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Edited Transcript of LUPE.ST earnings conference call or presentation 31-Oct-19 8:00am GMT

Q3 2019 Lundin Petroleum AB Earnings Call

Stockholm Nov 4, 2019 (Thomson StreetEvents) -- Edited Transcript of Lundin Petroleum AB earnings conference call or presentation Thursday, October 31, 2019 at 8:00:00am 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

* Teitur Poulsen

Lundin Petroleum AB (publ) - CFO

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Conference Call Participants

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* Al Stanton

RBC Capital Markets, Research Division - Analyst

* Alwyn Thomas

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

* Anders Torgrim Holte

Kepler Cheuvreux, Research Division - Equity Research Analyst

* Duncan Gregor Milligan

Goldman Sachs Group Inc., Research Division - Equity Analyst

* James William Hosie

Barclays Bank PLC, Research Division - Research Analyst

* Matthew Smith

BofA Merrill Lynch, Research Division - Research Analyst

* Michael J Alsford

Citigroup Inc, Research Division - Director

* Sasikanth Chilukuru

Morgan Stanley, Research Division - Research Associate

* Yoann Charenton

Societe Generale Cross Asset Research - Equity Analyst

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Presentation

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

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Thanks. Good morning, everyone, and thank you for joining the Lundin Petroleum Q3 Results Presentation. We'll follow the normal course. Alex Schneiter will talk to you through highlights in the operations, and then he'll hand over to Teitur to talk through the numbers. And there will be a Q&A session at the end.

So Alex, I'll hand over to you to start.

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

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Yes. Thank you, Ed, and good morning, everybody, and let me get straight into it.

So starting with the first 9 months and the highlights, again, very pleased with the results, both on the 9 months and the Q3, with production above guidance. We posted for the 9 -- first 9 months 79,000 barrels of oil per day. And as you see, the Q3 actual was actually close to 83,000, which is really at the upper end of our guidance. So very, very good performance from our Norwegian team on the production side.

On the operating costs, we continue to have leading operating costs, posting USD 4.31 per BOE and, with the Q3 actual, actually below $4. So very, very pleased with the efficiency and the cost in terms of operating costs.

Free cash flow, you've seen a large number, and Teitur will give more color on this. So we're in excess of $1.1 billion. That numbers were very much affected also on the cash received from the closing of the sale of 2.6% equity in Johan Sverdrup, but I will let Teitur go into it in more details.

And of course, the big news, which is post Q3, was the first oil in Johan Sverdrup, which came ahead of schedule on the 5th of October and, so far, very pleased with the performance of Johan Sverdrup, both in terms of ramp-up and also plant stability. So very pleased with Johan Sverdrup.

The organic growth, we continue to be very active and busy. We have 4 projects underway, and I will say a few more words later on, on the later slides. This year, we posted 5 discoveries, but -- and we continue to be very active with 3 new wells drilled this year, very interesting wells. And next year, we're anticipating to also have a very active exploration program.

The 5 discoveries, is fair to say, were small discoveries, and -- but I still believe the Norwegian continental shelf has got tremendous potential. And I -- if we continue on that path with our active organic growth, I'm convinced we will be able to find new resources and some sizable resources.

You've also seen in -- last Monday, we posted our press release that we have made a decision to -- for a full electrification of Edvard Grieg. I mean, now this is sanctioned, and the plan is that Edvard Grieg will be fully electrified by the time Johan Sverdrup reaches Phase 2 at the end of 2022. That means that Edvard Grieg's carbon footprint will go below 1 kilogram of CO2 emission per barrel produced from 2022. So a very, very good position to be in, particularly on the back of Johan Sverdrup also.

And of course, HSE performance. Our team in Norway continues to do an excellent job, and we've seen excellent performance on that level also, too.

The second slide on production, I think I will focus on 3 items, one of them I already mentioned. Q3, we are above the upper range of the guidance at close to 83,000 barrels of equivalent per day. Most importantly, we're increasing the full year guidance to 90,000 to 95,000 from what used to be 75,000 to 95,000. So a midpoint of 85,000 barrels of oil equivalent per day to now a midpoint of 92.5.

This is driven really by 3 items. Number one is the Edvard Grieg continued outperformance. Number two, it's Johan Sverdrup coming ahead of schedule. And number three is the improved or excellent ramp-up of the predrill well in Johan Sverdrup.

And then finally, this is the 17th quarter in a row that we're delivering at or above expectations. So really a tremendous job from the team, both here in Geneva and in Norway.

Moving to the next slide. This is something we've always been focusing, and it is true. We are industry-leading operating in terms of operating performance. And this is really driven by 4 items. Number one is production efficiency, so the facilities. And we've seen an excellent performance on Edvard Grieg with 98%, and also from our friends at Aker BP in Alvheim at 97%. These are simply very, very good numbers.

Moving from production efficiency. The second item is the operating costs, as I mentioned, $4.31 for the quarter. And we're maintaining the full guidance of $4.25 for the full year. So really industry-leading operating costs, 1/3 about of what we see in the North Sea on average.

Third item is obviously carbon intensity. And Edvard Grieg, despite being run by turbines today, has posted less than 5 kilograms of CO2 emission per barrel produced. This is a quarter of the world average. And as you know, by going full electrification by 2022, we're going to further reduce this number. So very pleased also with the carbon intensity on Edvard Grieg.

And finally, the fourth item is there's no good business without good HSE performance. And we had 0 material incident. So overall, really, really pleased with the overall efficiency and the operating performance.

Moving to the assets themselves, starting with Edvard Grieg. Of course, the key for us in Edvard Grieg is to maintain the facility full for as long as possible. On the previous quarter, we've told you that we've increased the plateau production to the end of 2022. And so we maintain, obviously, that guidance.

In Edvard Grieg, we see the performance continues to exceed expectation. This is very much driven, but still very limited [to water] production. And we also see -- we have now confirmed the infill drilling program, which has been sanctioned by our partners, and we'll be drilling our first infill wells in mid-2020. So Edvard Grieg itself has grown on us from what used to be 186 million barrels of oil field to today exceeding 300 million. So a simple extraordinary story for Edvard Grieg.

The next step is obviously to continue to grow and maintain the facility full for as long as possible, and this leads me to the area growth opportunities. As you know, we are now in the execution phase of Solveig Phase I and Rolvsnes extended well test. Both of them will be tied back to the Edvard Grieg platform.

We've seen also successes this year around the Edvard Grieg area. We've seen the Jorvik/Tellus East discoveries, which are certainly one of the potential infield drilling candidates for next year. We've seen also an appraisal success for Lille Prinsen, which is a small field North of Edvard Grieg and a potential tieback; and obviously, the [basement] play, Goddo, which also will be testing indirectly through Rolvsnes when we have the extended well test.

So all this, we have extended the plateau production to end of 2022 and very much driven by Edvard Grieg outperformance and the tiebacks to Rolvsnes.

And I guess my message really is that we -- there is more to do in the area. We haven't seen the end of it, and we will continue to explore with further exploration for the success for the tieback and also potentially increasing the 3P [into] 2P we will see potentially for the extension on Edvard Grieg.

The next slide, it really shows you the potential infill drilling candidates. We have 3 firm in-fill wells. Rig is contracted, which will add 18 million barrels of oil equivalent and with very, very good economics in breakeven at about $25 per barrel.

And as I mentioned, the ultimate is that we've increased our reserves, 2P preserve at Edvard Grieg to what used to be 186 today standing at 286. And we forecast the reserves in Edvard Grieg to exceed 300 million by year-end by the time we have the usual year certification process.

On the projects, Solveig and Rolvsnes, I would say, first of all, that the progress is according to plan and budget. Today, the status is that Solveig's about in excess of 10% complete, and Rolvsnes is in excess of 15%, and first on in Solveig, anticipated in the first quarter of 2021 and Rolvsnes to follow thereafter.

So overall, we're on track, and the project is on track to achieve first oil in 2021.

The next slide is what was announced on Monday. And I think this slide really summarizes what the industry can do at its best. As you know, Johan Sverdrup is fully electrified using onshore power, mainly coming from renewable. If we made the decision to extend this by the time Phase 2 is reaching Johan Sverdrup and fully electrified Edvard Grieg, and that full electrification or partial electrification will continue to the nearby fields, so this, obviously, leads to absolutely fantastic track record when it comes to carbon footprint.

If you compare it to the world, we will be about 20x lower than the world average. And both Johan Sverdrup and Edvard Grieg will post emission of CO2 per barrel produced less than a kilogram. And it's really phenomenal, and it really shows what our industry can do by being innovative and using new technology, and is even more so when you know that most of this [synergy] comes from renewable, mainly hydropower in Norway. So very pleased with this involvement [in] the development.

It's also fair to say it's a very good business case. We see that electricity increases [uptime] . We also reduce our CO2 taxes and, of course, reduce our emissions -- carbon emission per barrel produced.

Moving on. The -- you've seen that Lundin for the first time in its history has invested into renewable. I would say this is not something new. It's just a logical step. First of all, obviously, through technology, electrification, we've managed to reduce our carbon footprint dramatically. And the investments in renewable really is to offset and replace the energy we're using offshore.

So we invested in the -- what we call the Leikanger Hydropower investment. Lundin acquired 50% interest, and the remaining 50% is operated by Sognekraft. As I said, the main purpose is to offset the nonrenewable part of the electricity we're using offshore. About 65% is from the renewable sources, and the remaining 35% is from nonrenewable sources.

So our aim is to offset those nonrenewable and also replace what we're consuming offshore. And this is really part of our strategy to maintain and become one of the most efficient oil and gas-producing company offshore.

Moving on to the next asset, Alvheim. I think it's fair to say Aker BP continues to do an excellent job. We've seen 2 main things happening in Alvheim. First of all, through infill drilling, we've been able to reduce the decline of the production of the field in Alvheim. And secondly, we've seen new discoveries made, particularly in what we call the Frosk area. And we are just actually putting production to Frosk discovery, and which is currently tied back to the Alvheim vessel. So overall, really, I would say Alvheim continued to exceed expectation, and a great, great job from our friend at Aker BP in operating this field.

And despite the fact that the field is relatively mature, we continue to have relatively low operating costs per barrel produced.

Moving on to Johan Sverdrup. I think this slide and all these figures, you're very well familiar with those figures, [fields] 2.2 billion to 3.2 billion barrels of oil equivalent. And of course, I will not go into the details of all these other figures, which you're well aware of, but, most importantly, we came onstream on the 5th of October. And since we came onstream, the ramp-up has been better than anticipated. Today, the field is exceeding 200,000 barrels of oil per day, and we anticipate to have 8 wells up and running by the end of the month, end of November.

By that time, 80% of Phase 1 production should be achieved, and the remaining 20% to reach 440,000 will be achieved by the drilling of 2 to 4 new wells, which will be reached by midyear of next year.

Also, in terms of OpEx, record low OpEx at below $2 per barrel and also a very record low carbon footprint at below 1 kilogram per CO2 per barrel produced. So really, Equinor has done a phenomenal job, and Johan Sverdrup will continue to be a simply phenomenal field.

The next slide is -- it's actually a summary of what I just mentioned. We are currently producing from 5 wells exceeding 200,000 barrels of oil per day. We anticipate the 8 wells, as I mentioned, by the second half of November, by then, we will be at 80% of plateau production. And then we anticipate 2 to 4 wells to reach full plateau.

Now we will see -- we will have a better idea towards year-end or beginning of next year in terms of the productivity of these wells, and we will have a better idea of the necessity to drill 2 or 4 wells to reach plateau. But overall, very pleased with the progress and very pleased with the work that Equinor is doing offshore on this phenomenal field.

On the next slide, this is a summary of the pipeline on new projects, as I mentioned, 4 projects that have been committed or sanctioned: Solveig with first oil in 2021, early 2021; Rolvsnes, the basement play, the extended well test, which will come on stream on the second quarter of 2021. Edvard Grieg, as I mentioned, the infill drilling has been sanctioned, and we will be starting drilling in mid of 2020. And for us, Frosk area, the first production, first well to be put on stream, which is currently producing an excess of 10,000 barrels of oil equivalent per day. So also very pleased with that.

And beyond that, we have 4 other projects which are on the pipeline, which we're currently at different stage of maturity of their appraisal or moving towards commerciality or trying to establish commerciality.

Moving on to the last -- my last slide before I hand over to Teitur, this is on the organic growth. We had a very busy year overall. We drilled 15 wells. 5 discoveries were made and 2 appraisal successes. I would say that is good. What is perhaps less exciting is that the reserves or the net resources addition were relatively small, 10 million to 50 million barrels of oil equivalent. But I remain very confident that if we continue to have good level of activities, we will eventually find larger discoveries.

The Norwegian continental shelf still remains an extraordinary place to explore, and we will be busy in pretty much from North -- the northern area of the NCS to the southern area of the NCS. And this year alone, we still have 3 really interesting wells to drill, targeting significant resources.

And next year, we'll be more explicit during the Capital Market Day. We will continue to have some of the busiest ever years in exploration for the company.

So overall, I remain confident that the organic growth is very much alive, and we will succeed.

So with this, I'll hand over to Teitur on the more financial side. So over to you, Teitur.

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

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Okay. Thank you very much, Alex, and good morning, everybody.

So we will start here with our normal format of showing the key financial highlights for the quarter and also for the first 9 months. And as Alex said already, the operational performance has been exceptional again in the third quarter, actually having a production efficiency of 100% on Edvard Grieg in the third quarter and close to 96% on Alvheim. So that has obviously driven production numbers to above upper end of our guidance of 82,700 BOE per day for the quarter and 79,200 for the first 9 months.

Oil prices were somewhat volatile during the third quarter, but we averaged $62 Brent, and I'll come back on a later slide to benchmark that against how our realized prices performed against that.

And as Alex said, on operating costs, again, industry-leading metric for us, below $4 for the quarter and $4.31 for the first 9 months. And we will retain the full year guidance at $4.25, as has been our guidance throughout the year.

Operating cash flow, EBITDA, also very strong, $380 million for the quarter on operating cash flow and $411 million on EBITDA, and over $1.1 billion of operating cash flow for the 9 months and over $1.2 billion on the EBITDA generation. Both of those numbers exclude any of the gains from the JS sale.

Free cash flow, as Alex mentioned in his opening slide, over $1.1 billion for the first 9 months. We'll come back on that, but that's obviously significantly impacted by the proceeds from the 2.6% sale of Johan Sverdrup, which completed at the end of August and a similar impact in third quarter alone of $950 million, net results for the quarter of $520 million post-tax and $670 million for the first 9 months post-tax.

And we will introduce now our new reporting metric, which we call adjusted net results. This is to try to better reflect the actual operational performance of the portfolio, where we strip out one-off items such as FX and asset sales. And on that metric, we had $45 million for the quarter of net profit and $174 million for the first 9 months.

Flipping to the next slide and just looking at operating cash flow and EBITDA compared to the same period last year. If we start off on the 9 months, as you can see here, we are down 16% on EBITDA compared to 9 months last year and down 18% on operating cash flow. And that's really been driven by 2 main items, as you see in the table above both the graphs. Realized oil prices are down 11% for the same period -- compared to the same period last year. And sales barrels, so not to be confused with produced barrels, but the sales barrels were 79,900 for the 9 months this year compared to 82,100 for the 9 months last year. So that's a drop of 3%.

And you will also see on the current taxes for the operating cash flow metric that those current tax charges in the income statement are higher in the 9 months this year since the same period last year, we still had some tax losses available on the corporation tax in Norway, whereas none of those were available for the 9 months this year.

And looking at the third quarter, very similar drivers, of course, realized oil prices down close to 20%, for the -- or based --compared to the same quarter last year. Whilst sales volume's up 10%, we were over-lifted as we preannounced to the market. So we lifted 85,000 barrels oil equivalent for the quarter compared to 77,300 barrels per day lifted in the quarter last year.

So that drove EBITDA down 14%, and operating cash flow was down 13%.

Then looking at the next slide and touching upon the free cash flow generation, which is a key metric that we report against, and you can see here very healthy free cash flow increases compared to the 9 months last year, 128% up. But obviously, a big chunk of that has been driven by the sale of Johan Sverdrup, where we received net proceeds of $959 million from Equinor at the end of August. And that was made up of $910 million, which was the sale consideration with the effective date of 1st of January.

We then received some interest on that consideration from 1st of January and also some repayment of CapEx since we've been funding 22.6% of CapEx [off] the completion at the end of August. So Statoil repaid us some of that, 2.6% of that, which meant we received $41 million repayment of CapEx we had laid out. And then some working capital adjustments as well. So in total, $959 million.

So if you strip out the impact from the JS sale, we still generated close to $160 million of organic free cash flow, if you like, for the first 9 months. And that also includes our working capital buildup of close to $60 million for the 9 months. So if you exclude working capital buildup, it would be roundabout $215 million of free cash flow generation for the 9 months.

And a similar story for third quarter, again, impacted heavily by the JS sale. So if you strip that out, we were negative free cash flow of roundabout $8 million, excluding the Johan Sverdrup sale proceeds. But, again, in the third quarter, we also had a big working capital build of $93 million. So if you ignore working capital movements, the organic free cash flow in the quarter was roundabout $85 million.

And then looking at net results and also the adjusted net results I introduced in my opening slide. So looking just at the phase of the income statement, which are the bars you see here, you can see that net results is going from -- for the 9 months from $323 million up to $670 million. And again, that was impacted by the accounting gain we booked on the sale of Johan Sverdrup, which we preannounced to the market was $757 million.

But if we adjust -- if we look at the adjusted net result, whereby we would adjust for the gain on Johan Sverdrup, as you can see in the text box there; and also adjusting for the FX loss, most of which is noncash and relates to revaluation of intercompany loan balances of $237 million; and also the loan modification charge, which we are unwinding as a result of the loan gain we booked in the second quarter last year when we amended the terms on the RBL; and the tax effects from all of the above, then we get an adjusted net result of $174 million compared to -- on the same metric for the 9 months last year, $220 million or a drop of 21%. So fundamentally, that's then driven by lower oil price realization and also lower sales volumes and also higher exploration costs expensed in the 9 months this year compared to last year.

And we do the same exercise then for the third quarter. We posted $520 million, including the gain from JS sale for the third quarter. But if you, again, do the same netting out to get an adjusted net result, we reported $45 million, which is a 40% drop compared to an adjusted net result for the third quarter last year, driven, again, by lower oil price realization and also higher exploration costs and also generally some higher finance costs relating to the share redemption transaction that we executed at the end of -- or beginning of August during the quarter.

So then looking at the oil price realization, the way you read this graph is that the top of the bar is the oil price realization that we achieved during the quarter. And you can see here what we achieved was $61.44 in the third quarter, so slightly less than the average Brent price for the quarter of $62 a barrel. And that was mainly relating to the timing of our lifting. So whenever we do a lifting, the pricing is the 5-day average after that lifting. So you're somewhat dependent upon what the Brent price does over those 5 days.

And the timing of our liftings has been less than optimal when you compare it to the previous 2 quarters when we actually achieved an oil price above the Brent price. But despite that sort of timing issue, we still achieved good premium on the Grane blend and also the Alvheim blend for our liftings. So again, on average, we [had] a premium to Brent for the liftings that we did in the quarter.

And then the blended oil and gas price. Gas prices have been very weak in Europe in particular. So whilst we don't produce a lot of gas, but when you blend that in the BOE equivalent price, we achieved for the quarter was $57.65.

And then looking at our operating costs in the normal format that we tend to present this in, you can see that the base OpEx continues to be extremely stable. So our operating team in Norway is doing a great job on keeping these costs in check. I guess the big moving part here has been that we had very low OpEx projects during the quarter. In the first and second quarter of the year, we had certain maintenance done on our turbines in Edvard Grieg, which drove up that cost. But during the third quarter, as you can see here, that has been kept at an absolute minimum, which is also why we achieved close to 100% production efficiency on Edvard Grieg for the quarter.

Tariff and transportation costs are slightly up, and that's really driven by how we sell the Alvheim cargoes in particular depending on whether we sell free on board or deliver it to the customers. And when we deliver the cargoes to the customers, we are obviously [picking off] [the transportation element of such a delivery. And that is what's driving up slightly the tariff and transportation costs in this quarter compared to previous quarters. But the flip side to that is, of course, that we are also achieving a higher realized price on the Alvheim cargoes because it's delivered safe.

Then going to the next slide and looking at tax. So when you look at the income statement, we have reported a relatively low effective tax rate of 46%. And that has mainly been driven by the fact that the accounting gain on Johan Sverdrup that we recognized in the third quarter of $757 million is a post-tax accounting gain. So there's no impact on our income tax charge from that sale. And that's been somewhat offset by the FX loss of $237 million, which also is mostly nontax. So when you blend those 2 items into the pretax numbers, and you don't have any impact on the income tax element of it, then the effective tax rate turns out at 46%.

But then looking at the adjusted results that we report when we net out the JS sale and also the FX impact and the unwinding of the loan gain we posted last year, then you can see that we get on the tax rate an adjusted tax rate of 77%, which is roughly in line with what you would expect with most of the tax generation being in Norway at 78% tax -- effective tax rate.

I think it's also worth highlighting here that in terms of our tax installments in Norway, what you should expect during the fourth quarter is 2 tax installments of NOK 170 million per installments, so NOK 340 million of tax installment relating to our 2019 current tax. That's roundabout $37 million on current exchange rate. And in addition to that, in the fourth quarter, we are also due to pay a catch-up tax installment relating to our 2018 current tax of roundabout $55 million. So you will see in our cash flow statement for the fourth quarter a somewhat increased cash tax payment element.

And then for the first half of 2020, we expect to do further 3 tax installments relating to our 2019 tax due, and those 3 installments will amount to roundabout NOK 510 million or roundabout $57 million during the first half next year. And we also expect during the fourth quarter this year to be running out of tax losses on the special petroleum tax element in Norway. And therefore, on the income statement for the fourth quarter, you should expect somewhat higher current tax charge compared to the previous 3 quarters we've seen this year.

Then looking at the cash flow generation for the first 9 months. The cash flow from operating activities came in at just below $1 billion, $985 million, and the cash flow on investing activities at $826 million. So that generated organic free cash flow, as I touched upon earlier, of close to $160 million, which includes a working capital build of close to $60 million. So adjusting for that, as I said, it will be close to $216 million of organic cash flow generation.

And here, you see the impact on JS sale of $959 million, as I mentioned earlier. And to fund our share redemption scheme that we did during August, we drew additional debt of $682 million for the first 9 months. And we paid out dividends of $250 million for the first 9 months, which is effectively 2 quarterly payments.

And here, you see the share redemption, the 16% cancellation of shares of just over $1.5 billion of share buyback effectively, leading to a cash build for the 9 months of $29 million.

And in terms of liquidity for the company, it's still at very healthy levels. Our net debt, it was just below $4.1 billion at the end of the third quarter. And we have credit lines in place of $5 billion, so that leaves a headroom of close to $1 billion of available liquidity for the company.

Then on guidance, as you've seen in the report this morning, and as Alex mentioned, we are upping the production guidance now to 90,000 to 95,000 barrels for the full year. OpEx, as I said earlier, will be retained at $4.25, and we are reducing our CapEx guidance, again, down to $730 million from the previous guidance of $785 million.

This further reduction in CapEx is driven by 2 things. Really one is phasing -- some phasing on the Solveig and Rolvsnes and the Johan Sverdrup projects and also some further FX savings given the continued weaker NOK. A lot of our CapEx is NOK-denominated. So looking at this saving from $785 million down to $730 million, roughly 1/3 of that is FX-related saving, and 2/3 relates to phasing where those costs will then go into 2020. And our E&A expenditure has been retained at $325 million, which also was the guidance we issued at our second quarter release.

My final slide is just a recap on our dividend policy. As you know, we have committed to a dividend of $1.48 per share as per the AGM in March this year. And as you can see in this table, we have now paid out 3 dividend installments for the year, two at $125 million each, which was based on the share count we had prior to [accounting 16%.] of the stock and the last dividend payment, which was paid out on the 7th of October, was paid out based on the lower share count of roundabout 286 million shares. So that equated to an absolute dividend payment of $105 million, but still keeping it at $0.37 a share dividend per quarter. And the final dividend payment will then be made in early next year. 9th of January is our estimated payout date for the last quarterly dividend relating to our 2018 dividend.

So with that, I will hand back to Alex for some concluding remarks. Thank you.

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

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Thank you, Teitur. Last slides for the day before we go into the questions.

Well, very pleased overall with where we are in terms of the performance of the business. And it's fair to say we continue to perform at or above expectations.

Starting with, again, John Sverdrup, first oil, very pleased, ahead of schedule and, as I mentioned, production ramp-up ahead of expectations. In terms of numbers, we see now John Sverdrup producing above 200,000 barrels of oil per day on a gross basis, and we anticipate by the second half of November to reach 80% of Phase 1 peak production. And we are still guiding a Phase 1 peak production at 440,000 by midyear based on the requirement to drill 2 to 4 wells.

I guess it's worth also mentioning again on John Sverdrup the free cash flow breakevens on Phase 1 between 2020, '22 for Lundin will be below $20 on a free cash flow breakeven. And by the time Phase 2 comes onstream, we will have free cash flow breakeven of $10, which are really exceptional numbers.

Edvard Grieg outperformance continues. And I think best way to [ally] this is also the fact that for the first time in the history of Edvard Grieg, and by the time we've completed our reserve certification, we will see the field exceeding 300 million barrels of oil equivalent, which is a phenomenal story considering that when we submitted the plan of development, we were 186 million at the start of the Edvard Grieg production.

Strong production performance continues, and that has led us to guide the full -- to increase the full guidance for the year to 90,000 to 95,000 barrels of oil equivalent per day.

And in terms of industry-leading and sustainable operating costs, as I mentioned, Q3 below $4 a barrel. And our long-term guidance remains really much industry-leading at between $3.2 to $4.2 per barrel in the long term, so really exceptional numbers and well below the norm of the North Sea operating costs.

And carbon footprint, with Johan Sverdrup being fully electrified, and by the time Edvard Grieg will be fully electrified in 2022, we will have emissions of below 1 kilogram of CO2 produced -- per barrel produced. So really exceptional numbers and way below the norm and the average in the world, more than 20x below those numbers. And of course, we will continue to be -- to continue to be -- to lead and be one of the most efficient producers in this planet.

We're continuing to delivering high and sustainable dividend and free cash flow yields. Our dividend today stands at about 5%, and free cash flow yields are about 11%. And in the long run, as I mentioned before, we anticipate for the years to come to post at $60, about $1 billion of free cash flow every year for the company. So very pleased also with the numbers.

And in terms of organic growth, as I mentioned, we have a pipeline of new projects, 4 projects ongoing, committed and sanctioned, and 4 others, a different level of maturity.

And exploration drilling, we still see 3 very interesting wells this year. And next year, we will be clear at the Capital Market Day, but you will see probably, again, in excess of 10 exploration wells to be drilled. So a very active exploration time for us. And as I mentioned, I very strongly believe in the overall opportunity and prospectivity on the Norwegian continental shelf. So very pleased with that.

I think on that note, I'll leave it to you, Ed.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [5]

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Yes, thanks very much, Alex. So we're going to hand over to you, the operator, who will take questions from the line, and then I'll take questions from the web afterwards. So I'll hand over to you, Hugh.

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Questions and Answers

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Operator [1]

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(Operator Instructions) And we go for 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 [2]

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Just given the exceptional performance at Edvard Grieg this morning in this quarter, I just wanted to ask a little bit about how sustainable you might think that is, and maybe just ask a little bit more around some of the work you've done at Edvard Grieg in terms of getting that uptime to that level. And I know you've had sort of turbine issues and other issues in the past. I'm just wondering what you think the total capacity is for processing on the platform now, and just maybe just get your thoughts on that going forward?

And then my second question, I guess on the electrification program and the hydro offset that you've announced this morning, just maybe just to get your -- just to get some clarity on what the incremental changes are on the electrification program versus the original plans to Johan Sverdrup Phase 2, the inclusion of Sleipner and Gudrun and any other fields as well, and maybe just what that might mean going forward. And I guess, just on what that could mean for CapEx going into the next 2 or 3 years as well, and whether you're able to give rough guidance on CapEx into next year.

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

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Yes, okay. I will take -- so let me start with Edvard Grieg. I think your first question was about how sustainable -- based on the performance we've done today, how this is sustainable. I think, first of all, Edvard Grieg, in terms of plateau, we've guided until the end of 2022 that Edvard Grieg will stay on plateau. And that's predicated, obviously, on the 2P reserves of Edvard Grieg. It's also Solveig and Rolvsnes coming in and, obviously, the infill drilling, which is -- will be part of the 2P. So this is based on -- the end of 2022 is based on a range. And it's possible that we will be able to exceed that range, but it really depends now, a, on the performance of the field itself, so being able to capture more 3P and move them into 2P. But that's -- time will tell. And the second one is obviously other exploration successes around the area.

As I said briefly, I believe the end of the exploration on the LTRI is far from over. And we still have some really interesting area to explore around the Edvard Grieg. A good example is what we did -- latest discovery north of Edvard Grieg. We made Tellus and Jorvik, which are becoming now an infill candidate. So we see -- in terms of the ability to extend the plateau, we see further potential.

Your specific question in your uptime, we track some very high uptime with 98%, which is really, really high. I think the electrification is probably a good example of how we can sustain those levels. What we see is that when you're moving turbines, we had some -- in general has been -- they've done a very good performance on the turbine for generation electricity, power generation. But what we see is that once you move into electrification, you can expect an improvement in uptime. It is actually easier to achieve higher uptime on electrified platform than it is with turbines-run platforms. So that, in the long run, I think, is positive for the field.

You asked capacity. I think we'll reach the capacity of Edvard Grieg. That will not change. We are now at 23,000 cubic meter, which is roughly about 150,000, and now it's more than increasing capacity through [further] debottleneck. It's about maintaining the capacity as high as possible for as long as possible. So that's what I would say in Edvard Grieg. So -- but I see a lot of opportunities in Edvard Grieg going forward.

Your general question on electrification, there's definitely -- first of all, this is driven by -- it's a business model. It's driven by the economics. What we see today is that we have a choice either to maintain the turbines in Edvard Grieg, as it stands today or fully electrify it, or we had a choice because we made that choice. And what we see is that actually is beneficial for us to electrify the Edvard Grieg for several reasons. Number one, CO2 taxes in Norway are increasing and will continue to increase. And this is the path of the world anyways, [is moving] certainly in Europe. So by electrifying the platform, we're reducing our CO2 taxes. Secondly, as I just mentioned, we believe electrification will increase efficiency when translated into uptime. So that will also have a business benefit. And finally, there is clearly an environmental impact, is that we will be able, through electrification, to reduce significantly the carbon footprint on the platform. That is also true on Johan Sverdrup. And the fact that there's excess capacity in terms of electricity is also true for the nearby platform such as Ivar Aasen, which we will provide electricity to, which will -- mainly coming from renewable and a partial electrification of Sleipner and some of the other platforms. So I think it's a good and sound business decisions, and I think it also has a significant impact on the carbon footprint.

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Operator [4]

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So we move over to the line of Michael Alsford at Citi.

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

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I've got just one, really. So it's just around the exploration activity. So you mentioned, obviously, the limited amount of resources discovered this year, and I'm just wondering if you could explore, Alex, a little bit more. Is it that you're taking on higher risk opportunities as you get bigger, I guess, is a function of your success, but do you need to target larger prospects to replace reserves post Johan Sverdrup reaching plateau or is it the nature of the maturing sort of nature of the Norwegian continental shelf? And related to that, does that mean, therefore, you need to start to look outside of Norway or think about inorganic opportunities to help to replace reserves post Johan Sverdrup reaching plateau?

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

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Yes. There's not an easy answer to all these questions you're raising, but I would say the following. Yes, the -- in terms of discoveries, we're tracking very well. We made 5 discoveries. They are, as I mentioned, relatively small discoveries on nearby existing fields. Now I really truly believe the Norwegian continental shelf is not as mature as perhaps the North Sea on the U.K. side. And we see a lot of opportunities, and we've put a lot of efforts in the last few years. We've increased dramatically our acreage position in Norway by about the tune of 60%, and we are now maturing all these areas. And we are now -- we used to be present in 3 core areas very much, very much the Barents and the Loppa High, the -- and then the Alvheim area and the Utsira High. But now you see Odfjell being active in more than 6 core areas.

And a lot of work is ongoing and a lot of activities. So I actually don't believe what's happening is just a reflection of what's happening on the NCS. I think time will tell, but we're obviously targeting larger prospects. But I think it's a mix. It's a mix between nearby exploration, which will have lower resources and more grassroot to high-risk exploration with higher resources.

So I think in our portfolio, we have all those. And I'm convinced over time, we will show that you can still continue to be successful in Norway. And discoveries of the size of Edvard Grieg are definitely possible.

And we are, after all, this year and next year, we will have one of the most active exploration programs ever in the history of the company, very much driven also by the fact that the cost -- the drilling of the cost in seismic, it's very competitive.

So I think time will tell. I think there's a lot of work ongoing, and I'm convinced that will lead to the success -- some of the success that we've seen in the past. And it's not the fact that what has happened today this year with perhaps low resources is not necessarily a reflection of what will happen in the near future.

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

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And then just around the inorganic and organic and whether you should stay in Norway.

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

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Yes, you have a follow-up, that's right. I mean, our main strategy maintaining organic growth on the belief of what we know we're doing and on the belief of the opportunities in Norway. So that remains number one activity. Inorganic, we know we are looking at every opportunity. Of course, if there is an opportunity to buy undeveloped or developed field, and we feel it's value accretive, we have the means of doing it. And we have the team to reviewing all this, and there will be opportunity. And if this is the right opportunity, we will do new acquisitions. But it will really be -- and will have to be really value accretive and in line with our business model to be also very efficient and low operating cost.

Then to your question on looking outside, I think, for now, we are happy where we are with Norway. We continue to be very active. So at this moment, it's not in the agenda to go outside Norway.

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Operator [9]

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We now go to the line of Yoann Charenton at Societe Generale.

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Yoann Charenton, Societe Generale Cross Asset Research - Equity Analyst [10]

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Since your CMD is just a few months away, I would like to focus on short-term matters, if you don't mind. On taxation, thank you for providing details on the upcoming cash payments. I will have 2 follow-up questions. How much of the tax losses pool related to the SPT remained as of end 3Q '19?

At the same time, would you be able to disclose basically how much of tax payments are related basically to full year '19 in the fourth quarter as well on costs?

Another topic, I realize that -- I mean, it's pretty clear you have outperformed on production quite strongly so far this year. At the same time, you must have benefited from the weakness in the Norwegian krone. So how come your guidance for operating costs per barrel has not been adjusted as we speak?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [11]

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Okay. Yoann, it's Teitur. On your SPT tax loss, I mean, it's not something we are disclosing what the tax loss was at the end of the third quarter. But suffice to say, as I mentioned in my presentation that, that whatever remaining taxes we have at the end of the third quarter will be fully utilized during the fourth quarter. And that's not only because of the Johan Sverdrup ramp-up, we would actually have fully utilized it in the fourth quarter even without Johan Sverdrup contribution. So you'll see in our Capital Markets Day what the tax loss was at the beginning of the year. I think it was roundabout $350 million or thereabout.

And then on the tax installments, so in the middle of every year, you provide a projection to the Norwegian taxation office based on your best economic assumptions, and you, therefore, lock in tax installment schedule at that point. And what we are installing now, you will see in the third quarter. For example, we made one tax installment of roundabout $20 million. These tax installments are actually NOK-denominated. So it's NOK 170 million per installment over 6 installments. So we will make another 2 installments in the fourth quarter. So as I said, that's NOK 340 million or roundabout $37 million or thereabout. And in addition to that, we will also make a tax cash payment relating to our 2018 tax build of roundabout $55 million. So those are the tax outgoings in the fourth quarter for the company.

In terms of your question on operating costs. I mean, when we -- you're correct. Most of our operating costs is NOK-denominated and, therefore, a weaker NOK is going to be beneficial to us as a dollar-driven company. But we still retain $4.25 per barrel as the guidance, and the reason for that is that we -- when we guide on OpEx, we assume all our cargoes are sold at free on board. So no transportation costs are included to get the product to the end consumer. Where, in reality, some of these cargoes are actually sold to the end consumer. So therefore, we do pick up the transportation costs of such cargoes. And as I said, the flip side to that standard, we also have a better realized oil price because of that. So that is essentially the reason why despite a weaker NOK than we had previously planned that we are retaining OpEx guidance at $4.25, which still is not too bad a number, I don't think.

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Operator [12]

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We now go the line of James Hosie at Barclays.

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James William Hosie, Barclays Bank PLC, Research Division - Research Analyst [13]

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Just a question on your renewables investments. I was wondering if your search for further projects is limited to Norway and/or hydropower. And do you think the $60 million you're investing through 2021 in this project is indicative of what further capacity additions would cost you?

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

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Yes. In terms of -- yes, as we said, that we're definitely going to invest in further project. And the whole idea was to link our consumption offshore, both on net consumption of electricity, both on Johan Sverdrup and Edvard Grieg, and offset the nonrenewable part and also offset what we're consuming. So in order to achieve that, you will see us over the years continue to make multiple investment. Is that limited to Norway? No, I think, mostly, we will focus in Europe in terms of investment. And in terms of the -- I think this last project of size, I think it's an indicative of what we will be spending on a yearly basis over the years to achieve our objective to offset and replace what we're consuming offshore.

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James William Hosie, Barclays Bank PLC, Research Division - Research Analyst [15]

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Okay. If I may have another question then. Just on capital allocation, if we look into 2020, clearly, I think the outlook is you can generate a lot more free cash flow next year on the back of Sverdrup production ramp-up and even in this oil price environment. So I mean, should we anticipating that dividend grows year-on-year even after allowing for the buyback?

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

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James, yes, I think the answer to that is yes. I mean, when we outlined the dividend policy earlier this year, we always stated that given that we're generating $1 billion free cash flow per year at $60, kicking off a dividend policy at roundabout $500 million on the old share count, and on the new share count that would only be $420 million per year, there is obviously ample room to grow that dividend over time. And that will be the intent of the company to do that. And what we also said is that even if oil prices fell below $50 Brent, we will still feel comfortable retaining dividend at the current levels. But clearly, where oil prices are today, I think the assumption should be that our dividend will grow year-on-year over the next sort of our forecast period, which is 8 years out.

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Operator [17]

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We are now over to the line of Sasikanth at Morgan Stanley.

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Sasikanth Chilukuru, Morgan Stanley, Research Division - Research Associate [18]

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Two questions, please. I was just wondering -- following the Goddo discovery, I was just wondering if it had changed your expectations of the resource potential [materially] . I'm just referencing it to your 2Q presentation, wherein you highlight the resource potential is greater than 250 million barrels of oil equivalent on a gross basis. But in 3Q, you don't highlight that anymore. You just stopped the [discovered] resources. I was just wondering if that's your expectations of Goddo.

The second one on -- was regarding the electrification. You've highlighted a couple of quite a few positives coming from the electrification of Edvard Grieg, I was just wondering, what are the risks associated with it? Does an outage possibly in the -- on the power cable essentially take off Edvard Grieg and Johan Sverdrup at the same time? Or I was just trying to understand what those are. Any contingencies in place just to have the power going on in case of any outage?

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

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Yes. Thank you. Starting with Goddo, first of all, in terms of the overall basement play, we remain pretty positive. I think how the [basement] play overall will play out is going to be really interesting to see after the result of the extended well test, which would really be an important part of the development of the basement. But we've seen quite a lot of positive moment on the basement, the Rolvsnes discovery, now we'll see the extended well test. We've seen also, through the wells we drilled this year, Jorvik and Tellus some interesting basement data, and we've also been producing partially from basement to Edvard Grieg. So overall, the story hasn't changed.

Now the Goddo was a discovery, but what we found is actually Goddo, contrary to what we believe, is separate from the Rolvsnes. So it's 2 different accumulation. So that has an impact on the overall resources. We will be guiding or giving more colors to it at the Capital Market Day, but overall still remains a very, very interesting and prospective area. In terms of the specific numbers and 250 million numbers, I think Nick at the Capital Markets or the exploration team will give more guidance, but remains still a very -- we're still very pleased with what we see. But I think the ultimate -- the ultimate approval will be the extended well tests in Rolvsnes.

Now electrification outage, I mean, electrification to date has been very reliable in -- as you know, Johan Sverdrup, we don't have a backup plan. There are no turbines. So it's solely through electrification. And by the time you Johan -- Edvard Grieg will be fully electrified, the plan is actually to dispose of the turbines. But -- if you look at the history in Norway in the power network and the availability, it is not a concern to us. And so -- and one thing on the -- I didn't mention, but one other advantages in terms of the electrification and also investing to renewables is that we have a natural edge on electricity since we will be both the consumer and the producer. And the operating costs in Johan Sverdrup will account 50% electricity. 50% of the costs -- of the operating costs will come from electricity prices. So that's another positive element.

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Operator [20]

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We are now over to the line of Anders Holte at Kepler Cheuvreux.

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Anders Torgrim Holte, Kepler Cheuvreux, Research Division - Equity Research Analyst [21]

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I had some technical difficulties, so apologies if this question has been asked before. But I just wanted to ask if you could just reconfirm that you're actually aiming to go below 1 kilogram of CO2 per barrel of produced oil and gas by 2023.

And the second one, just as, I guess, some guidance for you in terms of the cost of, say -- of the renewables acquisition that you announced today. How does that compare to your current tax payments on the CO2 emissions in Norway for Edvard Grieg?

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

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On your first question, yes, the answer is yes. I mean, we are already below 1 kilogram of CO2 emission per barrel produced in Johan Sverdrup, and that will stay. And in Edvard Grieg, we will achieve the below 1 kilogram of CO2 emission per barrel produced at the time Phase 2 at Johan Sverdrup is reached, which is end of 2022. And currently, Edvard Grieg stands at just below 5%. So, yes, those numbers is definitely the number we stand behind. And that's the -- what we'd like to -- they already achieved in Johan Sverdrup. On the second question...

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Anders Torgrim Holte, Kepler Cheuvreux, Research Division - Equity Research Analyst [23]

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That's the group level, right?

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

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That's -- well, yes, it's for Edvard Grieg and Johan Sverdrup. Alvheim is slightly higher being more mature, and -- but it's a small, small equity on the -- in the portfolio. So you could almost say it's a group level.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [25]

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Anders, on the CO2 tax, I believe the number we pay on Edvard Grieg on an annual basis at the moment is roundabout $8 million to $10 million. Don't quote me directly on that, but it's in that ballpark anyway. And certainly, what I can confirm is that within our OpEx guidance of $4.25 that all CO2 taxes are already included in that number. And of course, with the renewable project, the hydropower project, it will not work such that we can immediately offset and whatever power production comes from the hydropower against the CO2 tax on the Edvard Grieg. So we will still pay whatever CO2 is emitted from both Edvard Grieg and Johan Sverdrup going forward, which will be very, very low, of course, as we go forward. But we will still be subject to this normal CO2 tax on those emissions as every field in Norway will be.

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Operator [26]

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We now go to the line of Duncan Milligan at Goldman Sachs.

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Duncan Gregor Milligan, Goldman Sachs Group Inc., Research Division - Equity Analyst [27]

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I guess, congratulations on the startup of Johan Sverdrup. It's been a long time in the making. But just on that, now that the first crude per ounce is being delivered, can you give any indication in terms of the pricing that you're seeing for the [separate] barrels?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [28]

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Yes. No, I can't really disclose what the current initial cargoes have been selling at. I think it's suffice to say, they've been selling at a better price than we were expecting initially. It's also still early days as this crude sort of finds its place in the market space. But if this crude will trade similar to Edvard Grieg crude or the ground crude, and they're not too dissimilar, then I think what lies ahead of us is pretty promising in terms of how that crude will be priced in the market long term.

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Operator [29]

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We are now over to the line of Al Stanton at RBC.

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Al Stanton, RBC Capital Markets, Research Division - Analyst [30]

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Yes. Most of my questions have actually been asked. So -- and answered. Can I ask 2 unrelated questions? So just looking at the exploration side, if you ignore the wells in the -- each [area] , your average equity stakes are only around 20% or 22%. I was wondering if next year you'll be telling us you're generally increasing your stakes on average to increase the bang for your buck.

And then the other unrelated question is, can you give us any guidance on your business interruption insurance in terms of any significant excesses? Or what would happen in the event that Johan Sverdrup went down?

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

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Okay, I'll take the first question. In terms of the equity exposures, I think our aim has always been to be between 30% to 50% equity stake and to be operator. In average, some we have lower equities such as the -- around the Alvheim, and that's historical. But if you look at the acreage and some -- particularly some of the new uppers, we're picking up more and more operating assets with higher equity. So that should give you the comfort that we'll have a greater exposure to the barrels.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [32]

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Al, it's Teiter. On business interruption insurance, so as I think you know, we have business interruption insurance in place already on Edvard Grieg, and we will have it on Johan Sverdrup. Also, we've already been out in the market and placed that policy. And I believe it will kick in from either November or very early next year. That's still to be confirmed. And the policy we have on business interruption insurance is really to provide a protection mechanism to the liquidity position of the company going forward. It's not really meant to fully replace the profitability of the business, but more, as I said, as an insurance against liquidity, potential liquidity issues. And it's on that basis also that we have entered into the business interruption policy on Johan Sverdrup itself.

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Operator [33]

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We now go to the final question from the phones, for sure, and that's over to Matthew Smith at Bank of America.

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Matthew Smith, BofA Merrill Lynch, Research Division - Research Analyst [34]

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I'm afraid I was having some slight technical difficulties earlier, so would you mind just quickly repeating what you're able to say on the timing of the 2 to 4 further wells required for Sverdrup plateau?

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

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Yes. I mean, we -- the drilling will start towards year-end. And then we're stating that we'll only require 2 to 4 wells to reach plateau of Phase 1 at 440,000. And the guidance hasn't changed for these 2 to 4 wells, is that we assume mid-year 2020 to reach the 440,000. The only thing that can change is eventually depending on the number of wells we will require. Is it 2? Is it 4? Or is it 3? And I think as we're getting more production data, I'm sure Equinor will be able to then to give a revised guidance next year. But for now, the guidance remains midyear of this summer to reach plateau.

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Operator [36]

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Okay. Back to you for any questions from the web.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [37]

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Thanks very much, Hugh. We have a couple here. The first one's from [Pasco Mayora]. It's a question on the dividend. Just wanting some clarification as to why the dollar amount dropped this year post the Equinor transaction. And what will you think about dividends going forward?

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [38]

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Yes. I mean the dollar amount per share has not dropped, it's $1.48 for the full year. The reason why the absolute dollar amount drops is because we have canceled 16% of the shares. So that's the simple answer to that. And the other question was in relation to...

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [39]

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What we think about it going forward.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [40]

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Yes. I think we can just reiterate what we've said, is that within our free cash flow guidance of $1 billion free cash flow generation per year, over the next 8 years at $60, there is a very good headroom to grow that dividend over time. Because if you look at the share count you have in place today, the current $1.48 dividend per share equates to $420 million of absolute dividend paid out. So that gives you a feel for what sort of capacity we have in terms of growing the dividend over the next 8 years or so going out in time. And the intent will be to grow it annually.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [41]

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Thanks. And the next one's from [Marius Lawrenson]. Is it more profitable to do the investment in hydropower direct with Sognekfraft or going through a PPA agreement to purchase 0 emissions of electricity from the market, what...

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [42]

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Well, our approach to this was -- as Alex has already mentioned, is that we will purchase electricity off the grid to power Johan Sverdrup and later on also Edvard Grieg. And those will be purchases off the greatest spot price. And therefore, for us to invest in hydropower projects, which are also selling at spot price, makes sense to us because that's how we create the financial hedge that we've been seeking. So we are very comfortable with that setup. And the intent from us will be to debt finance most of this project with a new external debt facility. So this will not impact the liquidity hedging we have within the RBL for our oil and gas business. So as such, we see this as good capital allocation and good equity rate of return from this project.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [43]

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Thanks. So the last one from the line is from [Theodore] from [SB1]. It's a sort of general question on the strategy post first oil at Johan Sverdrup. Are we going to -- and is organic growth continue to be the main driver of the business? And then on -- the next question is on Sverdrup plateau. Is there any chance of it reaching plateau earlier than we were guiding currently?

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

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Yes. In the organic growth, the simple answer is that definitely your main strategy remain organic growth. And that's -- we've created a lot of value on Lundin Petroleum by following that strategy. And we believe this will continue. We believe the Norwegian continental shelf still has a lot of opportunities. And we've worked really hard. The team has worked really hard in the last 2 years to build up a large acreage position, and we will see the results in the coming years. And more operating average -- operated acreage with -- saw good equity on each of these assets. That doesn't mean that we're not going to be looking at inorganic acquisition. But as I said, that'd have to be -- we'll have to -- it's based on the fact that we want -- that'd have to be very value accretive. But we're looking very actively also on that level, but [that] will be more opportunistic.

In terms of the plateau, and I guess, we -- I -- we mean plateau Phase 1, I think can we reach plateau Phase 1 earlier? It is possible, and it's really predicated on a number of the wells we will need. Do we need 2 wells to reach -- plateau new wells to reach plateau? Or do we need 3 or 4? It's very -- it's far too early now to make any comment on this, and we'll have to see the production of the first 8 wells. From there, we will acquire a lot of new information. And from that, we can then -- we'll have a better idea of the number of wells we will need new wells to reach plateau. But for now, we'll stand for the midyear as a guidance.

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Edward Westropp, Lundin Petroleum AB (publ) - VP of IR [45]

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Okay, thanks very much, Alex.

So with that, that concludes the presentation this morning. Thanks, everyone, for joining. If anyone has any questions or any -- need more clarity, please don't hesitate to drop me a line. Have a good day.

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Alexandre Schneiter, Lundin Petroleum AB (publ) - President, CEO & Director [46]

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Thank you.

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Teitur Poulsen, Lundin Petroleum AB (publ) - CFO [47]

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Thank you.