Orrön Energy AB (publ) (ORRON) Earnings Call Transcript & Summary

Thanks very much, everybody. Welcome, everyone, to the Q2 results of Lundin Energy and the Half Year Results. We'll follow the usual form, Alex Schneiter will take you through the highlights in the operations. And then Teitur Poulsen will take you through the financials, and Alex will summarize at the end. We're going to do questions from the conference call first, and then we'll take any questions from the webcast afterwards. So if that's all clear, I'll hand over to Alex.

Yes. Good morning. Thanks, Ed, and good morning, everybody. So well, let me get into the second quarter and the last 6 months right away, starting with -- on Page 2, and the highlights. I guess before I go into the highlights, we can say that the second quarter has seen 4 records. On the positive side, we've seen an historical record production for the company at close to 163,000 barrels of oil equivalent per day. We've seen also record low quarterly operating cost at below USD 2.4 per BOE. And we've seen also our emissions -- we were targeting below 4 kilograms per barrel produced and our emission were well below 3-kilogram per barrel produced. So 3, excellent record during the second quarter and what we can qualify as a difficult quarter, taking considers on the COVID-19 and the economic environment. And of course, the fourth record, which is less -- which was more a challenging record is obviously the oil price. And as you've seen in our reports, we've realized an oil price of just short of $25 for the second quarter. But I think to me, what was really pleasing and important is that this low oil price really show that the company is very resilient to low oil prices. And despite a realized oil price of $25, we've actually posted a positive free cash flow for the oil and gas operations. So very pleased with that. And it's a good proof that our business is very resilient to economic disruptions and low oil prices. On the corona crisis itself, we had no disruptions. There was a lot of attention on this subject and particularly on the operations side. But very pleased to say that we had absolutely no disruption on production during the second quarter of this year. I mentioned the free cash flow positive, which is in relation to oil and gas operation, we actually posted close to $20 -- $20 million on free cash flow positive for the second quarter. I think the other point that is important is the activities in the organic growth of the company, which really remain on the heart of our strategy. And you've seen that not only we have 4 ongoing projects, development projects, but we also have 8 new potential projects. And some of them will be accelerated, thanks to the uplift or the improvement of the tax and as you probably know, not only our liquidity has improved in the short-term due to the tax improvement and Teitur will say a few more words on this, but also, if you are able to submit a plan of development before the end of 2022, you will be able to actually benefit for this tax incentive. And this is significant. It's significant on the rate of returns and NPVs and there's certainly a focus today for us because we see several projects that can have great -- could become really great projects and great returns. So we'll say a little bit more later on. On the response to the oil prices, of course, we -- capital discipline has been in the forefront of our mind. And we've phased out some of the costs, and we've saved also cost, and this is in excess of $300 million. We also raised a new corporate debt of $240 million and of course, we took the prudent measure to reduce the dividend. If you -- plus improvement on the taxes, if you take all these items together, we've improved from the pre COVID to the post COVID situation over $850 million in our liquidity. So the company today, in my view, it is in a better position [ than ] actually was on the pre COVID. Moving on to the next slide, that's a highlight on the coronavirus crisis. I think the highlight really is that, first of all, we had no disruption, as I stated on the production. And secondly, of course, the safeguarding of the well-being of our people was on our forefront. And we've taken a lot of mitigating action to reduce the number of activities without impacting our production and that has worked really well. And I think the oil industry now has worked really well to cooperate and finding the right solution and the best solution today, I will finish on this to say that the offshore activity resumed to normal operations. And so far, I would say, I would consider this now all our projects and operations are going as planned. In terms of the resilience, as I mentioned, the market is the market. And then of course, we had quite a crisis in -- during the second quarter with probably the lowest demand ever after the Second World War and we have to be -- we had to face this crisis. But I think that, as I really highlighted the quality of the company, first of all, on our industry-leading operating costs, as I mentioned. And as you know, not only we're posting very low operating costs today, but this is sustainable over the long term and we don't see operating costs. We actually gave a guidance between $3.2 to $4.2 over a year on the operating cost, very much led by Edvard Grieg and Johan Sverdrup. The second point in terms of high-quality/low-cost is, of course, the -- our low cash-flow breakeven. If you take the next 7 years on average, or cash flow, free cash-flow breakevens are at about USD 15 per BOE. In actual fact, if you take these numbers post the onset of Phase 2, so from 2023, this $15 will go as low as below $10. So the company is extremely resilient to low oil prices. And that's very much led by high world-class assets and also, of course, low operating cost. On the liquidity side, I mentioned about the $850 million of improved liquidity for 2020. And I think I'm not going to go through each slide, Teitur can say a little bit more about it. And I think I mentioned the different part of the puzzles who makes up the $850 million so -- but in a very, very privileged position we are today as a company. Let me move on to the 2020 production. For the first half, we posted a 158,000 barrels of oil equivalent per day. And as I mentioned, the second quarter was actually a record production for the company, close to 163,000. That record was achieved despite the fact that in June, we already had the curtailment of production that was imposed by the Norwegian government and as you know, from -- until year-end, we have to somehow reduce our production. I would say the reduction in production due to the restriction are relatively small. And -- but we had to revise our guidance, and we are now targeting 157,000 barrels of oil equivalent per day for the full year guidance. And I think to highlight also the last point is that this is the 20th quarter in row that actually we posted at or above guidance in terms of production. So very pleased by the -- what the team has achieved and the operation in general, it's very, very good. In terms of operating performance and -- more an overall operating performance, what we've seen is, again, on the efficiency, very high-efficiency on Edvard Grieg and Alvheim. I mean we talked about 99%; this is absolutely world-class efficiency. And we've seen also high-efficiency on Johan Sverdrup, 91% despite the fact that Johan Sverdrup is, fair to say, still in a commissioning mode and it's not only -- it was only a few months ago that we started producing in Johan Sverdrup. And Johan Sverdrup has been absolutely brilliant. And in addition, we've seen the capacity of Johan Sverdrup increasing now to 470,000. We mentioned the operating cost and the full year guidance remaining at 2.8, which is really a quarter what you see in the North Sea, probably some of the lowest operating costs you see in our industry. And the final puzzle in terms of operating performance is obviously the carbon intensity. And I'm very pleased to see that not only we have achieved our targets, which was below 4 kilograms of CO2 per barrels of oil equivalent, but we went below 3 to 2.8 and we've seen that Johan Sverdrup is achieving very, very good track record in terms of emissions per barrel produced. And so those Edvard rigs. So we are well on our way to achieve our targets and our ambition to become carbon neutral by 2030. Let me move into the assets. I will start with Johan Sverdrup. I think in Page 7, it's -- those figures are well-known to the industry. But just to repeat, in terms of reserves, Johan Sverdrup today stands between $2.2 billion to $3.2 billion on a gross basis. Phase 1 now, as I mentioned, the capacity has increased and is standing at 470,000 that was achieved in April. Not only we have achieved plateau 2 months ahead of schedule, but higher than what was anticipated. And as a consequence, the full field production capacity has also increased and today stands at 690,000 barrels of oil per day. On Phase 2, and that's important considering the crisis we live in, and we're still living with COVID-19, but Phase 2 is on track and on budget, and so very pleased despite the uncertainties out there in the world that the project has progressed as per plan. And we still anticipate and there are no changes to achieve first oil in the fourth quarter of 2022 and as a reminder, that's been stated several times, but the full field breakeven stands at below $20 per BOE. So I would say Johan Sverdrup is really the field of the future with an absolutely phenomenal track record and phenomenal reservoir and field. And obviously, to mention very low OpEx below $2 a barrel. Overall, Johan Sverdrup has definitely performed above expectations. We've achieved -- I mentioned that 470,000 ahead of schedule and above -- and the 470,000 is above the anticipated plateau production. I think it's important to highlight that now we have well 11 that is on stream. And now we have the capacity test above and beyond 470,000. So plan -- we are currently working on a plan to -- for the next few months to test the capacity on Sverdrup Phase 1 and see if we can actually achieve rates above 470,000 barrels oil per day. So that's going to be very exciting to see. Reservoir is performing extremely well; it's an absolutely world-class reservoir. And I think over time, we're going to see some very positive news from this reservoir. And as I mentioned, we have now 11 wells producing. So we have capacity to go beyond 470,000 barrels oil per day. Moving on to the Edvard Grieg area and Edvard Grieg itself, I think the most important message to you today on Edvard Grieg is that based on the performance of Edvard Grieg, we've -- we are currently finalizing our reservoir dynamic reservoir model. And we definitely see that Edvard Grieg will have an increase in reserves, and we will have a further extension on the plateau, and today the plateau has been extended up to end of 2022 so we see already now that we will extend this. There will be further news coming during the autumn when we have finalized all the work. But it is very pleasing to see how this asset has performed over time. We are now at $300 million on 2P reserves, and we definitely see scope to increase this number. We will take the advantage of the shutdown and move back the shutdown to this year since we have -- we've been constraining production. We're going to move forward this shutdown so that next year, we don't have to plan another shutdown. On the -- we will also resume, or for the first time in Eastern Edvard Grieg has an infill drilling program, which is due to start in the Q2 of 2021. And of course, we are now well on our way to implement the full power from Shore, which, as you know, willing -- will bring Edvard Grieg to full electrification by the end of 2022 and will actually allow us to go even lower on our emissions as a company post-2022 to below 2 kilograms per barrel produced. The third item is on future growth. I think the story on the Utsira High and in particularly also Edvard Grieg is far from finished. We have the Solveig first oil, which is a subsea tieback to Edvard Grieg on -- due to common stream in the Q3 of 2021, and that's well underway, very pleased with progress. We have the Rolvsnes extend well test first half also in Q3 2021. And this is also progressing very well. This is a play in the basement between Johan Sverdrup and Edvard Grieg. And that production will allow us to decide to move to the next level to the full development of Rolvsnes and actually also being able to take advantage of the tax incentives, should we be able to submit the plan of development before 2022 for the full field development. We will see also Merckx, what we call Merckx exploration well in Q4, which is on the Western Flank down-dip from Solveig, a very interesting play. And actually, beyond that, there's still further exploration on the Edvard Grieg area. We haven't yet explored the Western Flank of Edvard Grieg and we have other projects such as Lille Prinsen which are potentially future tiebacks. So overall, very exciting. And that will allow us to maintain the capacity full for the -- for as long as possible. So overall, Edvard Grieg is performing extremely, extremely well. The next slide is it's more details in terms of the ongoing project, the tiebacks to Edvard Grieg. Solveig, as a reminder, is a subsea tieback development with a resource range between 40 million to 100 million barrels of oil equivalent and a very attractive breakeven oil price of below $30. Rolvsnes currently, the range stands between 14 to 78. But of course, this range will be very much dependent, and any upside, on how the extended well test will behave when we have the well on production. And as I stated, the current project, both projects are progressing well. I'm pleased with the progress. In the slide itself, you see actual pictures of the ongoing activities next to the Edvard Grieg platform for Rolvsnes and Solveig. Moving on to the third key assets, Alvheim, I think overall I would say Alvheim is performing also very well. In 2020, we have a plan to drill 2 further infield wells. And also importantly, we have the Frosk and the Kobra East/Gekko developments, which are planned to be sanctioned by mid-2021 but overall, and I will remain to that statement, Alvheim is progressing very well and it's producing well, and it's got -- it's also a very efficient production. But of course, it's compared to Edvard Grieg and Johan Sverdrup a smaller equity for us. In terms of the organic growth, that's really very exciting and a major focus for us. As I mentioned, we have 4 projects ongoing. And I think more importantly, the latest uplift in taxes, and particularly our ability to be able to take advantage of the tax uplift if you submit a plan of development before 2022, has been really a major focus in our company. And we see some very attractive projects. We currently have a preliminary estimate of a target of in excess of 120 million barrels of oil equivalent of resources but of course, as we go along the way, these numbers will be revised and there will be project that will be -- may be better, and there will be project in may not reach the threshold of commerciality. But very exciting, a lot of projects, and it's something we're focusing a lot on right now. And we'll add above and beyond the guidance in terms of production should this project go ahead. On the exploration and appraisal, this year we have a total of 7 wells. We drilled already 4 and made a really interesting discovery Evra and Iving which will be under -- will be appraised next year. This is another project that we'll be able to potentially take advantage of the uplift in tax that we could submit before the deadline of 2022. And we have 4 wells remaining. The fourth quarter, we'll see a lot of activity and explorations. And 3 out of 4 will be wells drilled in the Southern Barents Sea, very interesting wells with high potential and all in existing petroleum system, all in trend with existing discoveries. I'm thinking about Alta, but I'm thinking also about Castberg. So it's going to be a really interesting quarter from an exploration point of view. And we remain very active. The company is very focused on organic growth in Norway, and you'll see the company active through the whole Norwegian Continental shelf from the very north to the very south. Moving on to decarbonization strategy, I would say the punchline is that we are well underway to achieve our targets. You've seen the results in Q2, which are well below our target with the emission of CO2 per barrel produce of less than 3 kilograms. We are well on the way to achieve below 2 kilograms of CO2 per barrel produced by the time Edvard Grieg is fully electrified, and we're well on the way to achieve carbon neutrality by 2030. On the renewable side, the projects are on track. The hydropower project is now producing, and it's fair to say it so far, performance are above expectations. And the wind farm project in Finland is progressing well and according to plan and budget. So with this, I'll leave the floor to Teitur on the financial side. So here, we go. Over to you, Teitur.

Thank you very much, Alex, and good morning, everybody. So I think we can say the Q2 period has been a challenging one in terms of macro backdrop. But the key highlight we take away from it, though, is that our oil and gas portfolio still generated positive free cash flow. So that's just great testimony to the low-cost nature of our assets. The key highlights we emphasize here on this first slide is the sales volume was 172,000 barrels of oil equivalent per day. We were quite significantly overlifted in the second quarter. We had 21 oil cargoes sold. Our marketing guys have been doing a great job in what has been a very challenging backdrop in terms of getting all our cargoes sold and delivered to the market. We've been through the operating cost, as Alex said, a record low number of $2.37 per BOE, and we reiterate our full year guidance of $2.80 for the for the full year. Obviously, the Q2 number is somewhat helped also by record-high production and also a weak NOK during the period. CapEx investments of $221 million and renewable investments of $47 million. On cash-flow generation, we will come back to this in more detail later on, but the main headline numbers, CFFO of just below $900 million for the 6 months. And free cash flow generation of just over $380 million. And as we said, if we just look at Q2 in isolation, just on oil and gas, still generated $20 million of positive free cash flow before dividend payments. The Norwegian government took some fairly significant steps during the quarter to improve liquidity positions for companies in terms of a tax change. So this is quite material for us, $670 million over the period this year out to mid-2022. And we'll come back to that in terms of what the shape of that liquidity impact looks like as we look out over the next 2.5 years. And also what we announced this morning is we've now received a public credit rating from S&P, achieving BBB minus credit rating, which in the industry is categorized as investment-grade and thus, another sort of independent verification of the quality of our assets and the strength of our balance sheet. And this is clearly good news as we look forward into our refinancing options that we can explore over the next few quarters. So if we then go to the next slide and look at some of the key metrics in a bit more detail, we look at EBITDA and CFFO here on the first slide, so for the 6 months, just over $900 million of EBITDA generation, a 13% increase on the period last year. Obviously, prices, as we said, were weaker to the tune of 46% compared to last year. But sales volumes with Johan Sverdrup now ramping up significantly higher, 110% up. And for the quarter it's a slight drop of 19%, $335 million for the second quarter. Cash flows from operations are also up on the same period last year for the 6 months, just below $900 million, as I said. This has also been somewhat helped by a release of working capital of over $160 million with a drop in the oil price. That has reduced working capital balances somewhat during that period. And for the second quarter, we posted $260 million of CFFO, again, also slightly helped by a release of working capital of around about $20 million. And then looking at the next slide, free cash flow and net profits. So for the 6 months, before dividend payments we generated, as I said, $380 million which is already at the half-year point would more than fully cover our cash dividends for the full year in 2020. So we are way ahead on that; it was up 128% relative to 6 months last year, the investment levels in the first 6 months are slightly lower than the investment levels in the same period last year. And you see then for the quarter, there's a slight negative of $25 million of free cash flow. That's driven by the fact that the Leikanger hydro project in Norway completed in June. So we paid the consideration for that transaction in June, which meant we expensed $45 million, roughly, of renewable investment in the quarter. So without that, we would have been $20 million free cash flow positive. Adjusted net results, not too much change compared to the same period last year, just below $120 million in -- for the first 6 months and the reported income statement net results was negative $131 million, and that was driven mainly by a noncash FX loss of $230 million for the first 6 months. And during the quarter, we posted $51 million of adjusted net results, reflecting the underlying operational performance from the portfolio. But if we include, again, FX gains in the second quarter of $131 million, the reported net results on the income statement, just below $180 million for the quarter. If we then go to the next slide and look at realized prices. This has been much talked about for this particular quarter. And the reason for that, you can see in the bottom left hand corner here where we look at the future Brent curve, which is the blue part of this graph. And then you look at the Dated Brent, which is actually the reference points that our cargoes are being priced against and you can see there, particularly in early April, there was a huge discrepancy between the 2. Normally, these 2 lines are swinging within $0 to $1 to maybe $2 a barrel differentials. But in in April, we had up to a $10 differential on the Dated Brent versus the Future Brent. And perhaps some market players didn't sort of pick up this fact. And that's obviously put pressure on the realized prices in the second quarter. So you can see on the bars to the right that the realized oil price for our crudes that we achieved was just over $25, $25.78 versus a Dated Brent average for the period of $29.50. So we had a close to a $4 discount to the Dated Brent on the physicals of what we sold during the quarter. And if you then blend in the gas, gas prices remain extremely weak. So that takes the realized price per barrel of oil equivalent below $25 a barrel at $24.70. But the good news is that we've already seen during July and August that the cargoes that we have marketed and sold in that period, they've all sold at a premium to Brent. So that's our -- to premium to Dated Brent, I say. And you will also see on the graph, as we head into July that Dated Brent and the Future Brent are converging again in terms of pricing so that makes the macro environment much more favorable as we look forward. We are also announcing this morning that we got the CO2 intensity on our Edvard Grieg barrels independently certified now. We have a company called Intertek, so we are the first company to move into this product, and this will be -- should be a great help to those customers that we sell our cargoes to who have a very strong ESG focus because this will serve as an independent verification of our CO2 intensity of the barrels. And that will, in turn, clearly feed positively into the CO2 intensity of the refiners and eventually to the end products being sold. So the full chain CO2 traceability is -- with this instrument is being unlocked. So that could create some marketing opportunities for us as we move forward. Then on operating costs, we already mentioned the low unit operating cost of just below $2.40 for the quarter. And you can see here in absolute numbers, just over $41 million of operating costs. We down manned all nonessential personnel on the platforms during the COVID period. That has also reduced some of the OpEx. Some of that will be phasing, so coming back later in the year. And as I said in the introduction, also the NOK has been averaging NOK 10 to the U.S. dollar during the Q2 period. And given that most of our OpEx costs are not denominated, that's clearly pushing down our dollar absolute and unit costs. And as I said, we do reiterate our full year guidance of $2.80. But I think it's safe to say that our operational team in Norway have had a stellar job through this very difficult period to keep costs under control. Then we will go into tax, and we will have a few slides on tax, given the tax changes that we have had from the Norwegian government. So you see here, we had a total tax charge on the income statement of $360 million, split into $130 million of current tax and $230 million of deferred tax which then resulted in a negative post-tax result of $131 million for the 6 months. But if we adjust, as we normally do for the noncash FX items and certain other nonoperational items and look at what the underlying effective tax rate should have been, we have posted around about 75% effective tax rate on our operations. And most of that obviously relates to Norway. If we then home in on the current tax piece, which we then highlight on the graph to the right here you can see -- if we had remained with the old tax regime, we already posted in Q1 a current tax charge of $260 million. And if you hadn't had the tax changes, we would have posted another current tax charge for second quarter of $56 million, so taking the total current tax charge for the 6 months to above $300 million. But with the tax changes that the Norwegian government introduced where they allow 100% depreciation on CapEx against the SPT tax regime and also increased the uplift from 20.8% to 24%, that has meant that we have had current tax credits to adjust for during the period. And with these changes, the impact on the Q1 number is a credit of $80 million. And on the Q2 numbers, $107 million. All in, $187 million of current tax credits on this which, therefore, results in our first half reported current tax number of $130 million. Obviously, the flip side of this is that the deferred tax charge has increased not proportionately, but it has increased by around $150 million. Then looking on the next slide and examining how this will impact our actual cash tax installments, you can see on the left of this slide, the actual tax installments we have made during the first half, amounting to $52 million. We have now locked in with the oil taxation office in Norway, the next 2 tax installments in Q3 and Q4 this year of $36 million and $72 million, respectively, in addition to a tax installment of $265 million, which actually relates to our 2019 tax bill. So in Q4 this year, all in, we will pay close to $340 million in cash tax. And then when we look forward into the installments we have to make in the first half next year, which will relate to the full year tax return in 2020, we're showing here 3 sensitivities on different oil price assumptions for the second half 2020. So you see a $35 Brent, we would estimate to make another $138 million of tax installments in spread between Q1 and Q2 next year, and at $50 realized prices for second half this year we will pay another $454 million over Q2 and -- Q1, Q2 next year, in addition to the $108 million we will pay in the second half in 2020. And you can then also see at the extreme right, if we assume a realized price for second half of $20 a barrel, we will actually get tax credits from the taxation office in first and second quarter next year, in total just below $180 million of tax credits. So this gives pretty good visibility in terms of cash flow impact on the taxes we have to pay for the next 4 quarters. And then this last slide on tax. This is the impact we will have on the left here, you'll see the impact from the tax changes on our current tax charge, both in 2020 and 2021, as I said in the intro, in total around about $670 million, less current tax incurred over those 2 years based on our current CapEx estimate for 2020 and 2021. Of course, most of this is a phasing impact in that you can depreciate the CapEx 100% in the year you incurred it, in 2020 and 2021. That obviously means that you have no tax shelter from that CapEx as you then go forward from 2022 onward. And that means that you have, therefore a higher tax bill to pay than we otherwise would have had, but still the $645 million. So there's a debt, but there's an absolute tax saving of around about $25 million, because of the higher uplift on the CapEx we spend in 2020 and 2021. And because of the phasing of the tax installments that we went through on the previous slide, the liquidity impact of this is actually spread over 3 years, if you like, into the first half of 2022 as well. So here, you see how that liquidity impact will look like in terms of phasing. Then looking on the cash-flow statement itself and also the liquidity position of the company, if we start with the cash flow statement -- so as you said, excluding working capital movements, first-half cash flows from operations, $735 million. And then the release of working capital of $163 million. So in total, CFFO, just below $900 million. Investment levels in oil and gas, $440 million for the first 6 months. And as I mentioned, the renewables, the hydropower project in Norway, the deal completed in June. So in total, we have invested $77 million of renewable CapEx in the first 6 months. So still generating $380 million of free cash flow pre-dividend for the first 6 months. Dividend payment is $176 million for the 6 months and then a debt reduction of $221 million during the period. Then looking at the liquidity position, so we are posting a net debt position at half year point of $3.8 billion. We remain to have credit lines commitments in excess of $5 billion as of the 30th of June. So that leaves over $1 billion in liquidity headroom as we stand. But of course, as we have documented in the past, the RBL starts to amortize as we head towards the end of the year with $750 million of semi-annual amortization commencing from the end of this year and then every half year going forward. So therefore, the RBL commitment will drop down to $4 billion at year-end. And I think it's fair to say on the refinancing of the company, we're still monitoring the situation. We still have a window of refinancing either in the second half of this year or in the first half next year. And that will be entirely market-dependent as to when we decide to move forward with such refinancing. Obviously, the objective is to achieve as competitive rates as we can, and we need the right market conditions to achieve that. Then a quick recap on the guidance. The latest guidance is effectively unchanged, both relative to Capital Markets Day guidance, you can see that the midpoint of Capital Markets Day was $155 million, and we are now guiding $157 million, honoring the production cuts that the Norwegian government has introduced. And OpEx guidance, as we've said, $2.80. CapEx remains at $710 million for oil and gas, and $140 million for G&A expenditure for the full year. And the decommissioning costs mainly relating to the Brynhild decommissioning operations, $45 million, and then $90 million of renewable investments. And this is my last slide, just a recap on dividend. As you know, the dividend we have in place is $1 per share for -- for the 2019 dividend being paid out during 2020. And you can see that in early July, we went ex dividend and that $0.25 quarterly dividend was paid out around about 8th of July with the next upcoming dividend going ex dividend on the 1st of October, and we expect that to be paid out around about 7th of October in 2020. So with that, I will hand back to Alex for some concluding remarks.

Thank you, Teitur. Just one last slide. So definitely Q2 has been a challenging quarter, particular when thinking about the oil price policy from an operation point of view with the COVID-19. But I think these challenging times have really shown and highlighted how resilient the company is on a downturn and on a low-price environment. And at the same time, we've shown record performance when you look at our production, operating costs. So it has been, yes, challenging, but also very interesting, and it really highlighted the strength of the company. Specifically, to summarize, we've seen strong production performance through the 6 months in the second quarter, at the upper end of the guidance. We've seen also during the second quarter, record low operating cost and emissions below our target and also very high up-time. We've also seen the company mitigating the potential impact of the coronavirus with no disruption on production and all our projects on track according to our plan and budget. You also see that not only the existing ongoing development projects are going according to plan, but also we have now a pipeline of new projects, some also improved through the tax incentive that was announced a few months ago. And on the exploration appraisal, we continue to be very active and continue -- we're going to continue the company to certainly target about 10 exploration well per year, and we will see the fourth quarter of this year the activity level to increase, particularly towards the Southern Barents Sea as a starting point. But during the year, it will be across the whole Norwegian Continental shelf. Teitur highlighted quite well the increase of liquidity and through other phasing and savings and also obviously through the tax incentives. And finally, high-quality resilient business that has definitely been shown over the performance of the last few months. And this is perhaps best highlighted that we are free-cash-flow breakeven. And as I said, for the next 7 years, we anticipated an average of $15 for breakeven and post the onset of Phase II, as low as below $10 a barrel. So that really is a testament of the resilience of the company going forward. So overall, really pleased with where the company is and where we're heading. And with this, I think we'll leave it to the floor to the questions.

[Operator Instructions] We have one question from the line of James Hosie from Barclays.

Yes, a couple for me. First off, obviously you highlighted Lundin's first public credit rating, investment grade. So I'm just wondering what you plan to do with this now. Meaning is this the point when Lundin diversifies its debt structure away from the RBL? And then a second question is on your decarbonization strategy. Obviously, you've got a carbon intensity of 2.8 year-to-date. That's already well below the target of under 4 for 2020 through '22. So really is the target you've set for the next few years just not ambitious enough?

Yes. James, on your first question on credit rating, I mean, we just felt it was a prudent thing to do. And clearly, with the refinancing coming up in whatever shape or form that will take, this is going to serve us well as we go into that process. And in terms of the options we have available, I mean we are not going to go refinancing into our, sort of, the standard RBL format again. So if we go down the road of refinancing through the banks, we are aiming to achieve more of a corporate type of facility with greater flexibility than what the current RBL gives us in terms of running the business. Well clearly, option -- bonds is another option, and it always has been. It's always something we have considered and we'll continue to consider. But I will say, where we stand today, the most likely route remains a new corporate facility as an initial starting point at least, and then we can assess whether we do bonds or not a bit further down the road. But effectively, we have both those options available to us. So -- and I guess the thinking will then progress as we go into the second half of this year or first half next year. As I said, it very much depends on the shape of the market as and when we decide to launch the refinancing.

Yes. On your ambition target in terms of decarbonization, I think we've just started with Johan Sverdrup, and we're seeing now the real numbers on Johan Sverdrup, which are very low. And I think we -- this year is going to -- we're going to let go this year and see how the whole year -- the whole-year performance on Johan Sverdrup. And then we have also Edvard Grieg that will be fully electrified by 2022. So of course, if we feel that we can upgrade our targets, we will. And -- but I think we need a little bit more time to monitor the current performance. But my feeling is that there is room to maneuver here. And obviously, our ambition is to reach the -- in terms of emission per barrel, the most -- the best possible number based on facts and something we can sustain so it's possible we will be able over time to modify our targets. But we need a little bit more of production and performance both from Johan Sverdrup and Edvard Grieg. Regardless, I mean if it's 3 kilograms or 2 kilograms, I think we will be about 10x lower than the world average. So -- but our ambition is to do the best possible, for sure.

Our quest next question came from the line of Alwyn Thomas from Exane BNP Paribas.

A couple of questions from me. Firstly, given a little bit more visibility now with the tax regime and your potential developments, are you able to give rough guidance on where you think development CapEx will be for 2021? And potentially, what some of the tax implications could be around that as well? On low-enough oil price would you expect to get an exploration rebate next year? Perhaps -- well, perhaps following on from that as well, could you possibly comment on what you -- what your outlook is for shareholder returns now, again, with that sort of surety, whether you'd like to start increasing the dividend from next year or maybe just some commentary around what you're thinking there would be helpful.

Yes, on the CapEx, and particularly for the new projects, I think this is a bit early days. We have some internal discussion ongoing, and there's a lot of work ongoing. I think we will become clearer during the Capital Markets Day probably next year. And the -- as you know, currently, our CapEx profile is decreasing dramatically and is very much led by Johan Sverdrup Phase 2. These other projects are mainly subsea tiebacks. So we're not going to see the same CapEx level that we've seen through the Johan Sverdrup days. But we will give more lights probably during the Capital Market Day and update our CapEx profile as required. But it's -- but just to be clear, it's not going to be to the level that we've seen in the past, led by Johan Sverdrup. In terms of shareholder return, I think your question was very much related to the dividend. I think the -- we said it all along is we want to return cash to shareholder. And we want dividend to be sustainable. Of course, this year has been a very exceptional year. We had to reduce by 45% of dividend. And we did it for a reason to be prudent. At that time, we really didn't know what was happening and how the economy were going to behave. So we felt prudent to emphasize the -- or put our focus on the liquidity of the company and the strength of the balance sheet. Now as the COVID-19 improves and oil prices improves, of course, our intention is a, to continue to pay dividend, that's a given, but also to increase dividend over time. But of course, we need to also see -- we still are living in certain time, so it's -- we'll have to see how things are evolving in the coming months.

Alwyn, maybe I could just also add on the tax implications from the CapEx. The guidance we're giving here does not really include any additional CapEx from these 8 projects we potentially are going to sanction. So the $670 million liquidity impact really only relates to the positive CapEx commitments we have as of now, being Edvard Grieg tiebacks and Johan Sverdrup really. So none of that is reflected in the tax indications we are guiding on this morning.

Okay. Maybe I could just ask, is it fair to say that there should be an uptick in exploration activity? And is that partly spurred by the tax incentives to get more tiebacks to get more development opportunities signed off by 2022?

Well, I think it's going to be a challenge to exploration to get project sanctions within 2022. So the projects we're talking about here are more -- projects which are more mature than at the pure exploration stage, because the time frame wouldn't really allow us to progress projects within 2022 on the exploration front.

Yes. I think it's -- this is related to existing discoveries, other discovery are already being appraised or on the process of being appraised. That's really the project that we're talking about.

Our next question came from the line of Robin Haworth from Stifel.

A couple from me, please, if I may. So you mentioned this morning about production testing at Johan Sverdrup testing the limits of the facilities, maybe getting about 470,000 barrels a day in the second half. I was just wondering if you could talk through what that second-half program might look like. And if that may lead to a sustainably higher Phase 1 plateau, please? And then second question, if I may, just on the carbon certification. Is that -- you talked about refinery demand. Is that's what's driving this? It's the potential for higher realizations for your crude, is that right? And I was wondering if you could just describe the process of certification. Do you -- is it something that you think all operators might be doing at some point soon enough? And is it an exhaustive and painful process? Or is it something that's relatively easy to do and therefore, might become an industry standard?

Yes. I'll take the first one and Teitur can cover the second one. In terms of Johan Sverdrup's capacity, of course, we just increased from what it used to be 440,000 to 470,000 and now we really have to wait for another producer to come on stream, which is well 11 to be able to go beyond that. So there is ongoing plan right now to prepare for this -- for the capacity test. There's some work to do. As I said, there's going to be -- we're not getting exactly a precise timing of when we're going to do it, but it's definitely going to be this autumn and there's a plan to get it -- to do it. And of course, should we prove the high capacity, certainly, our intention is that this is sustainable and will be a revised capacity for Phase 1 Johan Sverdrup. I'd just like to emphasize the capacity is one thing, but it's also the other variables such as water injection to maintain the reservoir pressure. So there's -- it's a complex equation. But certainly, there is scope definitely to test the capacity further beyond 470,000. And we will have much more clarity on this on the third and fourth quarter of this year.

Yes. And on the Edvard Grieg CO2 intensity, so it's a company called Intertek, and it's a product called Carbon Clear. And as I said, we've been the first mover on this. And clearly, we've done this because we do think it will play positively into pricing of cleaner crudes going forward. Intertek has certified the other green barrels at 3.8 kilograms per BOE of CO2 intensity. And clearly, at our refineries we are focusing on the ESG metrics as well. This will effectively constitute scope 3 impact from their point of view. And if they can verify that the input products they are using are cleaner than the world average, that really should play well into their ESG metrics. And ultimately, the hope is that it will just enhance the valuation of the crude through the chain. That is essentially the rationale of doing this.

Got it. Okay. And is the certification challenging for an operator to deal with? Or is it a relatively straightforward process?

I think relative straightforward, you just need a good quality field to demonstrate that you have those lower CO2 footprint than the industry average. And of course, with Edvard Grieg also becoming fully electrified, that's just going to play even better into that particular narrative.

Our next question came from the line of Sasikanth Chilukuru from Morgan Stanley.

This is Sasi from Morgan Stanley. I had 2 questions, please. The first one, I just wanted to -- it was regarding the Edvard Grieg -- potential Edvard Grieg reserves upgrade. You talked about 2P reserves upgrade. But I was just wondering, if you were to look at the contingent resource base as well, the 2P plus 2C, would we see any reserves upgrade also based on the contingent resource base? The second question I had was regarding the tax laws impact on your potential new projects. You've talked about 8 potential new projects that you're kind of looking at now. Just wondering whether Alta/Gohta was included in this. And I wanted to check what the impact of these tax changes were on the profitability of the -- of that project? Would you need to do more appraisal work in order to prove this or with the tax changes in itself is it looking more attractive?

Okay. Edvard Grieg, as I said, right now, we're definitely stating that based on the work we've done so far, we feel confident that there will be an upgrade in reserves and we're talking about some of the 3P moving into 2P. When it comes to contingent, at this time we're not guiding specifically. As I mentioned initially in my presentation, the story on the TRI in general and Edvard Grieg also is far from over and as we go along, we'll be building up -- it will become clearer in some of the opportunities and potentials. But at this time, it's really in relation to the reserves upgrade on the -- moving into further 2P reserves. And towards the second half of this year, we will certainly come up with clearer pictures in terms of what the quantum and what it means. And as I said, this will definitely lead also to an extension of the plateau production. In terms of your question on the -- yes, the answer to your question specifically on Alta/Gohta, it includes Alta/Gohta, but I would specify it, it is Alta, not Gohta. So in out of this 8 project, Alta is a potential subsea tide back and we see great improvement on the rate of return from the tax incentive, if you submit the plan of development before 2022. And Alta is a good example because we've done all the appraisal, all the latest seismic, and we also did an intensive production test that lasted for 2 months. So we have a very good understanding and knowledge of the reservoir. So it's now a matter of putting all that together. So that's one of them for sure. I don't know on the taxes if you want to say anything?

No, no. I think we've obviously done some screening on all these projects. And it's fair to say that the IRRs are improving materially. I think the Norwegian government and Parliament have done with these tax changes has been very well thought through, and it has a very desirable impact on both breakeven prices in some cases. Some of these projects, breakeven prices is dropping by $10 a barrel, which is very significant. And IRRs are also increasing significantly. Obviously, the more CapEx-intensive project is, the more impactful these tax changes are going to be on those projects. So it's too early for us to come out with specific numbers on any of these projects. It is all work in progress at the moment.

The next question came from the line of Teodor Nilsen.