The line is now live. Please begin your meeting. Thanks very much, Mark. Good afternoon or good morning, wherever you are. Welcome to the Lundin Energy third quarter 2021 results call. We'll follow the normal course of business today. Nick Walker, the CEO, will take you through operations and an update from the quarter. Teitur Poulsen, CFO, will take you through the financials. Nick will finish off with a quick summary. Q&A once again will follow the normal course. We'll take calls from the line first and then I'll moderate any calls from the web. Please get your questions in early if you want. Thanks very much. Nick, I'll hand over to you. Well, thanks Ed, and good afternoon or good morning if you're joining us from North America. Of course, welcome to our third quarter 2021 results discussion. I'll start off with the key highlights. I'm pleased to report another set of record production and financial results for the third quarter. This is underpinned by continued strong operating performance and further strengthening of oil and gas prices. You can see here Q3 production was 194,000 BOE per day, and we expect full year production to come in towards the top of the guidance range. All of our key projects are on track. The Evergreen tieback projects of Solveig and Rolvsnes achieved first oil in the first quarter on schedule and below budget. The Johan Sverdrup Phase Two project is firmly on schedule for first oil in the fourth quarter next year. Yesterday, we announced a strategic acquisition of a further 25% interest in the Wisting development. I think this is a great deal for us. It adds 130 million bbl of resources at a price of $2.50 per bbl, which I think is very value accretive and further supports the long-term production outlook for our business. On top of that, our high-quality cash generative business delivered record financial results in the quarter. You can see operating costs here of $2.90 per BOE, which is better than guidance. We delivered record free cash flow for the period of $1.6 billion, resulting in deleveraging of the business. You can see net debt at the end of the period is $2.6 billion. I'm pleased to note that the board of directors anticipates to propose to the 2022 AGM a 25% increased dividend for 2021 of $2.25 per share, which in total is $640 million. I think this clearly demonstrates our commitment to grow shareholder returns. We continue to be firmly positioned as an industry leader on carbon emissions. During the quarter, we further accelerated our decarbonization plans to become carbon neutral by 2023 from our operational emissions. Already today, 60% of our production is independently certified as carbon neutrally produced. I see this as a key value differentiator for Lundin Energy looking forward. In summary, we've delivered another set of excellent results in the third quarter, and all of our key business priorities are on track. Now what I want to do is step through some of the details supporting this performance. First of all, looking at production. Our world-class assets keep on outperforming. As I've mentioned, our 3Q production was 194,000 BOE per day, which was towards the top of the guidance range, as you can see on the charts. That's now 25 quarters running that we've met or exceeded guidance. This performance continues to be driven by excellent production efficiencies across all assets and additional facilities capacity at Edvard Grieg due to further declines at Ivar Aasen. When we look forward, we expect the production for the full year to come in towards the upper end of the guidance range, which I think you'll recall is between 180-195 thousand BOEs today. We should come in towards the top of that range. This delivery is backed by continued top-tier operating performance, which you can see shown on this chart with excellent production efficiency metrics of 95%-98% across all our assets. I've already talked about operating costs of $2.90 per bbl, which is better than guidance. These are truly industry-leading levels. Also really good performance on carbon emissions, 2.9 kgs of CO2 per BOE. To put that into context, that's one-sixth of the world average. Importantly, we again delivered safe operations in the quarter. I think stellar operating metrics all around. Turning now to our decarbonization plan, where we're firmly an industry leader. We're making great progress, and during the quarter, we further accelerated our plans to become carbon neutral from operational emissions by 2023. To recap, the plan is supported by real action around three key pillars. Firstly, reducing emissions with electrification of our assets with power from shore, which you can see on the chart, significantly reduces our carbon emissions. Secondly, replacing and offsetting our power usage with our own investments in renewables. Then thirdly, what we can't reduce, a commitment to nature-based carbon capture, through quality reforestation projects to neutralize the balance. This means that by 2023, every bbl that we produce will be independently certified as carbon neutrally produced. We're continuing to work to build a market for carbon neutrally produced bbl. I think we're seeing lots of interest, and we've made quite a number of sales on that basis. As I mentioned, I see this as a key value differentiator for the company, looking forward. A key aspect of our decarbonization plan is powering our business with renewables. We're on track with the power from shore projects at Johan Sverdrup and Edvard Grieg. Our target is to meet all of our own power usage with our own generated renewable energy. Our Lyngen hydropower investment in Norway, as you can see, from the chart, covers around 40% of our net power usage this year. The MLK wind farm in Finland, which you can see in the photo, has just started generating power and will be fully operational by the end of the year. Our Swedish Karlsgruvan wind farm will be online at the end of 2023, by which time, as you can see in the chart, we'll have net generating capacity of around 600 GW hours per annum, which covers all of our usage, including the requirement we now need for Wisting. This means that by the end of 2023, our business will be fully powered by our own generated renewable energy. Now turning to our world-class assets, that underpin our business performance. Firstly, Johan Sverdrup continues to perform at an extremely high level with phase one operating very stably at 535,000 bbl of oil per day gross with extremely high production efficiency. You can see some stellar operating metrics. OpEx is well under $2 a bbl and exceptionally low carbon emissions, more than 100 times better than the world's average. When phase two comes online, this will lift full field capacity levels to over 755,000 bbl of oil per day. To put that into context, it's about 25% of Norway's total production. We continue to see excellent reservoir performance. Based on the company's latest technical assessments, there is potential for increased resources and also to extend the plateau through infill drilling. We're working to complete this work as part of our reserves process. I think you'll hear more of that in the coming months. Now looking at phase two of Johan Sverdrup. The project remains firmly on track for first oil in Q4 of next year, and with costs unchanged from the PDO. I think the key elements of the project are coming together very nicely. We reported in the last quarter that the jacket for the phase two platform and a large module on the existing riser platform were installed in the summer. The subsea facilities are being installed at the moment and will be complete by the end of the year. That which will allow drilling operations on the subsea well to commence early next year. In the photo, you can see the fully assembled, phase two process, topsides, which is being completed in Norway and will be installed offshore in the second quarter next year. In summary, Johan Sverdrup continues to deliver above expectations and everything's on track for phase two. Now turning to the greater Edvard Grieg area, where we're delivering on our multiple projects that will keep the facilities full in the long term. At Edvard Grieg, we've had excellent results from the infill well program, which I'll cover in the next slide. We continue to see the benefits of facilities capacity upside with Ivar Aasen clearly in the decline phase. We're on track with our power from shore project for completion at the end of next year. The Solveig and Rolvsnes tieback projects which flow through Edvard Grieg, I'll talk about those in a moment. They're now online. We recently completed a successful appraisal well and tests of the Lilleprinsen discovery, and we're now moving forward with development studies to potentially submit a PDO at the end of 2022. We're also working hard to bring forward a number of new opportunities, and I expect we will be exploring and appraising in this area for many years to come. Now focusing on the Edvard Grieg reservoir. The performance continues to exceed expectations, which I expect will lead to a reserve increase and further plateau extension. We'll update on that with our 2021 year-end reserves process. We've had great results from the three well infill well program in the field. As highlighted on the map, you can see the three wells that have been drilled, and this is now complete with results from all three wells in line with or better than expected. This is a great project with stellar economics. To remind, the breakevens for this project are less than $20 a bbl. We're already beginning to think about the further phase of infill drilling. The Edvard Grieg reservoir continues to outperform and continues to offer upside. Now focusing on the tieback projects to Edvard Grieg. I'm pleased to report that we've delivered first oil from Solveig phase one on schedule and below budget. This is a key project for us to sustain production through the Edvard Grieg facilities that will produce, as you can see, a plateau rate of 30,000 bbl of oil per day gross. The project's got great economics with a break-even oil price of below $20 a bbl, and I think this shows the value of tieback projects into existing facilities. You can see from the chart that the first two horizontal production wells have been completed, and we saw excellent results that are better than expected, and I anticipate this will lead to a reserve increase at year-end. The third producer is currently drilling, and then we've got two water injectors to complete, which will be done in the first quarter next year. That will complete the phase one development. The early production results here are key to de-risking a possible Solveig phase two project. Which on success we aim to bring forward for PDO at the end of 2022. There's quite a lot of upside here. You can see that the whole area has a potential up to 100 million bbl of oil equivalent gross. It's quite a big prize for us if we can move forward with the phase two development. This has been a great project for us so far. I think it's gonna be super exciting to see the production results, and hopefully then we can move forward with the phase two project in the area. We've also delivered Rolvsnes extended well test projects, again, on schedule and on budget. This is an exciting project, and it's aimed at unlocking significant potential resources in weathered and fractured basement reservoirs on the Utsira High. Early production performance from the extended well test is in line with expectations, which is, I think, very encouraging. The aim of the EWT is to gain a better understanding of the long-term production performance of the reservoir. On success, the potential is to unlock a full field development here of Rolvsnes with, you can see resources up to 80 million bbl gross. In parallel with understanding the reservoir, we're moving forward with the development studies, and we're ready to submit a PDO at the end of next year if the reservoir performance supports that. Success here could unlock significant additional basement potential in the area, potentially up to another 100 million bbl gross. I think it's gonna be super exciting to see how the EWT performance goes over the next year. Hopefully, then we can step into a full field development here and start to think about the other opportunities that are available in the area. This chart we've shown before, I think pulls all of the elements of the greater Edvard Grieg area together and reminds you of the long-term production outlook for the area. We've already stated in the past that the plateau has been extended to the end of 2023. That's five years on from where the original PDO was. With Ivar Aasen on decline, it allows production through the Edvard Grieg facility to further expand, as you can see, which has already increased production from the contractual levels that we have with Ivar Aasen from 95,000 BOE per day, and we have the potential to lift this up to 135,000 bbl a day as Ivar Aasen declines further. The key thing here is that we have the well capacity to use any of the capacity that's available to us. I think there's lots more upside in the area with the potential to keep the facilities full in the longer term. As I've discussed, we're working super hard to bring forward a number of those new projects in the area. I think it's gonna continue to be an exciting opportunity to grow resources here. Just one slide on the Alvheim area. This continues to be a good asset for us. It's got a strong track record of continually growing reserves and creating value. We continue to progress multiple opportunities in the area. With three infill wells planned this year, two have been completed with results in line with expectations, and the third well is currently drilling. With three new projects being progressed, PDOs have been submitted for the Kobra East and Gecko and Froskelår projects, and these projects are now moving forward. Concept studies are ongoing on the Trelland Trend development, with the aim to submit a PDO next year. All of these projects are being progressed under the Norwegian temporary tax regime, have great economics with breakevens in the $25-$30 per bbl range. You can see from the chart what these do for us. Together, they add 65 million bbl of gross reserves and deliver gross peak production of up to 45,000 BOEs per day. I think it's super encouraging that we continue to find opportunities here to create value, and I think there's still more to come in the future. Turning now to Wisting. I was super pleased yesterday that we could announce that we've acquired a further interest in the Wisting oil developments. Last year, we acquired 10% in Wisting from Mitsui, and at the time, we said we made it clear that we'd have liked more, and it's great this opportunity has come along for us. This deal with OMV gives us an additional 25% in the project, taking our working interest to 35%. I think this is a strategic deal. It creates the next production core area for the company and supports the long-term production outlook for our business. You can see the deal adds 130 million bbl of net, fully appraised contingent resources at an acquisition price of approximately $2.50 per bbl, which I think is very value accretive. The addition of these resources alone, you can see, delivers a total resource replacement ratio for the company in 2021 of about 190%. Wisting is a high-quality, 500 million bbl project with strong economics. At the moment, the finalization of the concept select for the project is ongoing, and the PDO is planned to be submitted by the end of next year. As this development is being powered from shore, the deal is fully aligned with our decarbonization strategy. On top of that, we see significant exploration upside close to Wisting, with the surrounding acreage estimated to hold another 500 million bbl of oil of undrilled prospective resources. I think this deal is a perfect example of how we look to supplement our organic growth strategy with opportunistic acquisitions and fitting our ambition to sustain our business in the long term. I was super pleased that we could do this. We're continuing to deliver on our growth strategy. The business is set to produce over 200,000 bbl a day by 2023. In fact, we're almost there, and that's supported by the projects that we've recently completed and those that are underway. We aim to sustain at those levels with a pipeline of new projects. We've got two projects heading to sanction, three projects are being de-risked, and we aim to also deliver future value. For example, the strategic acquisition of Wisting is a good example of that, but we also aim to continue a material exploration program. As I've mentioned, we're set to again more than replace our resources. The Wisting deal alone adds almost two times this year's production, showing we continue to grow the business. I remain really excited by the growth opportunities and prospects ahead, and I'm confident that we can continue to sustain our business in the longer term. That wraps up the operations overview. With that, hand over to Teitur to review our financials. Okay. Thanks very much, Nick, and good morning or good afternoon, everybody. I think third quarter, again, can be characterized as a very solid financial performance quarter for us, obviously driven by the outstanding operational performance. A very strong cash generation overall, and we continue to delever and therefore to build balance sheet strength. Some of the key financial highlights on this first slide here, and Nick has been through the production volume, but our financials are, as usual, driven off sales volumes. You can see in this quarter, we were overlifted by around about 7,000 bbl oil equivalent per day, with both Edvard Grieg and Alvheim being overlifted while Johan Sverdrup was somewhat underlifted during the quarter. Hydrocarbon prices is very much in theme of the day these days, and during third quarter, very strong realized prices both on oil and gas, $72 for oil and actually over $100 or per BOE in terms of gas price, $16.8 per Mcf. Costs continue to be very much in control. In fact, as you're seeing, we're guiding down full year CapEx guidance for the year. In the quarter, OpEx of just over $3 a bbl, and we had oil and gas investments of $322 million and renewable CapEx, which also includes carbon capture investments of $21 million. This has now generated yet another record EBITDA, EBITDAX number of close to $1.3 billion. For the first time also, cash flows from operations in excess of $1 billion for one quarter, and then generating $674 million of free cash flow before the dividends. As Nick mentioned, just over $2.6 billion of net debt at the end of third quarter, which now leaves our net debt to 12 months trailing EBITDA at 0.7x. Looking on the next slide and some of the key financial metrics that we measure ourselves on. You can see in the top right the volume we sold equated to 18.5 million bbl of oil equivalent, which is up 38% on the same period last year and 13% on the previous quarter. As I said, sales prices per BOE $72.80, which again is significantly up on both the prior same period last year 78%-79% up, and then 9% up on the previous quarter. You can see on the EBITDA generation up 21% driven off our total revenue of close to $1.5 billion. EBITDA of $1.28 billion. Cash flows from operations over $1 billion. This includes now higher tax installments, $321 million installments in the quarter, which is up from the second quarter. But CFFO was also somewhat positively impacted by an unwind of working capital of $91 million. We had total investments during the quarter of $338 million. That leaves free cash flow generation of $674 million, which covers more than five times the dividend we paid out in the quarter of $128 million. The free cash flow is up 59% on the previous quarter. The net adjusted results for the quarter, $234 million. On the next slide, honing in on our realized prices for oil sales. In the bottom left, you can see that the Dated Brent average for the third quarter was $73.50. The timing impact in this quarter was a negative 50 cents. We had a disproportionate amount of volume lifted during August, and out of the three months during the quarter, August was the weaker pricing month. We had the physical discount of $1.40, which is an improvement on second quarter when we had physical discount of $2.10. That left us with a realized oil price of $71.60 for all the cargoes that we sold during the quarter. On the chart to the right, you can see that the all-in blended cost was $72.80 when you include the gas and the NGLs. Actually a higher price than what we achieved for the oils on a stand-alone basis. Going to the next slide and just a slide on gas. It's not something that normally shines through in our numbers, the gas revenues. Given where gas prices have been recently, this is now starting to make an impact on our financials. Just to remind people, all our gas is sold on the spot. Edvard Grieg and Alvheim gas goes to St. Fergus in the U.K., while the Johan Sverdrup gas goes via the Kårstø terminal in Norway and then ends up on the Dutch market. All gas is sold on a day-ahead basis. You can see the volume we sold in Q3, just over 12,000 bbl of oil equivalent per day. You can also see how the gas price has strengthened during the quarter, actually the whole year, particularly in the quarter, and finishing the quarter at in excess of $120 per BOE. Very strong gas price realization. As I said, on average for the quarter, $101 BOE equivalent for our gas sales. Also looking at the working capital trend. You can see in the previous four quarters we have continued to build our working capital position. That's really been reflected through an increase in oil price environment over those four quarters and also increase in production. Since that was also the trend in the third quarter, you would logically expect Q3 also to continue to build working capital. In fact, what happened here is that we unwound working capital close to $100 million in the quarter. The reason for that can be explained by those three small bars in the top right, where you can see that in July, August, were the two months where we lifted the majority of the volume, close to 75% of the volume was lifted over those two months. Given that we invoice on a thirty-day payment term, it means that we got paid for both July and August. That's really what led to an unwinding of working capital in the quarter. Three quarters of the volume was lifted over the first two months, and therefore, we got full payment for those volumes. If we then go and look at the operating costs and EBITDA margin, I mean, operating costs continue to be extremely low, as Nick said, industry-leading in reality. The NOK has continued to strengthen somewhat, and given that all our costs, more or less all of our operating costs are NOK denominated with a stronger NOK that leads to somewhat higher U.S. dollar costs. But nevertheless, still, just over $3 a bbl during the quarter, and in absolute numbers, just below $60 million. We reiterate the full year guidance of $3 for the full year. You can also see here on the EBITDA margin continues to be extremely strong. The average for the nine months round about 94%, and also 94% in the third quarter. Turning to taxes. If we start with the top two charts first, this is the tax rate we reported on the face of the income statement. A pre-tax profit of $936 million and a tax charge of $800 million. That equates to an 85% tax rate on the face of the income statement. That includes our FX loss of $97 million, and most of that FX loss is non-tax deductible, which therefore drives up the effective tax rate. If we adjust for the FX and some other smaller items, then the underlying operational tax rate we've had is around about 77%, which is in line with the effective tax rate in Norway of 78%. In terms of cash tax payments, as I mentioned earlier, you can see in the bottom here, the third quarter payments, $321 million. What you also see here in the fourth quarter, we are gonna pay based on a NOK exchange rate of 8.5, we are paying $722 million. Of that, around about $640 million relates to the 2021 tax installments, and another $80 million relates to a catch-up payment to fully settle our 2020 tax bill. We're also providing here a look ahead on the first half next year in terms of tax installments we anticipate to pay to fully settle the 2021 tax bill. Based on an oil price deck of $70-$90 for the fourth quarter this year, we expect to pay in the first half next year, somewhere between $1.46 billion-$1.72 billion of tax installments spread across those two first and second quarters, as you can see here. As I said, to fully settle the 2021 tax bill. You can see also on our balance sheet, again, third quarter, we have booked a tax liability of $1.4 billion relating to this year's tax charge and also the catch-up payment we have to make for 2020. Looking at cash flow generation, organic CFFO, $921 million, and then unwinding of working capital, as I mentioned earlier, of $91 million. That takes us above $1 billion of CFFO generation, just in the third quarter. The investments we've been through just below $340 million. That's how we generate a free cash flow number of $674 million, in, during the quarter. The dividends we are paying is $128 million per quarter. For the full year 2020 dividend, we are gonna pay $512 million, all in. That leaves our cash flows for the quarter of $531 million. Which therefore leaves the company with a cash balance at the end of the third quarter of $853 million. On liquidity position and debt position on the right here, you see how the net debt is derived. We have $2 billion of bonds outstanding, and we have $1.5 billion of term loans outstanding, so a gross debt of $3.5 billion. As I said, just over $850 million of cash, which leaves us with a net debt position of $2.6 billion. That leaves the company with a very solid liquidity position of $2.4 billion when we add in the undrawn revolving credit facility of $1.5 billion. On the bottom left here, you can see the maturity profile of the debt instruments we have outstanding. The average maturity here is 5.25 years, and we actually have no maturities falling until the end of 2023 when a term loan of half a billion dollars matures. Also on the investment grade credit ratings, we continue to have three ratings publicly available, and all of those three are still higher than investment grade. Then just a recap on our latest guidance. Nick has been through the production volume. As I said, $3 a bbl OpEx is still our full year guidance on that front. As I mentioned, we are taking down our CapEx guidance to $770 million for the full year. That's driven by some CapEx savings on both Solveig and Evergreen through better drilling performance than expected, and also some rephasing of the onset of CapEx. While E&A expenditure is increasing to $325 million, and a big chunk of that relates to the 25% additional acquisition of the Wisting oil field, which has an effective date of first of January this year. Therefore, we have to account for all costs incurred from that point onward. Renewables continues to be at $100 million for the full year, reflecting this latest Swedish wind farm we acquired earlier in the year. My last slide then is just to recap on the dividends. In the third quarter, we paid the second quarter dividend in early July, and we have already paid the third quarter dividend, which will be reflected in our fourth quarter numbers. We paid that in early October. The big news, of course, is that the board of directors anticipate to propose to the AGM next year an increase of 25% in dividends to $2.25. Which will equate to an absolute number of $640 million of payout, which is still gonna be significantly less than half of the free cash flow generation we have during this year. That concludes my commentary, and I'll hand back to Nick for concluding remarks. Yeah. Thanks, Teitur. I've just got one final slide to summarize. I want to leave you with the message that we delivered another set of record results during the quarter, and all of our main business priorities are on track. The key points are listed on this slide. First, our world-class assets keep on outperforming, yielding record production and operating costs ahead of guidance. Second, we delivered record free cash flow and have a really strong financial outlook for the business, which supports the increased dividend proposal that we've talked about. Thirdly, all of our key projects are on track, providing growth to over 200,000 BOEs per day by 2023. In fact, when you reflect back on our capital markets day, we're set to go somewhat higher than that. We've a pipeline of opportunities to sustain at that level. Fourthly, as we talked about, we've announced yesterday the Wisting acquisition. I think this is a great deal, and I think it further supports the long-term production outlook for the company. The fifth element is that we further accelerated our decarbonization plans to be carbon neutral by 2023 from operational emissions. Crucially, we're already 60% of the way there today. Those are our third quarter 2021 results. Thank you for your time, and we'd now like to open up the call for your questions. I think it's back to you, Ed, or the operator. Thank you. Thank you. If you wish to ask a question, please dial zero one on your telephone keypads now to enter the queue. Once your name has been announced, you can ask your question. If you find your question is answered before it's your turn to speak, you can dial zero two to cancel. Once again, that's zero one to ask a question or zero two if you need to cancel. Our first question comes from the line of Sasikanth Chilukuru of Morgan Stanley. Please go ahead. Your line is open. Hi. Good afternoon. Thanks for taking my questions. I had two, please, both related to the Barents Sea. Now that you have acquired the additional 25% stake, and you have a 35% stake in Wisting, and you've established another core area in the Barents Sea. However, there have been issues of major cost escalations or delays with projects associated with the developments in Barents Sea, Goliat, and more recently, Johan Castberg. Wisting is further away from the shore. I was just wondering, when or how do you actually, or how did you actually account for the development risks associated for a project like Wisting? Especially, before increasing your stake, in the project here or committing to what's likely to be a very big, CapEx program. The second question was also sticking to the Barents Sea, but in terms of exploration. 2021 so far has turned out to be another disappointing year for exploration in this area. You highlight unrisked prospective resources around the Wisting area. Will you be restricting your exploration program towards that area in Wisting or are you still optimistic about exploring in other parts of the Barents Sea? Thanks. Good. They're both good questions. I can't really comment on Goliat and Johan Castberg. We're not involved in those projects. What I will say is that, you know, we've been, you know, Equinor are the operator of Wisting during the development phase. You know, we enjoy a tremendous performance with Equinor on the Johan Sverdrup field, and they've done an amazing job to deliver that project. Both phase one and phase two looks like it's gonna come in on schedule and below budget. So we think with the right structure, with the right focus on the project, that we can, there's no reason why a project in the Barents can't be delivered efficiently and on schedule. I'm sure that's the motivation for Equinor. In fact, I know that is. I think we also carry an element of contingency in all our numbers. As the project comes closer to sanction, you reduce that level of contingency. We have quite a wide range of cost estimates. When you take those cost estimates in the end, we see that we have strong economics even on downside cases. I think we're confident that we can move this forward, and I'm sure that the project will be set up in a way to deliver on schedule and on budget. We feel confident about that. Then around exploration, it's true that there hasn't been a lot of recent success in the Barents, but it's a big area. There's a number of big projects already there. Castberg, Wisting, Goliat, Snøhvit. You know, I think there's more to come. Of course, building this material position in Wisting, I think we're motivated to explore around Wisting. We've been building the acreage there jointly with the partners. You know, we're excited by those opportunities. There's some similar prospects with similar seismic attributes that you see over Wisting in those prospects. Those are the opportunities that we have. It's, you know, I think we have probably one other well to be drilled there next year, which is the only other commitment well we have that's closer to Goliat. But, you know, we have a big exploration portfolio also in other parts of Norway, and would continue to drill in those areas as well. Hopefully that answers your good questions. Sure. Thanks. If I can just have one follow-up or a clarification essentially regarding the acquisition. There's this increase in the year-end expenditure of around $65 million related to this Wisting acquisition. I was just wondering, will that be a payment towards to OMV, or how do we account for that? Or is it already considered in the cash consideration of $320 million? Yeah, no, no, that's that will be a catch-up payment that we have to make to OMV because they've effectively been funding the 25% spend on that license from first of January. Given that our deal is effective from first of January, we have to repay them whatever they have funded from first of January to the completion of the deal. Okay. Thank you. Thank you. Our next question comes from the line of Teodor Sveen-Nilsen of SB1 Markets. Please go ahead, your line is open. Good afternoon, guys, and thanks for taking my questions, and also congrats on very strong results. Two questions, if I may. First on the dividend versus cash flow title. You pointed out that cash flow this quarter is five times the dividend. Looking into 2022 and your indication of 2022 dividend, it still looks like you will pay a pretty low share of your earnings and cash flow in dividends. I just wonder, going forward, should we expect you to pay out a pretty low share of earnings and free cash flow in dividends? Secondly, on the Wisting deal, which looks very exciting. I just wonder the difference in the price you paid for its 10%, the $1.8 compared to the $2.5 you paid now. How much of that excess is explained by CapEx invested from last year until the time of deal closing now, and how much is explained by other factors? Thanks. Yeah, I mean, on the dividend, I mean, we've been very clear, and we're just following our policy really, which is that we want to continue to grow dividend year-on-year in line with our financial performance, and that's what this latest proposed dividend increase is doing. Of course, you know, this year's free cash flow number is looking somewhat better because of the tax installment, phasing of the tax installments, so there is a catch-up payment of cash taxes next year, as we showed on our slide. But even so, you're right that our free cash flow should exceed the dividends we are proposing now. That means that we will continue to delever the balance sheet next year also, even after dividend payments. We need to look at this through the cycle, and we need to set the dividend level so that we can actually follow the policy of increasing it year on year. We look out more than just one year. We look out a number of years and make sure that we can actually fulfill that increase over that timeframe. I think on the second question, I mean, the deal we did with Idemitsu didn't just include the 10% of Wisting, it also included a share of Aasta Hansteen. When we quoted the purchase price for that deal, it included the resources that we picked up from Aasta Hansteen. If you actually split those out, we paid very similar amounts for the Wisting share that we've received from OMV as to the deal that we did last year with Idemitsu. Okay. Understood. Just to follow up on Wisting, could you remind me on the gas oil portion? On- Gas oil. Oh, it's almost 100% oil. It's very, very small amounts of gas. It's a shallow field with low pressure, so you don't get much gas. The gas is exported, but it's basically no value in the development. Okay, thank you. That's all from me. Thank you. Our next question comes from the line of Michael Alsford at Citigroup. Please go ahead. Your line is open. Thanks. Good afternoon. A couple from me actually, and maybe following up a little bit on the last question around the sort of cash flow breakdown next year. Could you maybe try to isolate what the catch-up payment is for the 2021 tax payment in your guidance for 2022 tax? And just to pick up on your question around or your comment around the fact that you think you'll be able to generate free cash flow next year, I'm just wondering what that oil price is that you need to deliver that because I guess with the CapEx obviously rising probably with Wisting investment, you've got clearly the cash taxes increasing substantially. It would seem to me that you would need at least $65 to meet that sort of threshold. Maybe you could talk a bit about that please. Then just secondly on exploration, you spent, you know, several hundred million of dollar this year and really found limited amount of organic reserves. It's another year of inorganic reserve replacement, which is still a way to replace reserves. I was just wondering how we think about investment going forward. How much exploration spend should we expect from the business maybe going forward in 2022 and beyond? Thanks. Yeah. Michael, maybe I can start on your tax question. I mean, what we are guiding on the slide on tax is a payment in Q1 of next year of around about $575 million, and then another two tax installments in Q2 next year of $1.1 billion. That makes a total payment of $1.4 billion-$1.7 billion, depending on what realized price we get in the fourth quarter, the quarter we are currently in. Those tax installments fully relate to the 2021 tax charge that we are accruing for. Then it's only from August next year that we then start to pay tax installments relating to 2022. We haven't given any further guidance on that in terms of what that tax charge will be. It's obviously clear that when you look at the cash taxes we have to pay next year, they are gonna be significantly higher than the taxes we have paid this year because the 2020 fiscal year was a much weaker year macro-wise, so therefore the tax bill from 2020 spilling into 2021 was significantly lower. We will give further guidance on our cash flow breakdown for 2022 as we normally do, including what oil prices we need to achieve for break even pre and post the dividend payments. Michael, for your question around exploration, I think, you know, the way to look at this is that we see exploration and resource growth coming in multiple areas. First of all, step-outs around our world-class fields, and then near field exploration opportunities in the maturer areas in the basins. We supplement that with opportunistic acquisitions. I see all of those as levers to continue to sustain and grow the resource base for the business. I think it's fair to say we haven't had much success on the frontier exploration opportunities for a while, but the other areas I think we've had a lot of success are near field, step-outs, and of course, some of the acquisitions I think have been very value accretive. I think if you look over the last five years, we've had a 150% resource replacement ratio, average over that period of time. For every bbl we've produced in the last five years, we've added 1.5 bbl, growing the business. I think I'm quite confident now looking at where we are in the business, that we're going to have a resource replacement ratio this year, so towards 2x what we produce, and Wisting alone does that. Growing the business. I think we've had a lot of success growing the business. I think we can keep doing it. Yes, it's true that our frontier areas exploration hasn't particularly delivered for us. I guess for me it doesn't matter where it comes as long as it comes and that's what we've been doing. I think when you look at the expenditure levels, I think we've got quite a heavy load of appraisal spend this year in our exploration appraisal spend, that's quite a big component. All of the, for example, the study money that we talked about on Wisting goes into that bucket. We've drilled quite a number of appraisal wells. Relatively speaking, of the $325 million that we're guiding for this year, it's a relatively small amount on sort of frontier exploration areas. I think we've tended to guide somewhere between $200 million and $300 million per year on exploration appraisal. We haven't really set our plans for next year. We will do that around the capital markets day, and it's coming together at the moment, but you can expect it to be in that sort of range for next year. Hopefully that answers your question. It does. Thanks, Nick, and thanks, Teitur. Thank you. Our next question comes from the line of Yoann Charenton of Société Générale. Please go ahead. Your line is open. Good afternoon, everyone. Thank you for the presentation. I just would like to ask a few questions again on the Barents Sea. Is it fair to say that bringing forward the dividend upgrade announcement, which comes something like three months ahead of your CMD, has a lot to do with the Wisting deal announced last night? Just trying to understand if there is basically a link between the timing of the dividend upgrade announcement and the Wisting deal. Again, on the Barents Sea, you referred to that area in the vicinity of Wisting. You stated basically that there is unrisked prospective resource potential of 500 million bbl. How much of this can be targeted next year as part of your E&A program? Maybe a final question, looking away from the Barents Sea and thinking about the Edvard Grieg area. Are you able to say how much of the reduction you had this year in your development expenditure budget came from this better than expected trading performance at Edvard Grieg and Solveig? Thank you. Okay. You know, good questions. In terms of the exploration area around Wisting, you know, we see some good prospects there and but Wisting's on a development time scale, which will be 2028 for its production, and then won't have capacity for some years after that. I think what we're looking at is the exploration will come some years from now. The first step is to put the acres together and develop the plans. Really we need to explore in a timeframe that can keep the facilities full in the long term, 'cause these would be tieback type opportunities to Wisting. Hopefully that gives you a sense. It may be three or four years from now that we start to drill some of these opportunities. It's good upside, and we'll continue to study them and do seismic surveys and analysis to move those forward. In terms of the timing of the two announcements, there's absolutely no correlation between them. I think in terms of bringing forward our dividend announcement, you know, the business is in such great shape. We keep getting asked so many questions around what's the dividend gonna be for next year? We thought it would be good to provide some forward guidance rather than wait till our capital markets day at the end of January. There's absolutely no correlation between the two. The businesses is able to fund both growth and deleverage the business as well as fund a growing dividend. You know, we don't see that there's any conflict there. Then your final question, I didn't follow exactly what it was around Edvard Grieg. Yeah, it was on the CapEx savings. We're reducing it from $850 million- $770 million. It's around about an $80 million drop. In rough numbers, roughly half of it relates to Johan Sverdrup, and the other half relates to most of the savings on Solveig and the other Edvard Grieg drilling campaign. That's very clear. Got it. Thank you. Thank you. Our next question comes from the line of Karl Fredrik Schjøtt-Pedersen of ABG Sundal Collier. Please go ahead. Your line is open. Thank you, guys. Thanks for the presentation, and thank you for taking my questions. Two, if I may, both related to Wisting. First, is this a field that would have been developed without the Norwegian temporary tax regime in Norway? As a kind of part to that question, what if the 2020 timeline is not met? Is it something that we should expect to be de-developed regardless? The second question is, if it proves that electrification of Wisting is not feasible, is it still an asset that you would be keener on? Or is it an asset that does not fit with your low carbon strategy? Yeah, I mean, in terms of the timing, I mean, it's absolutely on the trajectory to get sanctioned at the end of next year. I don't think there's any question about that happening. There's a lot of motivation to do that. The project's going to make a concept selection about sort of defining the exact concept, which is happening very shortly. Actually the FEED contract has been awarded to Aker Solutions already. This is moving forward in my view. We're very confident that we'll get to PDO at the end of next year. In terms of, could you remind me of your second question again? Electrification. Sorry. That was regarding electrification, if it proves not to be feasible. Yeah, yeah, of course. In terms of electrification, the technology, it is 300 km offshore, but the technology is well advanced for doing this and it's perfectly feasible to do it. You know, to give you a sense, there's been a recent interconnector built from U.K. to Norway, which is further distant than that. And that's become operational. I don't think there's any doubt that this is going to be electrified. It's also feasible from an economical point of view? Yes. It's all part of the project concept that's being defined at the moment and is being engineered for sanction at the end of next year. Great. Thank you. Thank you. Our next question comes from the line of James Thompson at JP Morgan. Please go ahead. Your line is open. Super great. Thanks. Thanks for that. Hi Nick, hi Teitur. I have a few questions for me actually. First of all, Nick, are we now into a time where effectively it's kind of continuous drilling on Edvard Grieg? I mean, we've had kind of first infill campaign. You're now talking about another one. Should we just expect it now to be a sort of consistent drilling program there? And then secondly, on Edvard Grieg, have you kind of formally increased your allocation in the facility now? I think you talked about sort of 95 heading upwards. I mean, obviously, you've got full access to it at any time. But is there sort of a formal change in the amount you're able to utilize every day? Yeah, good question. You know, we've just come to the end of the current infill drilling campaign of three wells. The rig will depart from the field very shortly. And then we are starting to plan another infill campaign, which we haven't defined when the timing's going to be. And so that could be a year or two away. We need to define what the program's going to be. We'll probably do another 4D seismic survey next year, which will help define the opportunities. Of course, we like to continue to see field performance. I think you know, it's probably not gonna be the final infill program when we do the next one. I'm sure we'll be drilling here on and off for many years, and not just in the field, but around it, 'cause I think there's lots of opportunity. You know, you can see developments of the full field on the Rolvsnes as a potential and further phases at Solveig and other exploration appraisal in the area. I think we'll be drilling overall in the whole area for many years. I guess not so much drilling on the field itself next year when you've got Solveig at plateau. Pardon? Well, you're not gonna be drilling much on Grieg next year. On the Edvard Grieg next year, and in fact, Solveig, we will be completing the phase one development drilling. By the end of first quarter, we should be finished with the water injectors that we need to drill there. Then the rig will depart that field. What we're now doing is starting to plan for the future phases, full field on Rolvsnes, if we see success with the extended well test of phase two at Solveig. Both of those projects, hopefully we can move forward at the end of next year. I'm hoping during next year, we can also define another phase of infill drilling at Edvard Grieg. As I say, I think we'll be drilling here for many years. There's lots of upsides. Okay, that's clear. Just on Wisting, I mean, obviously you've got quite a big stake there now. Are you able to give us any color at this stage in terms of the kind of CapEx that you're gonna be exposed to ahead of first oil? No, we're not. I think, we can, you know, we tend to update on our capital guidance outlook at our capital markets day, and I think we'll do that again, and it's a bit early to be doing that, particularly given the projects in the definition stage. That's something for the future. You know, I thought it was quite interesting in your pack that you talked about the amount of gas that you are gonna be able to sell because of the electrification strategy in 2023. I mean, I think that's one part of it. I'd be interested to know as well, you know, obviously, carbon prices have been going up and up in 2021. Do you have a good estimate for how much you saved in dollar terms by your electrification strategy this year? The second part on that kind of cost angle is, you know, are you starting to see much cost inflation at all in Norway? I mean, clearly your operating costs are, you know, sector leading. But you know, prices are rising, and I'm sure service contractors want to get paid. Are you seeing much pressure there? Yeah. On the first question, I mean, I think it's well known that carbon taxes in Norway at the moment are just over $100 a ton. It was announced a while ago that they would progressively increase to $240 a ton by 2030. If you look life of field on our electrification net to us, we're saving through electrification about $1.4 billion on carbon taxes by electrification. It's material. Of course we don't as carbon taxes go up, we're not gonna be paying any more. It gets better and better. In terms of inflation, I think it's a good question, and I think obviously we are going to see some inflation. I think we haven't seen it into the services yet. I think still things like drilling activity is relatively modest. I think in terms of that area, we're probably okay for now. I think, of course, where we need materials that are on a worldwide market, like steel, for example, I'm sure we're going to see growth there. We haven't already seen it into our business, but it's as we start to define new projects, I'm sure we're going to see cost growth there. We've already, I think, built in latest cost growth into the outlooks that we have. You know, it's gonna be, you know, sort of clear to us that we need to understand what this looks like going forward. Are we looking at short-term inflation, or is it a longer-term structural change? Okay. All right, thanks. I'll hand over to Zach. Thank you. Our next question comes from the line of Al Stanton at RBC. Please go ahead, your line is open. Yes, good afternoon, guys. I've just got one question, so I'll be fairly quick. It's for Teitur. I don't think it's spelled out in the presentation, but I think it is in today's release that your forecast for fourth quarter cash flow from operations is $400 million-$500 million, which is a bit less than I'm assuming. You're also guiding to either no free cash flow or negative free cash flow of $200 million. I'm wondering, in addition to the big tax bill, the $700 million tax bill and the $320 million acquisition, is there any other big chunky numbers that we should just look out for in the fourth quarter? No, not really. The reason why, you know, there could be flat to even negative free cash flow during the fourth quarter is obviously movement in working capital, which is a bit more tricky to forecast and predict. Which is why we left ourselves a little bit more of a margin on that particular range in addition to movements in capital and DD&A programs. Okay. I lied. I'll ask a second question then, if I may. This one's for Nick. The disclosure in Norway is better than we have in the U.K. When the Lancaster field, the fractured granite basement was being produced, there wasn't that much clarity on water cut, but we will get the water cut figures for Rolvsnes. Is there any guidance or anything that we should worry about when we're looking at the production figures? No, I mean, it's too early for us to update, and it's not been producing for very long. What I will say is that the early production data is in line with the expectations, which I think is very positive. Of course, you know, there's the water cut development in the field is key to understanding it. Also, the pressure performance of the field will be also key to understand it. It's connected to a big enough volume. It's gonna be exciting to see the results over the next year, 'cause that's going to be key to defining whether we can move forward with the full field development. I will say it's a different type of geology than Lancaster. The difference here is that this is not just a fractured basement, but it's also weathered. You have porous, secondary porosity in the basement. The key here is to see that responds and that's what the key is about the extended well test. Too early to really give you any sense of how it's performing other than it's in line with expectations. Okay, cool. Thanks, guys. Thank you. As there are no further questions on the phone at this time, I'll hand back to Ed for any questions on the web. Yeah, thanks very much, Mark. We've actually only got two from the web, gents, so I'll just quickly run through them. One, first one is from Anish Kapadia. Your production from 2025 to 2030 from your current producing asset base could potentially halve over that period. Wisting should now offset some of this, but do you see further development projects required, or are you happy for longer term production to decline? I mean, it's a good question and, you know, obviously at some point our fields will decline, but I think there's still lots of upside in the Edvard Grieg area, in the Alvheim area, and particularly in Johan Sverdrup. I think all of those things are going to push the profile out and of course, Wisting adds to that. We would expect to see our exploration appraisal program also add to that. I think we're pretty confident that we can continue to sustain the business longer term. You know, I think we've demonstrated that our assets continue to grow and create value, and I think there's lots of opportunity to continue to do that longer term. Okay. The last question is unnamed, a shy shareholder. Will the increased stake in Wisting impact your 2022 CapEx and E&A budget? Are there any ways you can guide on the increased stake and what it'll do to CapEx and E&A next year? Yeah, it will at the margin, but obviously next year's big CapEx number really still relates to Johan Sverdrup phase two to complete that project. Whatever expenditure will be on Wisting will be relatively modest in the big scheme of our total CapEx program next year. Indeed, our capital drops relatively quickly next year too, so. It does. 'Cause Johan Sverdrup comes to an end, and the Evergreen project's complete. Actually, you should be looking at CapEx significantly down on this year, next year. Super. Thanks very much, gents, and thanks very much to everyone in the audience listening in. That concludes the Q3 2021 call. If you have any other questions or want more detail, please drop me, Edward Westropp, a line. Thanks very much. Thank you. Thank you.