Welcome everybody to the Lundin Energy Q3 2020 results presentation. We'll follow the usual format. Alex will talk you through the highlights and operations, and Teitur will take you through the financials, and then we'll have a Q&A session afterwards. Without further ado, hand over to Alex.
Thank you, Ed, and good morning, everybody, and very pleased to be here at my last quarter release. Let's get into the highlights. Overall, I have to say, very pleased with the Q3. Of course, I will start to say a few words about the corona crisis. We are successfully continuing operations. I think we see now the second wave, but it's fair to say this is second wave where we are much better prepared, perhaps, than the first one. The way the industry has reacted in Norway and the mitigating action we've put in place makes me comfortable that we will continue on this trend and being able to continue to operation without disruptions. Second point on the production. You've seen the production where we are at or just above guidance.
You also in particular seen that our full-year guidance has increased, I will say a few more words on the slides. Also to show that we will have a record fourth quarter production for the company at 175,000, I will say a little bit more later on about these numbers. In terms of operating costs, we continue to be industry-leading, low operating costs. For the period, we posted $2.79 per BOE. It's fair to say that we, as a company, continue to focus on cost control, I'm very pleased with these numbers, we will maintain our long-term this year's operating cost at $2.8. Important, also, Edvard Grieg, this is old news. Obviously, we posted an increase in reserves to 350 million barrels of oil equivalent. It's quite phenomenal when you think about it.
When we submitted the plan of development, Edvard Grieg was at 186. What is even more phenomenal is that I don't think this is the end of the outperformance at Edvard Grieg. Of course, with increased reserves, we will see, as you see in these results, an extension of the plateau production, which is now anticipated to be end of 2023. Really, Edvard Grieg is continuing to outperform, and I think that's not the end of the story of Edvard Grieg. On the free cash flow, I think I was very pleased to post $546 million of free cash flow for the first nine months. That's even more outstanding when you take into account the average oil price achieved during the same period, which was just above $36 per barrels of oil equivalent.
It really shows how resilient the company is at this low oil price environment. Q3 was no different with a posted free cash flow of $165 million. Perhaps before I move to growth, it's fair to say that we have now posted free cash flow for the last three years, quarter after quarter. Really pleased also with that result. In terms of growth, you've seen the transaction with Idemitsu, and I will say more later on the slides. We also started our high-impact exploration program in the Barents Sea in the fourth quarter. You will see also next year we will continue to be quite active all through actually the Norwegian continental shelf. Growth is definitely here and both in our existing assets and new concession, new areas. Moving to the next slide. We're zooming into the production guidance.
I guess a few points worth highlighting. Number one is the first nine months production over 157,000, which puts us at the upper end of the original guidance range. If you remember, at the Capital Market Day, we guided the market between 145,000, 165,000, with a midpoint of 155,000. Today we're now posting, despite the curtailment of the production in Norway, 157,000. Very pleased with that. Most importantly also is looking forward. Q4 guidance has increased. This is mainly in relation to the increased production quota that we have received for Edvard Grieg and Johan Sverdrup. For the full Q4, we anticipate to produce about 175,000 barrels of oil equivalent per day, which is a record quarter or a record production for the company. In actual fact, if I look at the performance of October, we've been producing an average over 175,000 already.
We're well on the way to achieve this Q4 guidance. As a result of the Q4 highest oil production, we are now increasing our guidance from what used to be a target of 157,000 to now a full year guidance between 161,000-163,000 BOE per day. Finally, it's worth pointing out that we've been at the upper range or at or upper range of the guidance for the last 21 quarters, so more than three years. Very also pleased with that performance. Moving on to the operating cost and efficiency. Definitely, it's fair to say that we are Lundin Energy Industry leading operating performance. Our production efficiency continues to be very good with our range between 95%-98% across all assets. During the third quarter, as I mentioned, posting for the first two nine months, 2.79. Q3, 2.8, right at the guidance.
Remember that Q4, we will have higher production, and so I have absolutely no concerns of achieving the full year guidance of $2.8 per barrel. On the carbon intensity, also very pleased with the performance. Just to remind you, we guided for this year, less than 4 kg of CO2 per barrel produced. Today, the average for the first nine months is just below 3 kg . Well below our guidance. That's much lower than the world average, or a sixth of the world average. I will say a little bit more about it on the next slide. It's also worth pointing out that just Johan Sverdrup today, it's producing less than 0.2 kilograms of CO2 per barrel produced, and that's well below the guidance of 0.7, so a phenomenal performance, and it shows the strength of electrification, an electrification platform.
Moving on to the next slide, I'm in page five. It's a good follow-up to my last comment. We're definitely delivering on our decarbonization strategy. Just to remind you, we guided the market to producing less than 4 kg of CO2 per barrel produced for the period of 2020-2022, and you've seen that we're well below that mark. By the time Johan Sverdrup Phase II comes on stream and Edvard Grieg is fully electrified, we're targeting below 2 kg of CO2 per barrel produced. I would say, certainly leading as an offshore company, and the most important thing is that this will allow us to target our carbon neutrality by 2030, and maybe even earlier, based on the performance we see to date. Just to remind you, our strategy in terms of decarbonization is really made of three pillar.
Number one, reduction of emissions, which is mainly done through the electrification of the platforms. As an example, by end of 2022, 95% or over 95% of our production will be fully electrified. Number two is our investment in renewable in connection with our electricity production on Utsira High, mainly Edvard Grieg and Johan Sverdrup. As we said, we will invest in renewable to offset and replace all the electricity we're consuming offshore. Thirdly is obviously continuing to work through innovations to further increase our efficiency. Finally, any residual CO2 emissions will be offset through either natural carbon captures or other technologies. We have a clear way forward, and we are definitely achieving and well on the way to achieve carbon neutrality by 2030. The box on the right, they just show you right now where we stand in terms of the replacement of electricity we're consuming.
The Leikanger project, the power project, is now accounting for 30% of the electricity we're consuming on Johan Sverdrup Phase I. By the time we have completed our wind farm project in Finland, we will have replaced 60% of the electricity we're consuming. Really what's remaining for us is probably one more project to offset and replace all the electricity we're consuming at full phase Johan Sverdrup and full electrification on Edvard Grieg. Moving on to Johan Sverdrup, definitely on a league of its own. You're mostly familiar with all the numbers. I will not go through all of them. I think I will highlight just few things. Number one, Phase II is progressing on schedule and on budget. We are now over 45% complete, so very pleased with that. First oil on Phase II, as stated before, is for the fourth quarter of 2022.
I stated also, very pleased with the efficiency, not only in OpEx, which is below $2, which is absolutely phenomenal numbers and is there to stay, but also, in carbon footprint, we hardly produce any emission of CO2 per barrel produced. To me, Johan Sverdrup is really a field of the future, both in terms of performance, efficiency, and carbon footprint. If we're moving on to the next slide, I think that the punchline is really that Johan Sverdrup will continue to surprise us, and it continues to outperform. We've seen several steps. If you remember, first of all, Phase I plateau production was standing at 440,000. During the first quarter, this plateau production was increased ahead of schedule to 470 at no cost.
During the month of November, we will be further testing the capacity on Sverdrup, and we're expecting that we will be able to show that we can produce above 470. This remains to be seen with the capacity testing that will take place during November. Reservoir performance overall, it's excellent. The well results is at to above expectations, so very pleased with that. Today, we have 11 wells producing, which is giving us well capacity that can exceed the current capacity for 70,000, hence the oil capacity test that we'll be conducting during the month of November. We about to complete well number 12. It's going to be in production very soon. Very soon we'll have 12 wells ongoing. Also very pleased with the performance in terms of operations. Moving on to Edvard Grieg or the greater Edvard Grieg area.
As I stated before, Edvard Grieg continues to outperform. It's been simply a phenomenal field when you think of the history and where we are today. Edvard Grieg has seen an increase in reserves of 50 million barrels of oil equivalent, we've seen the plateau extending again, this time to end of 2023. Just to put things in perspective, Edvard Grieg was supposed to decline by end of 2017. We've been able, over the years, to extend the plateau production by five years, we may have not seen the end of this. Very phenomenal performance from this field. We're going to also see the first infill drilling campaign starting at Edvard Grieg, which is due to start in 2021. Tiebacks.
Particularly in this environment, you want to maximize your existing facilities, and you want to maintain the capacity full for as long as possible. The tieback project we're doing are exactly doing that. We are now well on the way with solving a Rolvsnes, and we have potentially new tieback project, such as Lille Prinsen. Of course, there's a lot of exploration. We haven't seen the whole story in terms of exploration, particularly in the western flank of Edvard Grieg. There will be a lot going on in that area. Really the game plan is to maintain the facilities full for as long as possible, and this will generate some of the best and most profitable barrels. It's quite phenomenal if you then finally look at the reserves.
As I mentioned, 186 was the planned development reserves today in the greater Alvheim area. Edvard Grieg, Solveig, Rolvsnes, we are now exceeding 400. If you add the 3P2C, we're getting close to 600, and then for the exploration, 800. We still have the ability from the current 400+ to double again the resources over the years. Moving on to the next slide. This is just a snapshot of our current project, the tieback Solveig and Rolvsnes. I would say overall everything is on schedule and budget, so pleased with that. Just to remind you, first oil for both Solveig and Rolvsnes is for the third quarter of 2021. We're getting very close to that, which is only next year. It's also worth mentioning that these tiebacks are very value accretive. Look at just Solveig as an example with breakeven oil price of below $30.
Both Solveig and Rolvsnes have upside. I am thinking about Solveig phase II, and I am thinking about the full phase of Rolvsnes. Obviously those additional upside will be really crystallizing once we have some production history. A lot of potential also in that area. The next slide, I think it is a very important slide, and it is worth focusing on. There is really two things we are showing. Number one is the further plateau extension. As I mentioned, now we have extended Edvard Grieg to 2023. If you look at this slide, you can see that when I was talking about further upside, if you include the 3P reserves and 2C contingent, you can see that there is scope to further increase the plateau production. Obviously this will come with time. Of course, any other exploration upside.
The other one, which is really something we haven't shown before, it's accelerations. Now we are accounting for once Ivar Aasen comes into decline, the ability for Edvard Grieg to actually not only extend its plateau, but increase its production. You can see that over from 2022, Edvard Grieg will have capacity, and there will be capacity to further increase production while Ivar Aasen is going to decline. That is significant because by the end of 2024, if you include also the 3P reserves, we can exceed an increase by almost 40% of current production level. To take things in perspective, the last time we show you that slide on the 2P level, it was the red line you see in front of you.
You see that now you can start to have a better view of what Edvard Grieg can deliver over the years, not just in plateau extension, but in increased production. Again, really a phenomenal outcome. As I said, Edvard Grieg will simply continue to outperform over the years. Moving on to Alvheim. Really the game plan here is to sustain productions. Aker BP has done a phenomenal job when you think that Alvheim is really a mature asset today. Still with operating cost below $6 a barrel. The game plan here is really about infill wells. The first one will be two. The first one will be online during the fourth quarter 2020, and the second one early next year. We also have tiebacks, such as Frosk, Kobra East, Gekko developments, which we all plan to project sanction by mid-2021.
Really pleased with the performance and another great field, a great example of performance. Moving on to the growth side. I think we've shown again and again that Orrön Energy will continue to grow and continue to focus on high returns and valuable barrels. We currently have four projects underway, and as I say four, I'm thinking about Johan Sverdrup Phase II , the infill drilling in Edvard Grieg, Solveig, and Rolvsnes. You've seen us recently also entering into a deal with Idemitsu, where we acquired 10% on the world-class asset Wisting, which has estimated resources of 500 million and which is currently going under concept selection for submission of plan of development by end of 2022. I think what is important also is with the latest tax incentive that had a really significant impact on our organizations.
We have now nine potential new projects targeting over $190 million barrels of oil equivalent to Lundin Energy. Some of these are acceleration due to the tax incentive, and we've seen really benefit to this environment. The company is very busy bringing, hopefully maturing this project to commerciality. On the exploration appraisal, we've also been very busy. 2020, we have seven wells. We have already drilled three and made a discovery, which the Iving discovery, and we have now remaining four wells. Three this year will be very much focused on the southern Barents Sea, but more on the next slide. A very exciting program. Obviously, we continue to be very active on the upfront license maturations and really focusing on high quality, high returns prospects. Moving on to my last slide before I hand over to Teitur.
This is really a snapshot particularly in the Southern Barents Sea. Not that the Southern Barents Sea is the only area for Lundin. We are very much all through the Norwegian Continental Shelf very busy and maturing prospect and licenses. We're showing you these slides because it's fair that the fourth quarter will be very much a focus on the Barents Sea. Really three things to highlight. Number one is obviously the acquisition we made with Idemitsu, which is giving us exposure to 10% to 500 million barrels of oil field. This transaction was a very, in my view, value creative transaction where we acquired this position with less than or at about $1.8 per BOE, which is very good and an excellent asset. Currently going through the concept selection, and we anticipate a plan of development being submitted by end of 2022.
Number 2 is our Alta/Gohta discovery. Definitely impacted by the tax incentive, and we're currently working very hard to prove that this project can be a potential tieback and a commercial project and we will say more certainly next year during the Capital Market Day. Thirdly, very active exploration program. Three high-impact wells, in the coming month. We're currently drilling Polmak, which is on trend with the existing discovery in Alta. It's high impact with about 400 million barrels of oil growth. Then we will be moving to Bask, which is very much on trend with Johan Castberg, further down flank towards the west, and then with Equinor's Spissa. Very exciting program and very exciting activities overall in Southern Barents Sea. As I said, this is fourth quarter, but in the coming quarter, you will also see activities all through the Norwegian Continental Shelf.
With no further ado, I'll pass on to Teitur, who will guide us through the financial highlights and the financials overall. Thank you.
Okay. Thank you very much, Alex, and good morning, everybody. Kicking off with the first slide here, we normally run through the key highlights for the quarter and the nine months, and I think we can summarize the quarter as yet another solid performance from a financial perspective. The operational team in Norway is doing a good job in keeping costs under control, and also the project teams are doing a great job in controlling CapEx. As we have pre-announced, you can see on the top left box here, we were significantly under-lifted during the third quarter. Of course, our financials are reflecting the sold volumes as opposed to the produced volumes. 146,000 BOE of sold volumes during the quarter, which is 11,000 barrels less than what we actually produced.
Q3 has been less volatile in terms of oil price fluctuations compared to Q2. We have had a good price realization during the third quarter, just below $43 a barrel for the oil and gas, NGLs $21.30 per BOE. As I said, cost very much in line with expectation, $2.80 in the third quarter, and capital expenditure and E&A of $160 million and renewable investments of $5 million. Alex touched upon it, very strong free cash flow and CFFO performance for the nine months, $1.25 billion of CFFO and close to $550 million of free cash flow generated for the first nine months. We continue to distribute dividends on a quarterly basis, during the first nine months, we have distributed $247 million. The net debt at the end of the quarter ended at $3.7 billion, which leaves us with a leverage ratio of 1.7x .
Looking a bit more into the details and the comparatives to the same period last year. Obviously, underlying everything here is the fact that sales prices are significantly down both compared to the nine months and to the quarter last year. For the nine months, you can see they're down 41%, and for the quarter, 29%. That's been more than offset by increased sales volumes driven by Johan Sverdrup coming on stream from October last year. The comparative periods last year, there was no contribution from Johan Sverdrup. Therefore, you see sold volumes up almost doubled for the nine months and up 72% during the quarter. That's resulted in an EBITDA generation of $1.43 billion for the nine months, which is up 17% on the same period last year. For the quarter up 25% at $516 million.
CFFO, we reported the $1.25 billion for the nine months. That was all helped by a release of working capital of $92 million for the nine months. The cash tax payments during the first nine months was $91 million. For the quarter, $353 million. That was negatively impacted by working capital build of $70 million. We've obviously seen an increasing oil price in the third quarter compared to the second quarter, and that has resulted in a higher receivable at the end of the quarter of $290 million. That therefore resulted in a build of working capital of around about $70 million. Nevertheless, CFFO up 53% on the same quarter last year.
Moving on to the next slide and looking at free cash flow, where we are stripping out the impact of completing the sale of 2.6% of Johan Sverdrup, which completed in the third quarter last year. Like for like, excluding JS sale, we are up more than 240% for the nine months, $546 million, and for the quarter, $164 million of free cash flow. If you would add back the working capital build, we would have been at $230 million or there in free cash flow generation. Adjusted net results, where we take out various mostly non-cash impacts such as FX and various non-cash finance items. We are reporting for the nine months $193 million of net profit, which is up 11%. For the quarter, $76 million, which is also significantly up. I touched upon oil price realization.
Just to remind people, our cargoes are being priced off the dated Brent. You can see here that in this third quarter on the column to the far right, dated Brent averaged $42.94 for the quarter. As it happens, that's exactly what our realized oil price was for the quarter. When we then blend in the gas and NGL, we have averaged sort of $40 a barrel. Very good performance by the marketing guys. Unlike in Q2, where most of our cargoes were sold to Asia. During the third quarter, the majority, around about 80% of the cargoes have actually been sold in the European market, and just below 20% has gone to Asia during the third quarter. What we've also seen in this quarter is a normalization back between the relationship between dated Brent and the future Brents.
Whereas one point in Q2, we saw a delta there of close to $10 a barrel, which was unprecedented. Also that has normalized again as we move to the third quarter. On costs, very stable picture here in terms of absolute costs. This is reflecting the cost from the production, the 157,000 barrels oil equivalent per day. We posted $46 million of absolute costs, which is up around about 12% compared to Q2. That has also been driven by a stronger NOK in the third quarter compared to the second quarter by around about 10% strengthening in that. That has also impacted. You see that the unit- costs are continuing to be industry leading and extremely low, $2.80 for the quarter, and that remains also the full year guidance, $2.80 for this year.
On tax, you can see here that we reported a tax charge to the income statement of close to $600 million, made up of current tax of $250 million and deferred tax of $344 million. That resulted in a relatively high tax rate of 88%. That was also driven by, for the first nine months, an FX loss of $85 million, which is mostly non-tax deductible since it arises in the Netherlands. That's what has driven up the high reported tax rate. If you adjust for that non-cash FX loss. You can see that the adjusted effective tax rate would be 76%, which is much more in line with what we would expect from an operational perspective, given the tax jurisdiction in Norway with 78%, which varies off in Norway. On cash tax installments, so this reconciles back to our cash flow statement.
You will see in the third quarter that we made tax installments of $38 million. You can also see here that during the fourth quarter this year, we are due to settle around about $350 million of tax installments, of which $274 million relates to the 2019 tax return. That's the final settlement to balance out the 2019 tax return. We are scheduled to make two further tax installments for the 2020 tax return, amounting to $76 million in Q4. What we are currently now estimating in terms of first half 2021 tax installments to fully settle the 2020 tax return, we are estimating around about $470 million in total, $118 million in Q1 next year and an additional $236 million in Q2 2022 to fully settle the 2020 tax based on assumed effective realized oil price of $40 a barrel during Q4.
If we realize anything different to that, then obviously these first half 2021 installments will change somewhat. Just a quick summary on the cash flow generation during the first nine months and the buildup of that. As we said, the CFFO of $1.25 billion. We've invested in oil and gas, $625 million and another $81 million in renewable investments. Totaling $706 million, which is therefore giving us a pre-dividend free cash flow of $546 million. I mentioned upfront the dividend payments of $246 million, which therefore leaves us with a debt reduction of close to $260 million for the first nine months, and also a cash build of roughly $40 million. Net debt reduction of $300 million first nine months. In terms of liquidity for the company, we ended Q3 at a net debt of $3.7 billion.
Today, we continue to have in excess of $5 billion of committed credit line, so well in excess of $1 billion of headroom liquidity at the moment. Obviously, as we have communicated previously, the RBL is now in this amortization phase. By the end of this year, it has amortized down to $4 billion. With the corporate facility we have and the renewable facility on top of that, we will still have committed lines of $4.5 billion. In fact, we will have ample liquidity right out to mid-2021, at which point the RBL will amortize by another $750 million. That obviously leads into our refinancing discussions, which we have communicated in the past. That's a process which is currently ongoing. The key aim for us here is to improve the terms significantly relative to what we currently are paying on the RBL.
The target continues to be to have refinanced certainly before mid-2021. Obviously, the sooner we can close the refinancing, the better commercially, given that we are going to get improved terms. As I said, that's an ongoing process, and we are estimating to have somewhere between 15- 20 lenders on board in the new facility. Obviously, it's a process to get all of those lenders onto the same page and agree terms. Things are going in the right direction, and we are hoping to get the refinancing done sooner rather than later. This slide, I think articulates very well the resilience of the company, if you look over the last nine months. Extremely low cost base for the portfolio and good quality oil. We realized, including the NGLs and gas, just over $36 a barrel for the nine months.
That has generated an EBITDA margin of over 90%. With OpEx, as we said, and also very low G&A costs of half a dollar per BOE. We continue to have relatively low financing costs, although we hope those will be even lower once we have refinanced, and also relatively modest tax installments. A CFFO margin of 80% or $29 a barrel off a $36. CapEx per barrel that we have invested equates to $16.30 a BOE, which therefore gives us our free cash flow metric per barrel of $13 a barrel, which therefore equates to roughly $550 million. That more than 2x covers the dividend we have paid over the same period.
As we have also previously guided the free cash break even for the portfolio when we look forward from having started up phase II of Johan Sverdrup is less than $10 a barrel. There are two key things coming out of that, of course. One is that we will remain very resilient even if oil prices remain low and volatile going forward. The second point is obviously if the macro environment improves, then this portfolio has significant capacity to generate free cash flow, which will translate into shareholder distribution and continue to maintain a conservative gearing level on the balance sheet, in addition to continuing to invest in the organic growth, which is the cornerstone of the company strategy.
Just looking a bit further back in time, Alex mentioned that we've had 13 quarters running on free cash flow generation, which is what you see here in the top left. Cumulative, including the sale of JS, we've generated close to $3 billion since the third quarter of 2017 in free cash flow. That has been resulting in de-leveraging the balance sheet. As you can see, in Q3 2017, we were up at 3x net debt EBITDA, and we are now reporting 1.7x net debt EBITDA. That's despite having done a share redemption scheme of $1.5 billion during that period. If you actually look at the chart in the bottom middle, since we initiated the cash dividend in Q2 2018, we've generated CFFO of close to $4 billion.
How we have allocated that cash generation, you can see here, has been a balance split between reinvesting in the business. Roughly 40% of the CFFO has gone into reinvestment to continue to grow the business. A significant amount has been distributed back to shareholders, close to 60%. A big chunk of that is obviously the share redemption of $1.5 billion, but we've also distributed $755 million of cash dividend since we launched our dividend policy. There's also been a reduction in absolute debt over this period. This is an extremely solid platform, and with the low breakeven cash flows we have going forward, we will have a very good platform to continue to generate good free cash flow to distribute between a balanced debt and distribution to shareholders. Just recapping very quickly on the updated guidance we've given.
Increase in production to 161,000-163,000 BOE per day for the full year, up from 157,000, which was the previous guidance. OpEx remains unchanged. CapEx guidance has been reduced to $650 million. That mostly relates to phasing some of the CapEx into next year. E&A expenditure is up a little for the full year now, just reflecting a rescheduled work program on our drilling campaigns, up to $160 million. Decommissioning is also slightly up to $50 million for the full year. Similarly on renewable investment, which is mainly driven by FX movements from $90 million up to $95 million for the full year. My final slide is just a quick recap on the dividends. As you know, we have declared $1 dividend per share for 2019 to be distributed out in quarterly installments during 2020.
We have now distributed three out of those four quarterly installments, totaling $213 million. The last quarterly payment will be made around about the 8th of January 2021, with the shares going ex-dividend on the December 30th, 2020. That concludes the run-through on the financials, and then I'll hand back to Alex for some concluding remarks.
Yeah. Thank you, Teitur. This is really the last slide. I'll try to go quite quickly so we can move on to the Q&A session. Really, if I had to summarize, first of all, Lundin Energy is showing again and again its resilience in terms of this low price environment. We've also seen an increased production guidance, and we will see during the fourth quarter, record production for the company at 175,000. Continue to be industry leading when it comes to low operating cost and also carbon emissions. This is not just for this year, and particularly also when the Johan Sverdrup Phase II comes on stream, we will continue to see this low operating cost for many years to come. On the COVID, I think we said it all.
I think the industry, in Norway particularly, and us as operator, I think we put all the action to mitigate any risk for disruption in production and also in terms of delays on projects. You probably have seen also that in terms of growth, we continue to deliver. I'm thinking about the reserves increase in Edvard Grieg, opportunistic deals such as the Idemitsu deal on the Barents Sea, and also our continued exploration program all through the Norwegian Continental Shelf with a high focus this quarter on the southern Barents Sea. High quality, resilient business, really reflected by strong free cash flow generation in a period of lower price. Two, as I tried to show you, to put things in context, despite the fact that we average just $36 for the first nine months, we were able to generate a substantial free cash flow, over $500 million.
Really, one can say Lundin Energy is really uniquely placed to continue to deliver significant growth in value and a sustainable and material growing dividend to shareholders in the years to come. I think those are very much proven by the numbers you've just seen. Finally, I guess on a more personal note, as I said, this is my last quarter. I guess in a way, a mixed feeling. In one way, I'm very pleased to see these fantastic numbers and hand over the leadership to Nick. Of course, I'm sad for it being the last quarter because I had, over the years, a phenomenal time with this company and the team. Really, truly an amazing journey for the company, but also for myself. As I said, going forward, I'm actually very pleased with the team we have in place and the new leadership.
Having worked with Nick for the last five years, I know he's going to do a tremendous job, and he shares the same passion that I've had the last few years. A lot of luck to him, but I think we're going to see a lot of good things in the company in the years to come. As I said, I am absolutely convinced the company will continue to deliver a significant growth value, and in particular during this energy transition. Really thank you all for your great support over all these years. As I said, it's been extremely rewarding for me to work for such a great company and also a great team of people.
Finally, you can be assured that I will remain a faithful and enthusiastic shareholder over the years, I will be watching this new leadership delivering values as we've been used to do. With no further ado, I guess we'll move to the Q&A session.
Ladies and gentlemen, we now begin the question and answer session. If you wish to ask a question, please press star and one on your telephone. We have the first question from the line of Michael Alsford. Please go ahead. Your line is open.
Hi, it's actually Michael Alsford, anyways, let's carry on. Firstly, I just want to wish you very well for the future. I've got a couple of questions, please. Just firstly on production. You're producing 175,000 barrels a day currently, and given your comments on the increased plateau production potentially at Edvard Grieg, you got phase two of Sverdrup. I was a little surprised why the long-term production guidance remains at 170,000-180,000 barrels a day. Could you please elaborate on that? Secondly, you talk a little bit about the well capacity at Johan Sverdrup exceeding the production capacity. Could you give us some guidance as to what that potential capacity is also with the 12th well coming on stream? Finally, just a quick one for refinancing. It feels to me that the share price is suffering from the uncertainty regarding the refinancing.
Could you maybe give a little bit more color as to what the financing structure you're targeting? Is it another RBL? Is it a corporate facility or a bond, for example? Really, what are the improved terms you're looking for? I'm just wondering whether you sacrifice some of that upside to get the process done more quickly and remove that uncertainty. Thanks.
Hi, I'll start with the first two questions and hand over to Teitur on the third one. Your first question in terms of guidance, you're correct. For now, we maintain the long-term guidance to $170,000-$180,000. The reason really is that there are still quite a lot of variables in the equation. One of them is obviously, and that goes into the second question, is the full capacity of Johan Sverdrup. We're going to start very soon to embark on the testing of this additional capacity. We haven't had the results, so we felt it was premature to come up with a long-term guidance until we know more about what the capacity of Phase I, the full capacity of Johan Sverdrup is. This will definitely be incorporated during the capital market in January, which also include, by the way, the Edvard Grieg.
As you've seen in the slides, that was the first time this year we show you what impact could once Yme goes into decline, will have an Edvard Grieg and additional production there, too. We will be clear. We'll come to you in January, the Capital Market Day, once we have all this, and particularly on Sverdrup capacity testing. That leads me to the second one, which is the well capacity. We have well in excess. We have 11 wells, soon 12 wells. When you multiply this by, let's say 45,000 or more, you can see that we have quite a lot more capacity than the current 470,000. Hence now we have this capacity in wells, and the plan is to test this. It's fair to say there's a high expectation for the capacity for the increase for the current level 470,000.
I think we're only a few weeks away from this, so let's wait the results, and again, this result will be communicated in January.
Good morning, Michael. Just on your refinancing question, the structure we are looking at is to refinance into a new bank facility. It won't be an RBL type of structure. It'll be more of a corporate style structure, which will then allow us at some point in time to issue bonds on a non-secured basis and that pari passu with the bank facility. It is, as I said, an ongoing process, and I agree with you, timing is key here because we do expect to get materially better terms. The sooner we can land it, the better. At the same time, this is likely to be a five-year facility, so it's important we get the terms right since we are going to live with that for the next five years.
You don't want to compromise a good commercial outcome for the sake of a month forward or backwards. That is the process as we have it. Obviously, we wanted to have done this earlier in the year, but then COVID came in the way. As I said, we now recommence that process, and things are going satisfactory with landing that new facility within too long, hopefully.
Yeah. If I may add, investors shouldn't be concerned. This refinancing will happen, and as Teitur rightly pointed out, it's more a matter of getting the best possible results to reduce our cost. Secondly, time is working on our favor under the current RBL. We have until mid-next year, but of course, we want to do it as soon as possible, particularly reaching better terms, which will actually reduce our cost. Really, there shouldn't be any concern on this matter.
Great. Thanks to you both.
Thank you for your question. The next question came from the line of Daniel Thomson. Please go ahead. Your line is open.
Hi, yeah. Daniel Thomson here from Exane. Alex, congratulations on a good tenure. I think we can all say you've not done too badly. No pressure on Nick. Okay. I wanted to ask a bit about the Barents and Wisting. Now you've acquired the asset, can you just maybe give us your thoughts on the commerciality of Wisting and how it's going forward? I know Equinor's had some difficulties with some of the drilling beforehand. There's always been a few question marks around it. When you acquired it, what did you see that made you wanted to go for it? I guess maybe give us a sense of how important the Barents is going to be for Lundin now to develop that commerciality for the company's future over the next sort of five years. I guess the second question would just be on the dividend.
I know probably not overly committal at this point in time given some of the uncertainty, but is it perhaps fair to say that the previous level of $1.8 per share is roughly where you think the company would like to get back to on a sort of medium-term view? Thank you.
All right. Well, I guess I can start by saying thank you, and then to your comment, and then let me move to Wisting first. You mentioned drilling, and I think it is true, in the past, there's been some challenging issue on the drilling, but I would say all those are behind us, and both in terms of drilling technology and also the appraisal, that is completed in Wisting, so there are no outstanding issue there. Really, Wisting, it's all about now completing the work, and having the concept selection, which will be leading towards the submission of the plan of development by end of 2022. There's no question in my mind of the commerciality of Wisting. It's just about now completing the studies to submit the plan of development by end of 2022.
Remember also that there's a fundamental change also is the tax relief we received from the tax authority, which has further improved the returns of the project, provided you submit the Plan of Development by end of 2022. That's in terms of Wisting. It's a first world-class project, 500 million barrels, oil, shallow reservoirs, we're very pleased to be there, I think we made the acquisition at a very competitive rate of less than $2 a barrel. In terms of the Barents future, yeah, it's no question that the Southern Barents Sea has been a focus area for Lundin. We have seven core areas, there's many other areas, Barents has always been there. I studied again and again, it's a very prolific area. You just look at Castberg, half a billion, Wisting, half a billion.
We also have the Alta development, which is also becoming very much in the front of our mind because of the tax incentive, which is also a few hundred million barrels of oil. You have Goliat. The Barents, it's happening. People are always questioning the Barents, but it's actually happening as we speak. Castberg being developed and Wisting soon to have a plan of development. Today we have high impact drilling with three wells. All of them, they are great locations, and I'm really keen to see the results. I think over the years, we're going to see more and more on the Southern Barents Sea. It's by far the story is just unfolding as far as I'm concerned on Southern Barents Sea. It's not the only area, core area for us. Your third question in terms of the dividend.
I think it's difficult for me to give any numbers at this point. As you know, the new dividend will be decided in January before the Q4. I would say a few things. Number one is that there's always been our intention to have a sustainable and growing dividend. Of course, this year has been a particular year, and we've been cautious. It's true, because we didn't know really the world we were heading to. I think now we have a better idea, and it's more stable, even though we have a second wave, but I think there's a better understanding on this now. One thing I can say is that you've seen the numbers that Teitur produced.
You've seen our free cash flow ability even at low oil prices, and you've seen that our dividend payment this year, we had more than 2.2 times free cash flow, so compared to the dividend we paid. There's clear ample scope to increase dividend. I will leave it to that for now, and this is something we will decide and disclose in end of January.
No problem. Thanks, Alex. All the best for the future.
Yeah, thanks.
Thank you for the question. The next question came from the line of Teodor Sveen-Nilsen. Please go ahead.
Good morning. Thanks for taking my questions first. Well done, Alex. Wish you all the good luck with the new challenges. I have one question on production and one on dividends. First, just quick on production. Good to see that you actually have increased the permits. Is it fair to assume that the exit rate for Q4 also will be 175,000 barrels per day, such that we enter 2021 on a much higher pace than we previously assumed? On dividend, of course, I understand you can't guide precisely on dividend. I just want to get your thoughts around dividend increase versus the tax changes in Norway.
Do you think it will be controversial to increase dividend now, just a few quarters after this tax change, which definitely has been very positive for the oil companies and also in terms of gearing ratio going forward, Teitur, you showed a graph showing declining gearing. Going forward, do you think we should expect the financial gearing the current level of 1.7 net debt to EBITDA, or how should I think around the gearing going forward? Thank you.
Yeah. Thank you, Teodor. In terms of your question on production, I think the current increase in permits is pretty much allowing us to produce at maximum capacity, both in Edvard Grieg and Johan Sverdrup. Obviously, in Johan Sverdrup, we will see what happen in November with the capacity, but that will be more for 2021, and it will impact 2021. I think the exit rate of end of this year of 175,000, it's a reflection to what will come the following year. Keep in mind that we still have also to include the capacity and the test and the capacity on Johan Sverdrup. More of all that during the capital market day.
In terms of your question on the dividend, it is relevant, but I think the tax incentives, which were very welcome, it's above all to increase activities in the Norwegian Continental Shelf. I think if anything, Lundin Energy over the years, and this is not the first crisis. We've been hit by another crisis back in 2015, if you remember. We've always shown that our activity level and our commitment to investment has always been very high. As long as we can continue to have a level of investment and look for accretive value projects, and as long as we maintain and we can actually reduce our debt, then I have no problem increasing dividends. As I said, we will see in January whether we are, all being equal with the free cash flow we're generating, we will continue to invest in Norway.
At the same time, we think we can also continue to redistribute the cash to shareholders. I think the two go hand-in-hand and it's finding the right balance. I think to your last one, I'll leave it to Teitur.
Yeah. As you know, we are now publicly credit-rated, and we have investment-grade credit rating profile at the moment, and we intend to maintain that sort of credit rating. We will obviously balance any capital investment desires we have with a growing dividend and also maintaining a conservative gearing ratio. We don't have a specific gearing ratio target as such, but we want that gearing level to be appropriate for investment-grade credit rating.
Okay. Thank you.
Thank you for your question. The next question came from the line of James Hosie. Please go ahead. Your line is open.
Hi, good morning. Good luck, Alex. A couple of questions from me. Just first, can you clarify how the curtailment quotas actually work? Is output increasing on Sverdrup and Grieg because other fields haven't or aren't producing their quotas? What's the basis for raising quotas in those two fields but not others? A second question would be on your updated long-term production outlook for Edvard Grieg. Are you just simply projecting that Ivar Aasen starts to decline in 2022 and is shut down during 2025 to give you that extra capacity for you then to fill?
Yeah. Hi, James. In terms of your first questions, well, if you take a step back, the government of Norway decided to curtail production for the third and the fourth quarter. Now how this has been exactly allocated, I don't have the numbers of single fields. All we know at that time that both Edvard Grieg and our two main fields in Johan Sverdrup were affected. Now that commitment from the government stands until year-end. Of course, the reason we've been giving us a higher permit now to produce pretty much at capacity on the current capacity, it's obviously probably because these other fields and other developments haven't developed or produced to expectations. Beyond that, I really cannot say much more because I don't see any single numbers, and I don't know how others have been affected or not. I can only look at our fields.
In terms of Edvard Grieg, we always shown Edvard Grieg with the current commercial arrangement, and so that was pretty much on a gross basis, Edvard Grieg producing 95,000. As you know, the overall capacity of the processing facilities, it's above that. The reason we've always been standing at 95,000 is obviously to honor the commercial arrangement with Ivar Aasen. Now, the increase that we're showing now for the first time is really related to the start of decline of Ivar Aasen, which we assume not next year, but from 2022. Really this is the main assumption in terms of giving us more capacity to Edvard Grieg.
Okay, thank you. Just one follow-up on the curtailment point. Is that actually limiting the scale or duration of the testing for capacity you can do on Johan Sverdrup?
We have flexibility. As you know, we have to achieve a certain number, but it's not a daily number, but it's an average. In terms of the testing, we have absolutely no limitation because no matter where we go, then we can reduce production if we want to meet the quota. There's no limitation in terms of testing the capacity. I foresee to be really able to test the capacity in the coming weeks.
Okay, great. Thank you.
Thank you for your question. The next question came from the line of Al Stanton. Please go ahead. Your line is open.
Yes, good morning, folks. It is Al Stanton. Alex, I wish you happy sailing. For everything else, I mean, many of my questions have actually been answered by Michael at the start, but can I just check a couple of things in terms of cash flow you've been talking about look like they could get spoiled in the fourth quarter by that tax bill. I'm just wondering if that is very much a one-off. Last year was so exceptional that calculating the 2020 cash payments was always going to be quite difficult. Can I also just talk about buybacks? Is that on the agenda at all at a certain share price? Thank you.
Good morning, Al. That tax installment in Q4, which relates to 2019, that is a one-off, as I said, once that's been paid, then the 2019 tax bill has been fully settled. The way the tax authorities in Norway are managing this going forward now is that as you can see in our first half 2021 tax installments, in prior years, those would normally be the same size as the ones we have paid in the second half 2020. Now they've changed that so that the catch-up payment, if you have under-installed in the first two or three installments in 2020, then you need immediately to adjust your tax installments in the first half 2021. That's what we are projecting now, that we have to increase the tax installments that we have in Q1 and Q2 next year.
By the end of first half next year, we should have fully settled the 2020 tax bill.
Okay.
Yeah. On buyback, I guess I will simply say buyback is an option. Obviously, in this current environment, it becomes more and more attractive. So it's something we actively looking, and at the end, it will be a balancing act, because we want to continue to be able to pay and sustain dividend in the long term and increase dividend. Of course, we are mindful, and buyback it's also an option for the company that we actively looking.
Okay. Thanks very much, and good luck, Alex. Thank you.
Thanks.
Thank you for your question. The next question came from the line of Sasi.
Hi, it's Sasi Chilukuri from Morgan Stanley. I wish you all the very best for your future endeavors, Alex. I had two questions, please. The first one, I appreciate you're not necessarily giving specific targets, but I was just wondering in terms of the priority of cash flow, you've highlighted what you have done previously. I was just wondering if that is pretty much the priority going into the future as well, with dividend being or shareholder distribution being the top priority for additional cash flow, and followed by CapEx and followed by net debt. Any guidance on what your priority would be quite useful. The second one is regarding the Polmak exploration well. There have been some press reports suggesting some drilling issues and drilling being stopped as well.
I was just wondering whether drilling is actually going on, whether there's any delay in the drilling of that well, and if any delay, that has any subsequent knock-on effect on your other Barents Sea wells? Thanks.
Yeah. Hi. Thank you. I'll start with the last question. That was very simple. You're right, we had some issue in the beginning. Those are behind us, and as we speak, we're drilling. Really there's been very little delays. In terms of will that have an impact for the other wells? No. I think so now, I would say, is business as usual. Obviously something we've taken very seriously, and we're learning from it. On your first question, which is priority of cash flow, I think, as you said, it's a balancing between debt, CapEx, and dividend. I think you've seen as Teitur shows you from the past, our share of cash flow distribution has always been significant. I'm not prepared here particularly to give a specific guidance of debt, CapEx, dividend.
What has happened perhaps in the last few months is not necessarily a firm guidance of what will happen in the future. I am sure our colleagues at the capital market, once we have defined a new dividend, will give more color on this. It is always going to be, I would say, a balance between these three and but cash redistribution, it is on the forefront of our mind, and it is an important part of the strategy of the company.
Thank you.
Thank you for your question. The next question came through the line of James Thompson. Please go ahead.
Good morning. Great. Thanks. Alex, I echo everyone else's sentiment, wish you all the best for the future. I have a few questions, if I may. I just wanted to start with Edvard Grieg. Just, Alex, perhaps could you talk about how much you're going to expect to choke back the main Edvard Grieg field with Rolvsnes and Solveig coming on next year, and look at your chart, you're still expecting Yme-Aukra to be on plateau for all of 2021. The second question really on Edvard Grieg is obviously earlier in the year, you received your low carbon certification on the field. I wondered, is that actually making any difference at all now in terms of refiner appetite for that crude, and could we potentially see a premium coming through given clearly there's such a market focus on low emissions at this point in time?
Yeah. Okay. On the Edvard Grieg, your first question in terms of much Edvard Grieg, Solveig, and Rolvsnes, I think it's difficult to answer this question. I think the important thing is that there is certain capacity constraint, as you see over the years, this capacity we will be able to fill in more than we've been in the past. I think you have to look at Edvard Grieg, Rolvsnes, and Solveig as one area. At times, we may choke back some wells in Edvard Grieg or in Solveig until we have full capacity. It's difficult at this stage to really specifically give a number, because I see really this as a unit. It will give us a lot of flexibility and a lot of additional capacity. I think that's the best way to look at it.
In terms of the low carbon, Edvard Grieg, you're right to point it out. We were the first company actually to have this low carbon certification. Has this had any impact? I would say it's too early to say. I truly believe the future is the way to go, and I truly believe that eventually this will add value to shareholders at the end because it may imply a premium to our product. Also, I guess what we do see, but that's more generic in terms of a low carbon strategy, is that we do see impact today in terms of, for instance, on the financing, because we can link our performance on the ESG, and particularly the E side, link it to the terms we're going to negotiate with the banks, and if we are below a certain target, that will lead to better terms.
We're starting to see benefits of being first in class when it comes to carbon footprint, and carbon certification is one part of the puzzle.
Thanks. Sticking with the emissions, Sverdrup was only 0.2 kilos in third quarter. That was phenomenally low. What was driving that, and when will Sverdrup be certified?
Yeah. As you said, it is phenomenal. I mean, 0.2, you could say that is almost zero. It's hardly no emissions. I think we're learning. This is the first big field that was fully electrified, and we're learning from the performance on Johan Sverdrup. It's going to be really interesting to see also Edvard Grieg. Of course, for us, the lowest emissions, the better, because that means to reach carbon neutrality will require very little in terms of offsets. That's really good news. In terms of the certification of Johan Sverdrup, it's a good question. It's something that has been discussed. I'm not the operator of Johan Sverdrup. Everybody is well aware of what we're doing, and we hope soon we will be joined by many other fields, and hopefully Johan Sverdrup will be one.
I have no information specifically on this, but I know it's been discussed at the license.
Okay, thanks. Last one from me on a separate topic. Clearly the refinancing is, I think, top of mind for the market, and obviously you've given us a bit of a runway there, but is there any scope to get this wrapped up before the year ends, Alex, before you hand over the reins?
Yeah. This is Teitur here, James, that will certainly be the target. Above anything else, we need to get the right terms. That is what the focus remains from our side. Obviously it's a negotiation with the counterparties of which there may be 15 to 20. Doable this year for sure. Yes.
Yeah. End of the year, maybe. Our motivation is to do it as soon as possible so that we can have improved terms, which will have a direct impact on our cash flow. That's really our main motivation. As I said before, I'm not concerned at all in terms of our ability to refinance.
Okay, great. Thank you very much. I'll hand over.
Operator?
The next question came from line of Joan Sharpo.
Good morning. This is Joan Sharpo from Societe Generale. Alex, as you sail away, I would like to thank you for your engagement with the sell side, and I will use your last earning call as an opportunity to ask about the following, if you don't mind. If we think about the Barents Sea, we have seen some Norwegian explorers retreating from the area, and it also appears that there are less companies, basically, willing to put money to work out there. Following the Wisting deal that you announced a few weeks ago, have you seen an increase in interest coming from fellow oil and gas companies to farm down Barents Sea acreage to you?
Second question, coming back to this tax changes timeframe, since you are participating to this ongoing race to FID with other Norwegian oil companies by year-end 2022, have you entered any new contractual relationships with oil field services companies of late with a view to minimize future cost overruns and risk of delays?
Hi, thank you for your kind words, moving to the Barents Sea. The activity level in general, difficult to say. You can measure it. Of course, there's the M&A side, we've seen the Mitsui deal. Will there be any more activities? Probably. I don't know. What I can measure is also in terms of licenses and appetite, I think in general, there's still quite a high activity level. It is true that in the Barents, we've seen really few players that have been active over the years, I'm thinking about Equinor, I'm thinking obviously of Lundin Energy, Aker BP, to some extent also Vår Energi and Eni. That's a factor in itself because the fact that we are only a few companies into such a large area means that we don't really see the truth of the Barents Sea.
We certainly, from a Lundin Energy point of view, we always felt that the Barents Sea was an area to be, an area where you can find large resources, and an area really that is no more expensive than any other areas. There's a bit of a logistics challenge, but overall, drilling a well in the Barents and developing a project in the Barents shouldn't be really more expensive than in the Norwegian Sea, for instance. Our focus more than the Barents is to continue to invest in very value-accretive project with low cost. That will remain our main focus. We'll see. If there are going to be more discoveries, I'm sure you're going to see a lot of people back in the southern Barents Sea with a lot of interest. That's in terms of the Barents Sea. I've lost track now.
Your second question was?
Alliances with those.
Oh, alliances.
relations, alliance action with-
Alliances with other I think we're happy where we are now. We haven't specifically done new alliances or sales personally. Through our Solveig and on the subsea tieback, we already had the contract in place. Maybe in future we're going to look at other ways to conduct our business. Overall, our main focus will always be in cost. If an alliance that will have an advantage, so be it, our main focus will be mainly to find the best possible way to reduce our cost and for any development. That may be through alliance or maybe not. It's difficult to say at this stage.
That was great. Thank you again.
Yeah. Thank you.
Thank you for your question. The next question came from the line of Hendrik Holt. Please go ahead.
Yeah. Thank you guys for taking my questions. Of course, Alex, congrats on a very successful tenure. It's good to see that despite Ashley's retirement, and now your retirement, it's been almost no notable change in terms of strategy. That's good to see. My questions are two this morning. First of all, it's related to Edvard Grieg, and I just want to clear something up. You might have touched upon it in the call, so apologies if I missed it. Looking at your chart on page number 10 here of Edvard Grieg. Am I right in interpreting that the Edvard Grieg main reservoir is now expected to hold its plateau up until 2023?
Yeah, that's correct.
Hence the bump is coming from Solveig and Wisting. The second question is related to actual crude oil price development as we see so far in this quarter. It seems that the super contango development that we saw in Q2, it seems to be reemerging. The difference is now $5 per barrel on next month's contract. It's just wondering if you're starting to see, obviously not the huge spread that you saw in Q2, but are you starting to see some similar patterns in the price development on the crude oil barrels that you sell right now? Thank you.
Yeah. Thank you. Thanks for the comment. I guess, on the more strategic side, I would say I actually planted the seeds. I made sure that they grow fast and high, and Nick will make sure they grow even faster and bigger. In that point, I think we're looking good. On your question of plateau, yes, the current guidance is now that plateau in Edvard Grieg has been extended to end of 2023. That's correct. Further extension of plateau is possible, but depends on the 3P and 2C. We need to account for more 3P and 2P continuing resources. If we do, then there's scope to increase the plateau production up to end of 2024. Then, of course, you will have exploration for the upside, but that's not quantified at this stage.
As I said, also with more capacity being available, obviously the combination of Edvard Grieg, Solveig, and Rolvsnes, will give us a lot of flexibility beyond the further 3P and 2C. A lot of things happening in Edvard Grieg and the greater Edvard Grieg areas will continue to outperform, no question about it.
Yeah. Hendrik, on your question on crude oil pricing, we are seeing some level of softness over the last few days, it is nowhere near to the volatility that we saw during the second quarter. We are continuing to sell all our cargoes at reasonable prices. Obviously, the dated Brent differential is hovering around about $1.50 discount to the ICE Brent. That's not out of line if you look at that historically. The contango, I guess, is picking up a bit with this COVID second wave scenario playing in. We are far from the state of panic that was in the second quarter at this point.
Yeah, very good. Thank you.
Thank you for your question. The next question came from the line of David Farrell. Please go ahead. Your line is open.
Hi. Good morning, and congratulations. Alex, a lot of questions been asked already. I did have one which I was hoping to ask. Given what's going on in the oil markets currently, and the potential for OPEC+ to continue curtailment through into 2021, do you think there's any risk now that in Norway they may reciprocate and continue to have the permits, certainly through the first part of 2021?
Hi, David. Good questions. The straight answer is I don't think so. The situation we were facing back in March was quite different in a sense that you had two storms. One was obviously the pandemic and the reduction in demand, and the second one was the OPEC in the beginning that was doing exactly the opposite of what they were supposed to do by flooding the market with crude. We had a really extraordinary situation at that time, and everybody took note of that. Since then, we've seen OPEC, a much better discipline from the OPEC side, and I think we have now a much better understanding of the world, even with the second wave. I don't foresee at all post this year's further curtailment from the Norwegian, and I haven't had any signal on that front whatsoever.
Okay, great. Thanks very much.
Thank you for your question. The next question came from the line of David Round. Please go ahead. Your line is open.
Thanks, guys. I'm going to be really brief, but there is a bit of a rush to sanction projects at the moment to take advantage of the tax benefits, obviously. If all these go ahead, do you think there's actually capacity in the Norwegian yards? How are you thinking about potential cost inflation there?
Yeah. I don't think so. You're right. This tax incentive has been very smart from the Norwegian Government and it definitely has its impact. If you look at impact on ourselves, we are now able to move forward certain project that we may have not done before. Will that really create capacity issues on the Norwegian Continental Shelf in the yards? I don't think so, because we don't really have the magnitude of fields such as Johan Sverdrup at this time, where the largest field now it's Castberg and one there, Wisting. At this point, we don't see that concern in terms of capacity. I would say is more like a ball of fresh air for the yards in general, and we're not at capacity. Even in terms of inflation, I don't see this as being a big risk.
Okay. Great, and best of luck.
Yeah. Thank you.
Thank you for your question. We don't have any other question.
Thanks very much, Roberto. We've just got two from the web, which I'm conscious of time, but I think are worth asking. One of the questions is, can you talk about how you will reach full replacement of your 500 gigawatt hour per annum power usage? You're invested in Finnish wind and Norwegian hydropower. What types of additional investments are you looking at?
Yeah. Today, pretty much, we are 2/3 on the way. One project, the hydropower project, is now up and running and will be up in full production soon. We're currently developing this project onshore wind farm in Finland. When the wind farm in Finland will be up and running, in addition to the hydro project, we will have replaced and offset about 60% of the electricity we're consuming with zero CO2. We left with a 40% space to fully replace the 500 gigawatt-hour that you mentioned. That 40% really, depending on the equity position, but if you take a position of 100% on a sizable wind farm, that would be sufficient to fulfill our full replacement offset. Probably you're looking at one, maybe two project, if we take a lower equity position in some of the projects.
That's all it remains to be done.
Okay. Thank you. Lastly, can you elaborate on your options at Alta and the feasibility of delivering a PDO by the end of 2022 for the Alta project?
We're currently looking at Alta. In order to be able to submit a plan of development by end of 2022, Alta will have to be likely a subsea tieback. We're currently looking at the different options. Also comes to selection in terms of what would be the most feasible development for such a tieback. It's early days, but we working very actively because our aim, we see really benefits of this tax incentive and we see good rate of return and a possibility to have this project through the whole level of commerciality. I think more details on this one next year once we have completed a lot of the ongoing work.
Very good. Thank you, Alex. Operator, I think that's the last question from the line, so I'd just like to thank everyone for listening in. Of course, if you've got any more questions or need further detail, please don't hesitate to contact us or me. Thanks very much. Have a good day.
Yeah. Thank you all. Thank you. Thank you very much. Thanks.