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Edited Transcript of LUPE.ST earnings conference call or presentation 31-Jul-19 6:30am GMT

Q2 2019 Lundin Petroleum AB Earnings Call

Stockholm Aug 16, 2019 (Thomson StreetEvents) -- Edited Transcript of Lundin Petroleum AB earnings conference call or presentation Wednesday, July 31, 2019 at 6:30:00am 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

* 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

* Anders Torgrim Holte

Kepler Cheuvreux, Research Division - Equity Research Analyst

* Christopher Kuplent

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

* 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

* Karl Fredrik Schjøtt-Pedersen

ABG Sundal Collier Holding ASA, Research Division - Research Analyst

* Michael J Alsford

Citigroup Inc, Research Division - Director

* Sasikanth Chilukuru

Morgan Stanley, Research Division - Research Associate

* Teodor Sveen-Nilsen

Sparebank 1 Markets AS, Research Division - Research Analyst

* Victoria McCulloch

RBC Capital Markets, LLC, Research Division - Analyst

* 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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Thank you. Good morning, everyone. Welcome to the 2019 H1 results for Lundin Petroleum. We'll follow the normal forum this morning. Alex Schneiter the CEO, will talk you through the highlights and operations; and Teitur Poulsen, CFO, will take you through the financials. There'll be a Q&A session at the end, hosted by the operator. And then I'll see if there is any questions from the web afterwards.

So without further ado, I hand over to Alex.

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

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Yes, thanks, Ed, and good morning, everybody. Very pleased to be here for the second quarter and the first 6 months '19.

So again, I'm very pleased with the numbers, starting with the highlights. We are posting for the first 6 months, close to 78,000 barrels of oil per day, which is production above guidance and we've seen also that the Q2 numbers are coming just above the lower part of the guidance. So very pleased with that and we continue to see very good production efficiency on the Edvard Grieg field, which I'll talk about later on.

On the operating cost, really the story continues. We are in line with guidance. And for the first 6 months posted USD 4.5 per BOE, very pleased with that. And as I stated several times, this trend will continue, particularly with the production of Johan Sverdrup soon to come. Also I would like to add that this -- we continue to post very low carbon footprint per oil produced and also very pleased with the efficiency overall.

You've seen also on the free cash flow, very pleased with those numbers, posted $167 million free cash flow for the first 6 months and Teitur will be more specific on those numbers. And we paid our first quarterly $125 million and the second payment has just been made now for the dividend and will continue so.

On Johan Sverdrup, you probably heard from Equinor already a few days ago, we're very pleased with the project, very pleased with the execution of the project by Equinor. And we're now Phase 1, 90% complete, and we're firmly on track to expect first oil in November 2019.

On the organic growth, we continue to work very hard and we have 4 projects underway, and I will be more specific later on in my presentations. And we have made 4 discoveries, relatively small discoveries and we have 7 more wells to drill in the exploration side. So still a very active exploration ahead of us and some very interesting play.

And obviously, you've heard about the Equinor transaction. Today, we will have our AGM right after the Q2 reports. And we have redeemed 16% of the shares and sold 2.6% of Johan Sverdrup.

This -- I'm very pleased with this transaction. It's accretive for all our shareholders. And it really will give more higher equity -- higher exposure to our assets and our cash flow to every shareholder. And so very pleased with the transaction, and again, we can -- Teitur will say a little bit more on this transaction later on.

Moving onto production, on the second slide. As we mentioned, first 6 months, close to 78,000 barrels of oil per day, which is above the midpoint guidance range. I think it's fair to highlight that this is the 16th quarter on a row that we are at or above guidance. So very pleased with that. And from what I can see, I'm pretty certain that Q3 will continue that trend and we see continuing very strong production, particularly from our Edvard Grieg field.

On the operating performance. As you can see from the slides, our production efficiency both on Edvard Grieg and Alvheim are really high standards with 96% on Edvard Grieg and 97% in Alvheim. Edvard Grieg, in particular, where we have the highest interest and we are the operator, we continue to post very high production efficiency. And this trend is really continuing. So very pleased with the work our team is doing there in Norway.

Operating costs, we maintain a full year guidance of $4.25 and obviously that's very much related again to the performance of Edvard Grieg. And as we go -- move forward, particularly with Johan Sverdrup coming onstream, we will see these numbers even go lower than that. So a very good place to be in, certainly leading operating cost when compared to our peers.

As I mentioned, on the carbon intensity, Edvard Grieg posted for the first 6 months close to 5 kilograms CO2 per barrel produced. This is 1/4 of the world average. And it's half of what the Norwegian average is. I'm very pleased with these numbers. And as I stated, I foresee this number to go even lower by the time Johan Sverdrup comes onstream, which as you know is fully electrified.

On the next slide, I think that's an important slide, certainly pre- Johan Sverdrup that shows the -- it's mainly focused on Edvard Grieg. First of all, we continue to see high performance on the reservoir in Edvard Grieg. Suffice to say that it's exceeding our expectation quarter-after-quarter. We see still today limited water production, which is obviously a good place to be. And we've also now embarked into an infill drilling program, which will be sanctioned in Q3 '19. And this will see as a minimum 3 firm infill well targeting about 60 million barrels of oil equivalent.

There is also a much bigger story in not just Edvard Grieg in terms of area growth opportunities. As you know, Solveig Phase 1 and Rolvsnes' extended well test, it's on track, both will be tied back to the Edvard Grieg platform. And also we're very busy on the exploration and appraisal.

You've seen the Jorvik/Tellus, which is really the northern extension of the Edvard Grieg field, which was announced as a discovery, with a range between 4 to 37 million barrels of oil equivalent. We've seen also a successful appraisal of Lille Prinsen, which is further north on the Utsira High. And today, the Goddo exploration is ongoing, which is this basement play, which so far has been very successful with Rolvsnes, and also part of the Edvard Grieg field where we have seen good results from the basement.

I think the third point, it's -- I'm very pleased with that one. But we've again now extended the plateau production, as if you remember, the latest plateau production was mid-2020 and this has now been extended to end of 2022 from the mid-2020.

And this is really 2 issues is, one is the Edvard Grieg outperformance, which as I said, we continue to see outperformance on the reservoir; and also including the Solveig/Rolvsnes tie-back project would further increase the plateau and maintaining the facility of Edvard Grieg field for as long as possible. This is from the original plan of development that's -- it's really a full year extension of plateau. So it shows how extraordinary Edvard Grieg has been for Lundin Petroleum.

Moving on specifically on the most mature project, which we're currently executing, Solveig Phase 1 and Rolvsnes extended well test. I would say, all I would like to say at this point is that both projects are on track. We're very pleased with the progress and to remind you in terms of schedule, Solveig first oil is anticipated for the earlier part of 2021. And Rolvsnes will follow right after towards the mid-2021. And so far, we're well on track to achieve that.

And as I said, this project will also help to maintaining, in addition to the outperformance for Edvard Grieg, to maintain the plateau for as long as possible and the capacity full in Edvard Grieg.

Alvheim is really the same story. It's a successful story that continues to exceed our expectations. Alvheim is really 2 items. One is the continuing infield program both on Alvheim and Volund, which has been very successful and continue to be successful. And despite the fact that Alvheim is relatively mature field, we still see very low operating cost per barrel, close to $5. So very pleased with the work that Aker BP is doing and the performance of the fields.

The second item is really the Frosk area, where we've seen several discoveries, there's been a lot of activities. And we also close to bring this first discovery onstream on the Q3 2019, which is the Frosk, we call it the Frosk test. So not only we're performing on the field itself, but we're adding new reserves -- resources and reserves in the area. So very pleased with the performance there.

And moving on to Johan Sverdrup. Of course, Johan Sverdrup is transformational for the company. It's quite unbelievable. I remember it was -- felt like yesterday we made the first discovery and here we are now 9 years later and just about to start production on Johan Sverdrup.

As I mentioned, Equinor is doing a tremendous job in executing this world-class project. And the numbers that are on this slide, I'm sure you're all very familiar with; gross resources remain unchanged from the Q2 between 2.2 to 3.2 billion barrels of oil equivalent, Phase 1 at 440,000 and Phase 2 full field at 660,000. As I reiterated several times, record breakeven price below $20.

I think the key item to highlight on this slide is the CapEx of Phase 1. And those have now been reduced further from NOK 86 billion to NOK 83 billion today. So we are continuing to see cost reduction on Johan Sverdrup. And that's very much driven by our stellar execution from the operator. And so overall, very pleased with the execution. We've seen also cost reduction in Phase 2. On this quarter, we maintained the guidance we had previously of NOK 41 billion.

On the second -- the next slide, probably that's a question that a lot of you are asking in terms of the first oil. I -- as I said, very pleased with the progress, 90% complete. One thing I would like to say is that we're firmly on track to achieve first oil in November 2019. Of course, we're carrying a range between October to end of the year. There is a possibility to do better, but I think we have to be realistic also that this is a very complex project. And certainly, I feel -- we are firmly on track for the first half of November. Could we do better? It's possible, but we have to keep in mind that this is a very complex project.

And by the second half of next year or Q2 of next year, that's where we anticipate to reach the Phase 1 plateau at 440,000 barrels of oil per day. So overall, very pleased. And this project clearly will be transformational for Lundin by the time it comes on production this year.

On the new project, we've been very busy. As you can see from the slides, 8 projects, 4 pretty much committed and ongoing, and other 4 perhaps less mature, but also like Lille Prinsen, we just completed the appraisal. And Jorvik/Tellus we just made a discovery. So this project will be further mature. And I'm sure will become a committed project soon.

Solveig, as I mentioned, first oil by 2021, Rolvsnes towards the mid-2021, Edvard Grieg also sanctioned with the rigs and there, we will be starting drilling in 2020. And the Frosk area we'll see the first Frosk production test well to come onstream this year towards the third quarter. So I'm very pleased with the progress made on that side.

On the exploration program on the next slide, we drilled so far 12 wells. We made 4 discoveries and 1 appraisal success. The net additional resources it's between 10 million to 40 million barrels of oil equivalent, is relatively modest discoveries, but ahead of us, we still have quite an exciting remaining program with 7 wells, targeting about 200 million barrels of oil equivalent.

And some of these prospect we'll be drilling, such as Goddo or Evra/Iving or even Toutatis to the north, very, very interesting prospects. So I'm really excited to see the activity in the second half. And as I said before, the organic growth is -- we are very active on that front.

And then finally, that leaves me to my -- to Teitur, the CFO, will present the numbers. And then we will have a summary slide and move on to the Q&A. Over to you, Teitur.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [3]

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Okay. Thank you, Alex, and good morning, everybody. So we are starting here in our normal fashion with giving the key highlights for both the second quarter and the first 6 months of '19. And I think we can characterize the quarter as another very solid performance financially.

You see the production numbers here, which Alex already has gone through. The Brent prices have ticked up a little bit in Q2 versus the first quarter of the year, so for the second quarter, just below $69 a barrel. And you will see later on, similar to Q1, we again had a very good quarter of realized oil prices. So we were very pleased with that.

Operating costs keep trending slightly below guidance, $4.50 for the first 6 months. And as Alex said, we are retaining our full year guidance of $4.25 for the full year. So we would expect the unit costs to come down somewhat in the second half, particularly as Johan Sverdrup starts up production. Operating cash flow of $400 million for the quarter and just below $800 million for the first 6 months. And EBITDA, very similar, $412 million for the quarter and $811 million for the first 6 months.

We had strong free cash flow generation, just below $170 million for the first 6 months, and that number includes the payment of the Lime deal, which completed in the second quarter of $43 million. So we will come back to these free cash flow numbers in more detail later on. And net results after tax for the quarter, just below $100 million; and for the first 6 months, just below $150 million.

So looking at the EBITDA in more detail and the comparatives to same periods last year. What I should state upfront here and as we have also announced to the market is that we have changed the accounting method of over/underlift positions. So we have moved away from what was called the entitlement method, and we are now reflecting sales in our financials. That means that we are basically reflecting the cash margins based on the volumes sold as opposed to what we've actually produced. And the comparative numbers have been adjusted accordingly.

So you can see here from first half '18 to first half '19, we've had a drop of 17% in EBITDA. And you can see the 2 main drivers for that is realized prices is down 7% and the sales volume is down 8% from 84,500 in the first half '18 to 77,400 for the first half '19.

For the quarter, we are down 20%. And similar drivers, again, realized prices down 8% and sales volumes from 82,900 down to 75,100. So we were underlifted in the second quarter by 1,000 barrels, which is also something we preannounced to the market. So second quarter EBITDA, $411 million, so down 20% on the same quarter last year.

On operating cash flow, very similar drivers to what you saw on EBITDA, so down 20% for the first 6 months. You can see on the table here at the top left that current tax charges have gone up to around about $44 million for the first 6 months compared to less than $10 million in the first half 2018.

And for the quarter, $400 million operating cash flow in Q2 '19. And we had a current tax charge for Q2 of $17 million, and that equates to roughly 4% of the EBITDA generation, which is pretty much in line with what we have guided to the market for the full sort of current tax rate as a percentage of EBITDA for the full year.

We are still not paying any special petroleum tax in Norway. We have, at midyear, we have remaining tax losses of around about $185 million, and that compares to $350 million tax losses at the beginning of the year. But what we do expect as we ramp up production from Johan Sverdrup is that towards the end of this year, we have fully utilized these tax -- SPT tax losses. And therefore, we will start to incur some special petroleum tax towards the latter end of the year.

Free cash flow generation has also been very good. We have seen, again, drops compared to the same period last year, again, driven by obviously lower oil price and lower sold volumes. As I said, the Lime deal completed in the second quarter of '19. So we closed that deal and, therefore, paid out the $43 million consideration, post-tax, to Lime. So that is included in these free cash flow numbers. But somewhat offsetting that in the second quarter, we had a release of working capital of close to $50 million.

So those 2 items were roughly offsetting, so still generating close to $72 million free cash flow for the quarter, which is down 20% on the same quarter last year or just below $170 million free cash flow for the first 6 months, which is down 36% compared to the same first 6 months in '18. But if you strip out the Lime deal for the first 6 months, we would have been around about $210 million for the first 6 months. And these cash flow numbers are all pre-dividend payments.

Then the net result post-tax, so for the first 6 months, as I said, $150 million net profit. That number includes an FX gain of $35 million roughly, which is a higher FX gain of $25 million higher compared to this -- to an FX gain of $10 million in the first 6 months in '18. But we should also remind ourselves that in the first 6 months '18, we booked a loan -- a gain on the loan modification of close to $100 million, post-tax. So that is why you see this big drop in net profit for the 6 months in '19. If you strip out the FX and the loan gains, we are down 28% on a like-for-like basis for the first 6 months, which again is driven mainly by the lower oil price and sold volume.

In the -- for the quarterly result, $96 million for the second quarter if you include the FX gain of $34 million. But again, if you do a like-for-like, we are down 32%, from $91 million down to $62 million. So again, simply reflecting underlying performance on oil prices and production volumes.

Then looking at the income statement at face value. We exclude the third-party marketing revenue, which was up to $84 million for the first 6 months, and that was preannounced to the market. So leaving that revenue out of the numbers, we generated a total revenue of $900 million for the first 6 months and realized a price for -- a blended oil price and gas price of $63 a barrel.

Production costs are trending very much in line with expectations of $77 million for the first 6 months. Depletion came in at $197 million for the first 6 months. That equates to $14 a barrel depletion rate, which is somewhat lower than what we have guided. We guided $15 a barrel, and that's all driven by the weaker NOK that we have seen over the first 6 months compared to our guidance.

Exploration costs pretax have all been preannounced, the $71 million. And G&A is also very much trending in line with guidance. We have guided $30 million G&A for the full year. And for the first 6 months, we came in at $14.5 million, so no surprises in -- within our G&A.

Financial items, which include the FX gain I mentioned earlier of $34 million, but we also had interest rate swaps, a realized gain there of $16 million during the first 6 months. And that was somewhat offset also by FX losses on our NOK hedges of $9 million. So all-in financial items, we had $28 million cost.

On tax, again, most of our income saving tax is deferred. So a total charge of $363 million, of which current tax was $44 million, so roughly 4%, 5% of the EBITDA generation. And that, therefore, gave us a net result after tax of just below $150 million.

I mentioned strong oil price realization in my intro. And you see on this slide, to the extreme right, the performance that our marketing department has achieved in terms of realizing crude oil prices. We had an average Brent in the second quarter of just below $69 million -- I'm sorry, $69 a barrel and we have achieved $70.30. So on average, $1.40 better, per barrel, better price realization compared to Brent.

And that's been driven, again, by strong demand for the Grane blend, which is a blend which competes, among others, against the Urals. And the Urals were short in supply in the second quarter, and that helped our realization. And also we were somewhat fortuitous in terms of the timing of our liftings during the quarter.

So as you can see here, both second and first -- first and second quarter '19, we have actually achieved a higher realized oil price than the average Brent for those respective periods. And if you then blend in the gas and NGLs, we have realized in the second quarter just over $65 a barrel, so strong realization as such.

In terms of our operating costs, we have already talked about the unit cost. But if you look at the absolute costs in quarter, came in -- if you exclude in a few movements in under/overlift, so these are effectively the cash cost relating to our produced volumes of 30 -- just over $37 million in the quarter, made up of just below $29 million for the base and project OpEx, and then just below $9 million in tariff and transportation costs. So very much in line with what we were expecting -- in fact, slightly below what we were expecting.

Within these numbers, there is also some additional costs relating to the new lifting arrangement on Alvheim where we are transporting the crude to the end customer. So we are incurring somewhat higher transportation cost on that, but we're also -- the flip side is we're also achieving a better sales price. So in the second quarter, we had $800,000 extra cost because of that.

But what you can effectively see here from the trend is that our operation team in Norway is doing a great job in keeping costs under control; you can see for the last 4 quarters, very consistent fixed OpEx. And as we flagged in Q1, the tariffs have somewhat increased on the Sture terminal, and that tariff's trend is similar in the second quarter, but down in absolute numbers because of the lower production volume.

Then turning to the cash flow generation and also the liquidity within the group. So for the first 6 months, we had cash flows from operating activities of just over $750 million, and that was offset by investments of $587 million, which includes this $43 million Lime consideration, which we paid. So that is how we generate a free cash flow of $167 million. And as I say, if you look at the organic cash generation, if you like, and take out the Lime deal, then we will be up at $210 million.

As Alex mentioned, we also paid out dividends in the second quarter in April of $125 million. And we paid out the second quarterly dividends on the 8th of July, which is not included in these numbers, of another $125 million.

In terms of our liquidity position, that remains very strong, $1.6 billion liquidity headroom within our RBL as of 30th of June '19. And what we have also announced, and this still remains subject to the EGM which we will hold straight after this call, we have added an extra liquidity of $0.5 billion in the form of a bridge facility with 2 banks. So provided the EGM approves the deal, then that bridge becomes available to us as of later today, and that bridge will obviously be utilized to partially fund the share redemption scheme that we will turn to next.

So this is just a summary of the Equinor transaction deal, which we announced on the 7th of July. It's essentially 2 transactions within this transaction, if you like. One is the share redemption whereby we pay SEK 14.5 billion to SpareBank 1 in return for redeeming 54.5 million shares. In parallel, SpareBank 1 is purchasing shares from Equinor, same amount of shares, 54.5 million shares for the same amount of -- for the same consideration of SEK 14.5 billion.

So if you calculate that out, that translates into a share price -- acquisition share price of SEK 266 a share, which was an 8% discount to the closing share price on the 4th of July, which is when we effectively agreed to deal with Equinor, or a 7% discount if you look at the 3 or 6 months VWAP price leading off to the 4th of July. So we are very pleased with that share price consideration.

What the end result will be is that our share count will reduce by 16% from current 340 million shares in issue to 286 million shares in issue once the share redemption has completed.

The second part to this transaction is the sale of 2.6% of Johan Sverdrup with an economic date of 1st of January '19. We are selling that at a price of $962 million, of which $52 million is contingent and $910 million is a firm consideration. And on that basis, we are expecting to book an accounting gain of roughly $750 million once that asset deal has completed.

And if you look at the deal metrics on this, as we said in the press release, this deal is going to be immediately accretive on a per-share basis. You see the 4 metrics we are reporting on here, 2P reserves increasing by 9% per share, from 2.3 barrels per share up to 2.5 barrels per share. And the accretiveness is even stronger on both 2C and prospective resources given that we held very little 2C in Johan Sverdrup and, therefore, didn't sell down much of our 2C numbers. We didn't sell down any of our prospective resource numbers, so we have a 19% up per share in terms of exposure -- exploration exposure per share going forward.

In terms of free cash flow, also accretive there from $3.16 per share up to $3.26 per share, less of an impact compared to the other metrics simply because Johan Sverdrup is obviously making up much of the production numbers going forward and, therefore, cash flow generation. And also somewhat offset by the fact that we, for a period of time, will carry a higher debt to fund the share redemption.

But also within these numbers, we are still continuing to assume $250 million of E&A of spend per year from 2020 to 2026. So we have not prorated down exploration spend despite the share redemption. So effectively, that means a higher gearing per share towards our exploration efforts. But the $250 million E&A is, of course, a working assumption at the moment, and we will give further guidance on that later in the year when we set the budget for 2020.

In terms of timing on the deal, as we said, we will have the EGM vote immediately after this call. And provided that goes through, we expect the shares to be redeemed effective probably at some point next week. And the Johan Sverdrup sales transaction, we would expect to complete potentially in Q3 or if not in early Q4. So those are the key milestones we should look out for in terms of completing the full transaction.

Then looking at our updated guidance, as we also outlined in the report itself. The short-term guidance remains unchanged in terms of production, 75 to 95 MBOE is the range, and we stick with that, 85 MBOE being the midpoint. And as we also said, the OpEx guidance also remains unchanged at $4.25 for the full year.

We have taken down our CapEx guidance from $930 million to $785 million. Part of that reduction guidance is, of course, a reflection of the fact that we sell 2.6% of Johan Sverdrup. That's roughly half of the saving you see here, and the other half relates to true Johan Sverdrup CapEx savings. There's also some FX impacts here given that we've had a weaker NOK during the first half and a little bit of phasing as well.

And on E&A expenditure, we are increasing that from $300 million to $325 million, again, reflecting some farm-ins. We have increased our stake in Evra/[Irving] and also Toutatis. And Jorvik/Tellus wells were successful, so we incurred more costs on those given that they took slightly longer to drill.

Long-term guidance is essentially staying unchanged despite the fact that we are selling down 2.6% of Johan Sverdrup. So near term, 150,000 barrels a day -- larger than 150,000 barrels a day stays. And the medium term from 2023 onwards when we have Phase 2 on plateau from Johan Sverdrup, there's a slight tweak from over 170,000 barrels a day to approximately 170,000 barrels a day. And the OpEx guidance long term, the bracket there is increasing by $0.20 per barrel, so a very minor change on that.

So with that, that completes the financial section -- no, there's actually one extra slide on the dividend shares. This is just to highlight that the dividend per share on the back of the share redemption will stay the same, $0.37 per share in terms of quarterly dividends relating to 2018 numbers.

But in absolute terms, with a lower share count, that will mean that our absolute dividends will reduce to $105 million per quarter compared to previously $125 million per quarter. So essentially, per share, the dividend that we have guided stays and remains unchanged.

So that was the last slide I had, and I'll hand over to Alex for concluding remarks.

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

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Thanks, Teitur. And yes, so really, for me, the best way to summarize today is we continue to have sustained production performance. This translates to 16th quarter in a row of meeting guidance or above guidance. And as you heard from Teitur, I'm very pleased also for the fact that we maintain also Phase 1 long-term guidance of over 150,000, which is really due to the high performance of Edvard Grieg and, of course, the coming -- soon coming Johan Sverdrup.

Industry-leading operating costs and carbon footprint. This is true today and it will be even more true tomorrow when Johan Sverdrup comes on stream. And maintaining our long-term guidance of between $3.4 to $4.4 a barrel, which are absolutely leading numbers on a world scale.

Edvard Grieg, as you heard from me, they -- it continues to exceed expectation, continues to grow. And the result of that is now we have today extended the plateau from what used to be the mid-2020 end of the plateau period to end of 2022. So very pleased with that, and it's been a phenomenal story and it continues to be a phenomenal story in Edvard Grieg.

And of course, we couldn't mention -- couldn't finish this presentation without mentioning again Johan Sverdrup world-class assets and a major step change for Lundin Petroleum once Johan Sverdrup will come on production. And the project is on track, firmly on track to achieve November first oil.

And we continue to deliver growing and sustainable dividend and free cash flow yield. Best way to summarize is that the company today is yielding dividend close to 5% and a free cash flow close to 10% yields. And meanwhile, we also have a company growth rate of about 20%, and we continue to be reactive on the organic growth. So overall, the company is in really great position. And it's very exciting to see now also Johan Sverdrup come on stream, which will be a major step change for the company.

So with that, I think I'll leave it open for the questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions) And our first question comes from the line of Michael Alsford of Citigroup.

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Michael J Alsford, Citigroup Inc, Research Division - Director [2]

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I've got a couple of questions, if I could, please. So firstly, just on the deal with Equinor. Clearly, very compelling on a per-share basis in terms of accretion, but it does leave Equinor with a 4.9% stake in Lundin, which I understand there's no lockup period associated with it. So it does present a bit of an overhang. So I was just wondering whether and why you didn't take Equinor out completely? Was that to do with the balance sheet? Or was it not on the table in terms of that deal? That's my first question.

And then just secondly, relating to Goddo, there was a nearby well drilled in NPL 502, the Klaff well that was testing basement, that was unsuccessful. So I was just wondering whether there's any read across to what you're looking for or what you're expecting in Goddo.

And then just finally, on Solveig, there's a big resource range, 40 million to 100 million barrels of oil equivalent. I was just wondering whether you could just talk a little bit about the range and why it's such a big range even with the [thing FIYD-ed]?

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

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Yes. Okay. I'll take those questions. On Equinor, the 4.9%, I think, you've heard from Equinor, they stated clearly that they're happy with that investment and, for now, they're happy with their position.

Now your specific question of why we didn't take it all off, partly it's that was the deal that was negotiated. At that point we -- both parties were happy with that negotiation with the -- with us taking 16% and selling a part of Johan Sverdrup and part of the deal was simply that Equinor will maintain 4.9%. And I think it's -- it was just, for us, the best way to conclude the deal with Equinor. I don't think there's much more to say at this point.

On Goddo, yes, you're right. You mentioned Klaff. I think it's a basement play. We have to mention also that Equinor was targeting sand above the basement play. So in terms of the sand, yes, there was a minor -- that they still fund some of the sands, but perhaps it was minor. But in terms of the basement, actually that well presented some really interesting features. And we're currently evaluating the course, or Equinor's evaluating the course along and we're looking at all these results.

So in actual fact, we find the well quite interesting. Goddo. So we still very excited with Goddo. It's a really -- for us, Goddo is a follow-up of the Rolvsnes discoveries. It's closer to the Edvard Grieg. So I'm still very keen to see the results, and we're going to see soon the results of Goddo probably in the next 4 weeks as -- since we're drilling it as we speak. So overall, including the results from Klaff, I would say interesting for the basement play.

On the range on Solveig, the 40 million to 100 million you're mentioning, this is also related to the phasing of Solveig. And as we drill further wells, we will have a better understanding on the reservoir and the performance that will allow us then to narrow the range, and also -- that will have also an impact on Phase 2 of Solveig.

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Operator [4]

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And our next question comes from the line of Sasikanth Chilukuru of Morgan Stanley.

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Sasikanth Chilukuru, Morgan Stanley, Research Division - Research Associate [5]

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Two questions, please. The first one was regarding Edvard Grieg and the production efficiency. You've highlighted 96% for first half, but it does seem like in 2Q it was relatively lower at around 93%. Just wondering what the reason was and whether it was temporary?

And the second one was regarding liquidity. You mention the additional bridge loan, but if I were to take the timing under consideration it seems like the share redemption happens earlier and then the -- possibly, the sale of the additional stake are 2.6% of Johan Sverdrup later on. I was just wondering, in the meanwhile, it seems like liquidity might come down to around $500 million, $600 million. Are you comfortable with that? Is there anything that you think should be done necessarily about that?

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

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I'd take the first question, your question related to Edvard Grieg. On the second quarter, we posted about 94% of uptime, converting the 96% for the 6 months. I think we had a slightly lower uptime that was related to some turbine issue that we had to resolve. Those are now behind us and all I would like to say is that since that, the field has been performing extremely well. So very pleased with the performance, I would say, that's -- it was one unexpected event related to 2 turbines, but that's well behind us and Edvard Grieg performing very well right now.

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

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [7]

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Yes. It is true that the share redemption will happen earlier than the completion of the asset sale, and that's exactly why we took out this additional bridge of $0.5 billion to give us this sufficient liquidity to effectively bridge finance to share redemption until the asset sale completes.

So what will effectively happen is that over the next 2 or 3 days, we are going to pay the cash for the share redemption, which, as I said, is SEK 14.5 billion or around about 1.5 -- just over $1.5 billion. And then when the Johan Sverdrup asset sales completes, which remains subject to government approval, which we expect just to be a formality. And then we will receive proceeds from Equinor of $910 million plus some interest on that from 1st of January and also plus a catchup on CapEx we have funded from the 1st of January.

So if you look net-net, after all the transactions have completed, our net debt should increase around about $600 million compared to pre-deal. So that will effectively mean that we will have plenty of remaining liquidity within the RBL, once the asset sale has completed. And our plan will be to cancel the bridge facility as soon as we receive the proceeds from the asset sale.

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Operator [8]

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And our next question comes from the line of Christopher Kuplent of Bank of America.

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Christopher Kuplent, BofA Merrill Lynch, Research Division - Head of European Energy Equity Research [9]

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Quick one. Firstly, could you go into a bit of more detail about the source of the CapEx cut that you're announcing in your guidance? I assume this is about more than the Johan Sverdrup cut that we know about.

And secondly, Alex, if I may, the transaction with Equinor, were we right in interpreting this as Lundin being more bullish on its own share price then bullish about Johan Sverdrup at the valuation? I think it puts out $37 billion-or-so implied that Equinor paid you.

The wider point of this question is, what's the equity story in your mind once we see Johan Sverdrup for the U.S.? And I think we're not far away from that. What are you most excited about as you look beyond, let's say, Phase 1 ramp-up?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [10]

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Yes. I can take the CapEx question first. It's pretty straightforward, really. We guided $930 million CapEx for the full year. That was based on our 22.6% working interest in Johan Sverdrup. With this sale to Equinor, our effective interest is going to be 20% for the full year '19, given that economic date is 1st of January '19. And that means we have to fund around about $70 million less in CapEx for the full year '19 because of that.

The other item is that when we gave the guidance originally at Capital Markets Day, we had Phase 1 CapEx guidance of $86 billion -- NOK 86 billion for Phase 1 gross on the Johan Sverdrup and that's now been reduced to NOK 83 billion. Not all of that saving relates to '19, some of it's to later years. And then there is some -- a smaller element in terms of FX saving of -- because of a weaker NOK.

So those are the 3 items really impacting that. There's a little bit of phasing on Solveig and Rolvsnes, but that's immaterial in the bigger scheme of things here.

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

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On your second question, I guess, if I can summarize your second question was beyond Phase 1 ramp-up was in the story of Lundin Petroleum. I think there's many things. Of course, the -- beyond Phase 1, I'm thinking about the Edvard Grieg areas, we continue to see Edvard Grieg growing. We've been very successful so far. We've seen also further growth to the north of Edvard Grieg with Jorvik and Tellus. We now also see the tie-backs, such as Solveig, Rolvsnes, which will further extend the plateau of Edvard Grieg and create -- generate great value. And so the aim obviously for us over the time is to maintain the capacity on Edvard Grieg full.

And I'm convinced around the Edvard Grieg area there will be further potential and further discoveries. I'm thinking perhaps at Goddo, which is ongoing in the basement plays. We've seen a lot of good results and that, in itself, has got great potential. We categorize that as over 250 million barrels, and we have substantial equity in that area. So the Edvard Grieg area and actually the Utsira High as a whole, I still see a lot of upside and potential to grow there.

Of course, then beyond that, we have Phase 2 of Johan Sverdrup. There are -- there is -- it's -- that will bring us to the next step change to the 660,000. And I think overall Johan Sverdrup, I've said that several times, I see quite a lot of upside on Johan Sverdrup itself and we have -- we've -- yes, we made that transaction but we maintain a very significant equity position in Johan Sverdrup with 20% and fully expose to the upside of Johan Sverdrup.

And then beyond that, we have the 8 projects, which I mentioned, 4 of which are ongoing and 4 to further mature. And so that will add to the post- Phase 1 ramp-up. And of course, the organic growth. I still believe NCS is one of the best place in the world to be. It's a great place to explore. We are very active, we've done a lot of work over the years and there's going to be a lot of activity coming forward, and I'm convinced that there will be further growth for the company on the organic growth.

And of course, all that will then translate into cash flow, cash flow generation, free cash flows. We still -- over the -- for the next 8 years, we still forecast close to $1 billion of free cash flow for the company, which will give us the ample ability to maintain our policies and -- the sustainable policies and grow our dividend.

So there is -- there's really a lot ongoing in petroleum going forward, and we're maintaining the low operating cost guidance between 3.4 to 4.4, which are leading operating costs, which obviously lead to excellent financial performance. So between Edvard Grieg, the Utsira High, the existing projects, which are ongoing the organic growth, this is how I see Lundin moving with further growth and where I see the further value created.

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Operator [12]

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And our next question comes from the line of Karl Pedersen from ABG.

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Karl Fredrik Schjøtt-Pedersen, ABG Sundal Collier Holding ASA, Research Division - Research Analyst [13]

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Just wondering if you could help break down the volumes on Edvard Grieg and effectively, both that you had the nerve to extend the plateau. So how much of it is reflected in your current 2P reserves to resources, and how much is the push out from the [interval]? Where do you see the barrels coming from?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [14]

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Yes. When it comes to 2P, this will be updated at the end of the year as we do every year. Our reserves are third-party certifications, so I will not be specific at this point in terms of the reserves' addition on 2P. That will come towards year-end in January.

All I can say is that the current extended plateau, you could -- from the mid-2020, approximately 1 year comes solely from the Edvard Grieg field. And then the rest is from tie-backs. But in terms of pure reserves and upgrades, this will be updated at year-end.

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Karl Fredrik Schjøtt-Pedersen, ABG Sundal Collier Holding ASA, Research Division - Research Analyst [15]

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Yes. Sure. So it's more of a -- [wanted to] do so much is already in your numbers and that would be 1 -- you're adding 1 year, more or less.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [16]

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We are approximately, adding 1 year on Edvard Grieg, yes. And then as I said, in terms of reserves, this -- we will be more specific at year-end, by the time we're done with third-party reserve certification.

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Karl Fredrik Schjøtt-Pedersen, ABG Sundal Collier Holding ASA, Research Division - Research Analyst [17]

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And looking to exploration, of course, the Utsira High has been your key area. Looking to the end-to-end Barents Sea end, Southern Barents Sea, how active do you anticipate to be there? Do you feel that, that's an area that requires a lot more work before it can do full scale exploration program there? Yes.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [18]

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We maintain a very active program on the Barents Sea, we -- Southern Barents Sea. We still firmly believe that there's great potential in that areas. We haven't unlocked all the secrets of the Southern Barents Sea, but we also have to remember that over the last 4 years over 1 billion barrels of oil have been discovered with different play type, different petroleum systems. So we continue to do a lot of work there. We -- you will see us drilling further wells there.

There really are 3 company are very active in that area is Equinor, Aker BP and ourselves. And the area, it's a huge areas. But I'm convinced that there will be further discoveries and the Southern Barents Sea will -- it's a great place to be and is one of the core areas that we will maintain and be active.

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Operator [19]

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And our next question comes from the line of James Hosie at Barclays.

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James William Hosie, Barclays Bank PLC, Research Division - Research Analyst [20]

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Yes. Teitur, you described the $250 million annual exploration spend as a working assumption that could be revised now following the Sverdrup stake sales. Are you suggesting that budget could go up or down? And what are the factors that could actually drive that change?

And then a second question is just in the recent drilling results you've had at Lille Prinsen and I guess the Frosk area, too. Are these now projects that could reach PDO in 2020?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [21]

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Yes. No. On the E&A number, I mean given that we're guiding 8-year forward on free cash flow numbers, we have to assume some kind of E&A spend. So we picked the number of $250 million. Now of course, when it comes to budget time, that will be a bottom-up throughout number on the opportunities that we see in Norway. So whether that number will be higher or lower, I think we will have to work that through the budget and see what the opportunities that is. But it's clear that organic growth is -- remains the key focus of the company. So there's certainly no intent to cut the E&A spend despite this share redemption at the moment.

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

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Yes. And then Lille Prinsen and then Frosk, of course, our aim is to reach commerciality on both this project. I mean Frosk is -- one of the first well is going to production on the third quarter. Lille Prinsen, we just completed the appraisal. So it's early days to give a specific timing, but clearly, we're going to work as hard as possible. And those are -- all of them are tie-back. So they -- if it didn't commercial I would assume they would be quite easily developed and -- timing-wise, but too early to give a specific timing at this point.

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Operator [23]

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Our next question comes from the line of Teodor Nilsen of SB1 Markets.

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Teodor Sveen-Nilsen, Sparebank 1 Markets AS, Research Division - Research Analyst [24]

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And congrats on the Equinor (inaudible). I have 2 questions. First one on Sverdrup Equinor, they had indicated that the ramp-up pace to plateau of Phase 1, that will be quicker than previously assumed. So what should we assume in our models in terms of ramp-up pace? Would it be a linear ramp up from end of 2019 until mid-2020? Or will it be back-end loaded?

And my second question is on dividend. You said you will keep dividend flat per share after the Equinor deal. And looking into 2020, how should I think around dividend? Will that be a percentage of EPS or cash flow or some kind of other metric?

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

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Questions. You're right, Equinor, it guided, and as you know, they guided that they will reach plateau by midyear of 2020. I think in the ramp-up, you have to remember that the -- it will be initially coming from the first 8 wells, and we anticipate it is first 8 wells by year-end to be on -- to be completed. And then to reach plateau, we will have to drill 2 to 4 further wells. So you'll see a relatively steep ramp-up in the beginning and then later on the 2 to 4 wells to come at the end. So -- and with a target of midyear.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [26]

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Yes. And on the dividend, Teodor, I mean if you look at the share redemption of 16%, so if we take the per share dividend of $1.48, that will equate to an annual dividend of $420 million going forward compared to the $500 million we guided initially. And yet, despite the sale of Johan Sverdrup, we are still forecasting from 2020 to 2026 to be just below $1 billion of free cash flow per year, still assuming $250 million of E&A spend per year over that period.

So again, the message is the same as it was pre-deal that we have ample scope to both increase the dividend over time, which still is the plan, at the same time as maintaining our organic growth strategy and to pursue our contingent resources, whether that's up in the Barents Sea or around the Edvard Grieg area.

So we can do all of those components without overstretching the balance sheet, and the assumption is that we will gradually pay down debt within that financial framework. So really, the situation remains the same, pre- and post-deal, in terms of our dividend strategy.

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Operator [27]

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Our next question comes from the line of Yoann Charenton of Societe Generale.

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Yoann Charenton, Societe Generale Cross Asset Research - Equity Analyst [28]

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I will ask 3 question, mainly on operations. So Edvard Grieg, would you be able to provide any indication on the operating costs you will expect to see from now until late 2022?

Then maybe as well on exploration. Based on your track record so far this year, would you believe that there is a case at this stage to lower the Barents Sea share next year as part of your E&A campaign?

And then last point on production guidance for 2019. If you could please provide further clarification what prevents you from tightening the production guidance tranche as we enter the second half of the year.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [29]

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Yes. Okay. I think on Edvard Grieg, the best is to look at the current performance in terms of operating cost. And as long as we maintain Edvard Grieg, kept the capacity full, I wouldn't expect this cost to change significantly.

On the exploration side, no, as I said before, we still strongly believe on the Barents. As I said, it's a very large areas. There is a lot of potential, but we have to do further work. And we've just acquired a large 3D TopSeis, and we will be drilling further wells. And as I said, this is one of the 7 core areas we are working on. But we have no plan to reduce our activity, and we still firmly believe on the potential of the Barents Sea, and in particular, the Southern Barents Sea.

Your third question was...

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [30]

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Production guidance.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [31]

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The production guidance, yes. No. I think if you look at the production guidance, it is very clear. The range is between 75,000 to 95,000, which is a large range. It's very much driven by the onset of first oil. If we -- the midpoint, 85,000, is predicated on achieving first oil in November, and the lower part, the 75,000, assumes hardly no production from the onset of this year. And vice versa, an earlier start in October will lead to the top range of the production, that 95,000. So we -- since we are very close to first oil on Johan Sverdrup, we're not changing at this point the guidance since it's very much related to the startup of the onset of first oil.

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Operator [32]

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And our next question comes from the line of Alwyn Thomas at Exane BNP Paribas.

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Alwyn Thomas, Exane BNP Paribas, Research Division - Analyst of Oil and Gas [33]

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I just wanted just a quick couple of questions on the financial outlook following the Equinor transaction. Firstly, Teitur, can I just check on your expectations for tax paid, given the selldown? I believe the historic CapEx depreciation allowance is transferred, but maybe if you can just talk a little bit about moving parts there for this year and next year as a result of this transaction.

Also on CapEx, and so looking into next year as well, I'd appreciate some comments on phasing but also with sort of falling [scheduled] CapEx. Maybe -- should we extrapolate that into next year as well, starts with additional activity on infill drilling and some of the other projects?

And perhaps just last one on exploration. Just wanted to get some comments on the Mandal High area where you drilled a couple of wells over the last few months. It looks highly prospective area, but it hasn't quite been working yet. So maybe just a few comments there on what are you seeing in that area going forward.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [34]

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Yes. I can take the question on the tax. And you are correct that when you do sell a stake in a license on asset deal effectively, then the undepreciated tax balance relating to the working interest you're selling will transfer across with that working interest. So that means that part of the tax shelter we had at the beginning of the year, that will effectively be reduced by 2.6% or 11.5% of our working interest in Johan Sverdrup. But I wouldn't expect our current tax charge for '19 to change materially. Obviously, that will depend a little bit upon when Johan Sverdrup starts up. But our mid-case assumption is still November. And on that basis, I would still expect the full year tax due as a percentage of EBITDA to be somewhere between 4% and 6%.

Then looking into next year, I think we've guided already that once Johan Sverdrup for Phase 1 is on plateau, we would expect our current tax charge as a percentage of EBITDA to increase up to around about 45% to 55% over the period from plateau Phase 1 until the plateau Phase 2 comes on stream in 2022. And that guidance still remains intact. Of course, there are lots of moving parts within that. How much of the contingent resource we will go after and therefore, what CapEx do we spend on that? And also on the E&A, will it be higher or lower than the $250 million? That will also impact on those current tax numbers. But broad-based, the guidance we gave at Capital Markets Day still stays.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [35]

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Yes. And then on your Mandal High question, you're right. I mean it's a very interesting area. We drilled 2 wells so far, having unlocked the secrets of the Mandal High. But it's fair to say there's -- we continue to review and doing a lot of work in that area and looking at the opportunities, understanding the results of these wells to really zoom in on the right direction on the Mandal High. But definitely, we believe there's still further potential in that area, which is highly prospective. So it's -- I would say it's work ongoing at this stage.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [36]

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And then maybe on the -- you had a CapEx question as well. I mean we will give, again, more detailed guidance on the 2020 CapEx. But clearly, our CapEx for 2020 will, on a like-for-like basis, go down, given our lower working interest in Johan Sverdrup. But as you also said, that will be somewhat offset by the infill wells we are now committed to on Edvard Grieg, which weren't in our original Capital Markets Day guidance. So all-in, I wouldn't expect the number to be materially different to what we have already guided in our Capital Markets Day material.

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Operator [37]

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And our next question comes from the line of Duncan Milligan at Goldman Sachs.

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Duncan Gregor Milligan, Goldman Sachs Group Inc., Research Division - Equity Analyst [38]

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I just wonder on the Edvard Grieg area. You mentioned before that you were shooting some TopSeis over the area. And with the success of Jorvik and Tellus in the kind of near-field area, what does that do to your expectations for the Edvard Grieg area as a whole kind of excluding, I guess, Solveig? And what do you need to kind of see to kind of continue to think about extending that plateau? I realize it's gone out another year so far at this update. But -- to kind of continue to build on that.

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

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Yes. On the TopSeis, it's a relatively small area we currently -- we've acquired, which goes from the Lille Prinsen into Edvard Grieg and further south. We're evaluating the data. It was really a test data to really look at the quality of the data, where the TopSeis compares some of the bottom -- ocean bottom cable and seismic we've done. So we hope to see that the TopSeis can equal or increase the resolution of that seismic, and that work is ongoing. As you know, we are a great believer in the TopSeis. We view that, that can unlock and increase the resolution in general and show us things we haven't seen before.

In terms of your question on the Edvard Grieg area, specifically on plateau, of course, the -- right now, we've extended the plateau to end of 2022, which is coupled between odd performance of Edvard Grieg and also the future tie-ins. But in addition of -- as you heard from us, we will be drilling infill in the -- in Edvard Grieg areas, and that will start in 2020. And that will further impact the -- maintaining the full capacity of Edvard Grieg for a longer period of time. We also have, of course, Rolvsnes and then hopefully Goddo and other prospectivity and Edvard Grieg continuing outperforming, which will allows us to capture more of the 3P reserves. So there's a lot going on in that area to have a chance to further increase the plateau beyond 2022.

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Duncan Gregor Milligan, Goldman Sachs Group Inc., Research Division - Equity Analyst [40]

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And I guess just following up on that. I mean will additional wells to your [quad], so drain Jorvik and Tellus, or do you think that, that can be drained with the existing well stock? And should we think about further infill campaigns over the coming years? What would you think of these for next kind of 3 wells is?

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

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Well, Jorvik -- yes, Jorvik and Tellus, those wells been -- have been abandoned. Those were test wells. So if we need to drain the Jorvik area, Jorvik and Tellus, that will require further drilling.

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Operator [42]

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Our next question comes from the line of Anders Holte at Kepler Cheuvreux.

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Anders Torgrim Holte, Kepler Cheuvreux, Research Division - Equity Research Analyst [43]

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Just a quick one for me this morning. As far as to your funding structure, you now have the RBL in place. But I guess we all have seen where the arc of BPS moved, also a bit more flexible funding structure. I know that's probably not where you're going to head. But do you think RBL is going to remain your main source of debt funding? Or is there an idea that you would potentially move over to a more RCF-like structure as long as the [equitable debt] doesn't raise materially?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [44]

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Yes, Anders. I mean that's clearly something we are looking at and continuously assessing. I think for now, we're happy with the RBL. We have an excellent relationship with the 26 banks, which are within the RBL. We modified the terms of the RBL last year, a year ago actually. So we achieved some better terms on that. And the RBL will start to amortize from mid next year and then amortizes down to 0 by the end of 2022. So I think our sort of logical refinance window would be somewhere towards late 2020 or potentially into 2021 depending on how our debt projects out over that period. But clearly, moving from an RBL into more of a corporate facility is something that we would look at and consider, and the bond structures is also something we're looking at potentially in parallel with that. But no decisions made at this point, but all options are open, I would say.

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Operator [45]

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Our next question comes from the line of Victoria McCulloch of RBC.

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Victoria McCulloch, RBC Capital Markets, LLC, Research Division - Analyst [46]

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You talked a lot about how obviously first oil from Sverdrup plays an important role in getting to this year's production numbers. Could you just give us an idea of the scheduled maintenance for the second half of this year across the other fields?

And secondly, you've also talked about organic growth mostly this morning. Is there an appetite for asset deals in the business?

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [47]

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Yes. On Johan -- your specific, Johan Sverdrup and maintenance, at this stage, we're guiding specifically. And -- but I -- we don't have any expectation of maintenance on the -- certainly, in the earliest part of this year.

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Victoria McCulloch, RBC Capital Markets, LLC, Research Division - Analyst [48]

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[Sorry] it was in the other fields, too. So excluding Sverdrup being the main...

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

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The other fields, yes. No. We don't have -- we're not guiding specifically on the maintenance. But what I can say is this year we don't have any specific maintenance in the MDA on -- particularly in [ambiguity] operated fields, which we operate.

On the organic growth story, your specific question was on the M&A, yes?

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Victoria McCulloch, RBC Capital Markets, LLC, Research Division - Analyst [50]

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Yes.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [51]

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Right. And yes, we -- there's no -- we're looking at every -- we're turning every stone in the Norwegian Continental Shelf, and we are driven by organic growth. But of course, if we find the right opportunity, we will do it. We have the liquidity and -- to do it. We've done some smaller deal. We've obviously done in the past the Edvard Grieg, where we bought from Equinor. We also bought a company, Lime, this year, which allow us to increase our equity position on the Utsira High. And if there are other opportunities, which tie in well with our strategy, we will definitely look at it. And we've been very, very active on that front. But at the same time, when it comes to perhaps more mature fields, this is perhaps less of interest to us. But we're very active in that front, too.

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Operator [52]

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Next question comes from the line of James Thompson at JPMorgan.

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James Thompson, JP Morgan Chase & Co, Research Division - Analyst [53]

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Just one question for me really. It seems to me that the basement play on the Utsira High is probably the best source of upside at this point in time to your contingent resource base, which I feel is probably a little bit of a weak link in the story. So with that in mind, when do you think you'll be able to give us an updated sort of more holistic view of the resource opportunity on -- in the basement play on the Utsira High? I mean do you plan on providing one post-Goddo? Or do you think you're in a position now to sort of talk a little bit more about the opportunity above the sort of 250 million barrels that you've guided to so far?

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

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Really, there's -- I mean a lot has happened on the basement, as you know. Just to put things in context, we drilled the Rolvsnes discovery. Then we did drill the extended well test, where we produced over 7,000 barrels per day. We also drilled basement through some of the Edvard Grieg development wells, which have been successful. We then drilled Jorvik, which was another successful well into the basement, and now we're waiting obviously the result of Goddo, important to unlock the upside. And so we're waiting for those results, and we will then work on those data to then work towards resources. But I don't expect to come up with any area-specific numbers before 2020, once we have digested all the results and particularly Goddo. But overall, I -- so far, what we've seen in the basement is very exciting.

Now beyond the basement though, I would like to say that there's still quite a lot ongoing. We are active in many core areas. Of course, it's [pure], it's explorations. But there is -- I'm convinced there would be more to come beyond the basement.

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Operator [55]

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(Operator Instructions) And as there are no further questions at this time, I'll hand back to our speakers for the closing comments.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [56]

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Thanks very much, operator. And rather disappointingly, we have no questions on the web either. So I think we'll conclude here, and we'll skip across to the general meeting, which will take place shortly.

So thanks very much, everyone. And if you have any further questions, don't hesitate to give us a call.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [57]

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Yes. Thank you very much.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [58]

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Thank you.