little higher, I wonder -- and you obviously are leaving your full year guidance unchanged. What are you saying to us in terms of full year guidance? Or what can you say to us in terms of achieved prices premium to Brent? Because it seems to me there's a bit of a tradeoff here between OpEx and -- unit OpEx and achieved prices. So is that an element that you may want to add to your guidance at some stage?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [31]

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No, we are not really changing that guidance. I mean we see the impact from these Alvheim lifting. Remember, Alvheim is relatively small component of our total production mix. So on an annualized basis, this shouldn't really change the overall OpEx and achieved oil price materially from what we have guided. So we deemed it to be immaterial to go and change our guidance, is the short answer on that.

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Operator [32]

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Next question is from Michael Alsford from Citi.

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Michael J Alsford, Citigroup Inc, Research Division - Director [33]

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I've just got one question, please. Just really on the exploration drilling campaign in 1Q. You had obviously a couple of high impact wells that were disappointing, Gjøkåsen sort of shallow and deep, and obviously Pointer/Setter in the Barents Sea as well. So can you maybe talk a little bit about the results, what does that mean in the southeastern Barents Sea for prospectivity after Gjøkåsen? And then I guess when you move to Pointer/Setter more in the Barents Sea, if I remember rightly it was targeting a sandstone play, not carbonate play. So what does it mean for, I guess the broader area from a sandstone perspective in terms of that play type?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [34]

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Yes. No, the 3 wells you mentioned, Gjøkåsen deep and shallow, I think you have to remember, this area was really a frontier area close to the Russian border, very interesting because of the size of the structure. I think the main conclusion -- we're still digesting all the data, but what we saw, we did find most of the ingredients that we didn't find really (inaudible) that was -- that led to a commercial discovery. But it's early days. It's fair to say that this just been completed, so we're currently digesting the data and trying to understand what does it mean and what does it mean for that particular area, particularly in the area (inaudible) and Gjøkåsen, which is close to the Russian border. So that's work ongoing, but it's really understanding the petroleum system in particular.

Now when you're moving towards the other wells, which are Pointer/Setter, which is -- this is a -- we are now 300 kilometers to the west of Gjøkåsen, about and that's on the Loppa High, that's different. The actual well itself, Pointer/Setter, it's fair to say we did find the reservoir. We did find oil. We did find all the ingredient necessary to make a discovery. But the reservoir was not in that particular location as we would have anticipated. But it did actually show some very interesting trends and there was more of an issue reservoir and the petroleum system there was very -- we actually did recover oil on Pointer/Setter.

So we, again, here we're digesting all the data and to incorporate them to see what it means for the follow-up drilling campaign. But I think on that point, it's fair to say this whole area, the Loppa High, has been so far successful area. You should think about Castberg, which is 0.5 billion oil, which is on the western side of the Loppa High. You have Alta/Gohta, which is also an oil and gas discovery of a significant size. And you do see different reservoir, different petroleum system, we just have now to put all the puzzle together to better understand the geology in the Loppa High. But I'm still very convinced of that, that area will lead to further discovery in the future. I think the last point is that on that Loppa High and that leads also to the discussion of Alta/Gohta. We've shot a very large TopSeis, which has dramatically improved the resolution of the subsurface. And I think this will be a very interesting next step to the next wave of drilling campaign. So in summary, the 2 wells, Gjøkåsen and Pointer/Setter are completely different and different results, but work is still ongoing. But certainly on the Loppa High, we remain very positive on the potential of that area.

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Michael J Alsford, Citigroup Inc, Research Division - Director [35]

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Alex, and just a quick follow-up on Gjøkåsen. Do you think you'll go back to drill a well in that area in 2020? Or is that a lot longer time frame to really understand the petroleum system there?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [36]

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I think I would have to process now, I think we need to digest really all the data and the results and then make a decision at the joint venture level of what we do next in that area. It is -- we have to remember that between Korpfjell and Gjøkåsen, it's a huge area and we have only really drilled 3 wells. So we really need to carefully look at all this and understanding what is this telling us and where we should be focusing on. So it's early days. I wouldn't be able to really give a precise answer at this point. But we definitely, I would say by the end of the year, we will definitely come up with a plan on what we're going to do in that area.

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Operator [37]

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And that was our final question for today. So I'll hand back to the speakers for any closing comments. Please go ahead.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [38]

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Yes, thanks very much, operator. We also have no further questions from the web either. So Alex, I'll hand over to you just to wrap up, if that's okay.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [39]

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Yes, sure. So thank you very much for your time. And again, from my side and our team, I think we're very pleased with the Q1 results overall, and we're really very pleased with the progress we're making on all fronts being on the performance of Edvard Grieg and optimizing Edvard Grieg further and finding new barrels, as I mentioned, through the infill drilling or future tiebacks. And very pleased also with the progress that we make on the different projects, including, of course, Johan Sverdrup, which is well on target to achieve the November 1 oil. So we are really only few months away from what I would say is transformational for the company. And meanwhile, still optimizing, continuing to improve our existing assets. And finally, I hope the message came through, but in terms of exploration, we've been very active. Just to remind you, in the last 1.5 years, we've actually increased by 70% our acreage position, and that is leading to a lot of activity in the whole NCS [following] petroleum. And the coming months are going to be really interesting. And I am convinced that this -- all this work that's been happening in the last 2, 3 years will really lead to success. But as exploration is -- has its ups and downs, but I think we'll be drilling some very high-quality wells in the coming months. So overall we're very pleased with the -- where the company is and where we're heading. So with that, I think, Ed, with no further question, I thank you all again and looking forward to talk to you on the second quarter.

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Operator [40]

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And this now concludes your conference call. Thank you all for attending. You may now disconnect your lines.