Orrön Energy AB (publ)

Hello, good afternoon or good morning, wherever you might be. Welcome to the London Energy Q4 2021 results and also the 2022 business outlook and budget for the year. We'll run today like a normal set of results, actually. We'll have Nick Walker talk through the top line, some operational highlights, and then we'll hand over to Dan Fitzgerald, who'll talk you through the operations, and then over to Taita Paulson, who'll talk you through the financial performance for the year, and an outlook into 2022. After that we'll be followed by the Q&A and we'll run it by the conference call line first Q&A and then I'll host the calls from the web thereafter. So thanks for joining and I'll hand over to Nick Walker who'll kick off the presentation.

Thank you, Ed. And good afternoon or good morning if you're joining us from North America. And it's great to have you all join our London Energy's 2021 results discussion and 2022 business outlook. Of course, given the transaction we announced with ACA BP in December. The format today is naturally slightly different to our usual Capital Markets Day. And as Ed says, I'll give an overview and then give an insight into the ACBP transaction. And then we'll run through the agenda. And, of course, as usual, we'll give you the opportunities to answer your questions at the end. So, first of all, the key highlights for 2021. I'm really pleased to report record production and record financial results for the full year. This is underpinned by continued excellent operating performance and, of course, the strong oil and gas prices that we're enjoying today. You can see our world-class assets continue to outperform. Full-year production you can see came in at 190,000 BOEs per day. That's top of the original guidance range. And we exited the year at just under 200,000 BOEs per day. All of our key projects are on track. In the greater Edvard Grieg area, we delivered an infill drilling program and we delivered two tieback projects to the facilities, Solvay and Rolsnes. And all of those projects came in on budget and on schedule. And together with a number of new projects that are being planned, we'll keep the facilities full in the long term. Jons Federup Phase 2 remains firmly on schedule for First Oil later this year, which will provide a big boost to our production, as you'll see when Dan talks. And we have two projects in the Alvheim area just started in the execution phase. We again grew the business with a resource replacement ratio last year of 200%. And I see more to come from continued growth in our world-class assets. And I think Dan will give you a flavour for that when he talks. Our high-quality cash-generative business delivered record financial results. You can see continuing industry-leading low operating costs of $3.1 per BOE in the year. We generated record free cash flow on the back of strong production performance and strong prices of $1.6 billion for the year. That's over three times our annual dividends and results in us deleveraging the business with net debt reduced to $2.7 billion at the year end. We're also making great progress on our decarbonisation plan with the company set to be carbon neutral by 2023 from operational emissions. And I see this as a key value differentiator for Lundin Energy and supports our top quartile ESG ratings. And this is the foundation of our recent inclusion in the Dow Jones Sustainability Index for Europe. And I think this is a big deal. It's one of the biggest accolades you can get in relation to ESG. So in summary, we've delivered excellent results in 2021 and all of our key business priorities are on track. But also at the end of last year, I was very pleased that we announced a transaction where we're combining Lundin Energy's E&P business with ACA BP to create the leading European independent E&P company. And I'll talk about that in a few moments. But first, looking forward to what can you expect in 2022. You can see we're guiding production of 180 to 200,000 BOEs per day. And that's consistent with what we've indicated previously, with the main variable being the timing of the startup of Johans Fedrup phase two. As I've discussed, we're set to be carbon neutral by the end of this year. And we continue to sustain low operating costs. $3.6 per barrel is the guidance for this year. That's slightly above 2021 levels, but that's due to startup phase of Johans Fedrup. And when we get to a full year of production on Johans Fedrup phase two, then it drops down again in 2023. In terms of operational delivery, you'll see that Johans Federer Phase 2 comes online in the fourth quarter of the year, lifting capacity through the field to 755,000 barrels of oil per day. Gross. At Edvard Grieg, we expect to see three new project sanctions by the end of the year, supporting this long-term production plateau extension. And electrification of the facilities will start up later in the year. And this is, of course, a key element to our decarbonisation plan. And at the large Wisting field, where we increased our interest last year to 35%, we will sanction that project development at the end of the year. And this provides material support to the long-term production outlook for the business. And of course, during the year, we expect the transaction with ACABP to complete around the middle of the year. And on the back of that strong performance and the outlook for the business, and as we announced at the end of last year, the board is recommending to the 2022 AGM a quarterly dividend increase by 25% from this year. So on an annual basis, that's $2.25. $2.25 per share, which will be paid quarterly. This is in line with our dividend policy to grow shareholder returns. And this increased dividend level will remain payable until closure of the ACA-BP transaction. And I now intend to run through a couple of slides that talk about the proposed ACA-BP-London energy combination. London Energy is a track record of creating value for shareholders for over 20 years, which you can see shown in this slide. So, since the company's inception, the share price has grown from 3 sec per share in 2001 to roughly 375 sec per share today. while also along the way distributing around $2.5 billion through spin-outs and dividends. And this represents a 28% compound annual average return every year for 20 years. However, the board has felt for a while that to prosper through the energy transition, we need to build greater scale while retaining focus, being low cost and low carbon, which led to the process that we ran during the second half of last year, resulting in this proposed transaction where we announced in December to combine Lundin Energy's E&P business with ACA BP. and leaving Lundin Energy, a renewables business, which is positioned to grow. And I think this creates more value for shareholders, and I think selling the renewable business with the E&P business would not create that extra value. So I'm convinced this transaction will continue our path of creating value for shareholders. So focusing now on the details of the transaction, the proposed combination of AccuPP and Lundin Energy's E&P business I think is a tremendous deal to combine these two great companies, drawing on the best of both to make something even bigger and better. It creates a Norwegian pure-play E&P company of scale, production growth, low cost, and low carbon emissions that I think is set to prosper through the energy transition. It will be Europe's leading independent EMP company and one of the top independents in the world, with a market cap of today around $23 billion, and will be Norway's third-ranked listed company by value. I think it's a great deal where the value of the combined business is greater than the component parts, and I think in this case we can truly say one plus one is equal to more than two. And for the Lundin Energy shareholders, this will deliver significant upfront cash consideration of approximately 72 SEC per share. That's around 20% of the value of the company. The opportunity to be a shareholder in the leading European E&P company. And you can see receiving roughly 0.95 ACABP shares for every one Lundin Energy share you hold. And a retained interest in the new renewables business that is set for growth. And the combined business has the financial strength and cash flow profile to pay a growing and sustainable dividend into the next decade. ACABP has announced a 14% increase in dividend for this year. And the combined group will pay an annual dividend of $1.9 per share post-completion on a quarterly basis. And the intent that is that will grow thereafter by at least 5% per annum. And so I'm convinced that this combination proposal with ACA BP is a win-win outcome for both sets of shareholders. And I think in terms of the process moving forward on the transaction, the Lundin Energy shareholders will be asked to vote on the transaction at our AGM at the end of March, and the ACA BP shareholders will vote early April. And then there's some necessary approvals, government approvals and... petition authority approvals in Norway, which I think I see as a formality which will lead to closing of the transaction around the middle of the year. And this is what the combined company looks like. It will have reserves and resources of over 2.7 billion BOEs. Production today will be around 400,000 BOEs per day in 2022, and that will grow to over 525,000 BOEs per day in 2028. You can see industry leading low operating costs of less than $7 a barrel and industry leading low carbon emissions of around one quarter of industry average. providing the combined entity the opportunity to continue a progressive and market-leading decarbonisation strategy, which I think you will hear more about from ACA BP in their Q4 results. And also delivering sustainable and growing dividends. And this creates a company of scale, production growth, low cost, low carbon emissions, which, as I say, I think will prosper through the energy transition. And for the remaining Lundin Energy business, this will be a new renewable company that we intend to grow. It has three high-quality renewable assets in the Nordics, which when fully built out will produce 600 gigawatt hours per annum net. This business will be debt-free and with significant cash reserves to complete the projects and generating free cash flow from the end of 2023 and with the financial capacity to grow the business. We also intend to position this to pursue other opportunities and consider other opportunities through the energy transition. The business will remain listed on the NASDAQ Stockholm Exchange. And I think this is really a great opportunity to grow and create further significant value from this business. And we will outline what the business plan, the management board and governance details are going to be for this on the 7th of March so that you can understand the opportunity ahead of our AGM. So that's what I wanted to cover. So now I'm going to hand over to Dan who will give you some more details on our operations. So over to you, Dan.

Thank you, Nick. And it's a pleasure to be here presenting today what has been a phenomenal year of performance for Lundin. And notwithstanding the ACABP transaction, a really exciting outlook for 2022 with a lot of activity aimed at continuing to grow the business. And so if we look across the operations and the assets that we have today, it's been another year of really good top-tier operating performance. On Johan Svedrup, the excellent performance we've seen over the past 18 months, two years, has continued in the same fashion. And we're going to touch a little bit later on where we see opportunities for further resource growth in Johan Svedrup. On Edvard Grieg, we've seen a reserves upgrade of around 40 million barrels this year, which is more than we produced from the area in 2021. And that comes from not only the Edvard Grieg field, but starting to see some of the upsides in the tiebacks. And so we'll delve into those a little bit more and the activities that we have to continue that growth into the future. We have five new projects moving towards sanction this year, and that corresponds to net resources of around 240 million barrels that we're aiming to mature in towards the reserves at the end of the year. And each of those projects has an exciting potential to continue to grow beyond what we put forward in these project sanctions. If we look at the resource replacement, we've added two barrels for every barrel we produced in 2021. And that comes primarily from the Wisting acquisition we announced at the end of last year, growth in the Edvard Grieg area and the subsea tiebacks to Edvard Grieg as well. And that corresponds to 140 million barrels of 2P plus 2C resource additions in 2021. And the operating performance of the assets really has been world class. We've been at 98% on Edvard Grieg and Johannes Fedrup and 95% on Alfheim, which really is world class performance from all of these assets. And something you'll see which is unparalleled in the industry when you look broadly across not only Norway, but the wider industry. And we've done that at an all-in cost of $3.1 per barrel to us OPEX and a carbon intensity of less than 3 kilograms of CO2 per barrel, which is really world-class operating performance. Nick touched quickly on our production in 2021, and we finished the year above the top end of our original guidance range at just over 190,000 barrels of oil equivalent per day. And you see here the growth towards the tail end of the year with 194 in Q3 and 195 in Q4. And December finished just shy of 200,000 barrels per day. And the outperformance in 2021 really was due to Edvard Grieg and a little bit from Johan Svedrup. Really high production efficiency on both assets. And we saw some increased capacity available on Edvard Grieg, which we took advantage of towards the tail end of the year. And that puts us in a position where now for six and a half years, the company has been delivering at or above the midpoint of its production guidance range, which is really an outstanding achievement all considered. If we look forward towards 2022 and this year, we've given guidance of 180,000 to 200,000 barrels of oil equivalent per day. And that range is really driven by two main themes of activities. In Q2, we'll see turnarounds planned outages on Johan Svedrup, which will be the hookup and commissioning of the phase two platform, which will have been lifted late in Q1 of this year. Edvard Grieg has a planned maintenance turnaround as well in Q2. And then in Q4, we see the start-up of Johannes Frederick Phase 2, and that really drives the opening and increasing of our guidance range towards the end of the year. And there's some flex in that range. In the low side, we see it start later in Q4, and in the high side, we see it starting in the early part of Q4. And so the external guidance for Johannes Fedrup is firmly on track for Q4, and we see a range of outcomes possible in our external guidance for this year. And all of that will be completed with operating costs still in our long-term guidance range of between $3 and $4 per barrel, and we maintain that range as we look forward with another year behind us. 2021, our outturn on the year was around just over 10 cents higher than what we expected at $3.10. Still industry leading levels, but we're impacted towards the tail end of the year by increased carbon prices and increased electricity prices. As we move into 2022, we're guiding at $3.60 per BOE, and that takes into account the fact that we have increased costs in Johan Svedrup, and we don't benefit from all of the production upside we see getting Phase 2 online. We also see an increase in carbon pricing and electricity pricing, which is taken into account in this guidance. As we roll then into 2023 and we see a full year of production impact from Johannes Fedrup phase two, we will see our operating costs reduce back to our long term average of between three and four and down at the lower end of that range while we remain on plateau for Johannes Fedrup. So all in all, we remain industry leading on operating costs and we expect to maintain that guidance going forwards. Our carbon neutral promise still stands firm, and we're now less than 12 months away from being carbon neutral on our operations. And the three key pillars we have driving that carbon neutrality is, firstly, powering our assets from shore. Secondly, powering them by renewable assets, which we've invested in. And third, natural carbon capture projects. And on the electrification, we expect to see this online in Q4 of this year when Edvard Grieg and Johannes Fedrup Phase 2 are both powered from shore. And once we see Phase 2 online, then we'll see Edvard Grieg powered from shore through the P2 platform. Our renewable projects are progressing well, and by the end of next year, all three of the projects will be fully online. Today, Lykanger is fully online, which is a hydropower plant in Norway. MLK, we have around half the turbines generating power. About three quarters of them are fully commissioned and nearly all of them bar one are fully constructed. And so we are slightly delayed from our original plan of end of last year, but we expect to see MLK fully online and handed over towards the tail end of Q1 this year. Then we move into Sweden with our Karsgrove project and that'll be online towards the tail end of 2023. And the activities, project activities have already commenced on Karsgrove. And then our natural carbon capture projects, once we complete those first two pillars, there's a small amount of remaining emissions and our natural carbon capture projects are firmly on track. We've planted around half a million trees to date. We have just shy of three million being planted this year and a total of eight million trees being planted, which will capture the residual emissions from our business. And as we move forward, Nick touched on this a little bit, ACA BP will acquire the assets and will pick up all of the electrification projects and assets. They will also pick up the natural carbon capture projects with the renewables staying behind in Lundin Energy's renewables company. And ACA BP are going to communicate a little more on this when they come out and speak to the markets later in their Q4 results. Then if we start to look through some of the key assets across our portfolio, Johann Svedrup really has had another year of world-class delivery. We've seen emissions from the Johann Svedrup asset at significantly lower than 0.1 kilograms of CO2 per barrel, operating costs down at less than $2 a barrel with extremely high production efficiency and a credit to all of the teams involved in making this performance happen. This will continue with Phase 2 coming on stream, and we see some of the benefits of that, not only on Johansvedrup, but in the whole Utsira High region with the power from shore infrastructure coming on. And so we expect to see this performance continuing on Johansvedrup. If we look at the opportunities for resource growth, and we opened this door a little bit at the end of last year where we're now looking, now that we have more production data from phase one, we're looking at opportunities on how we can continue to grow the Johannes Fedrup field and how we can realise some of the key themes that we see as upside in Johannes Fedrup. The first one that we touched on in our reserves announcement and today in our guidance announcement is on acceleration. And so this year we've put a range of infill wells into our 2P reserves and we see a lot more potential in the field for infill drilling and bringing forward some of the tail end resources from Johannes Fedrip. And this field has an extremely long tail and a lot of volumes which can be recovered over its entire field life. if we're able to take some of those volumes and move them forward, extending plateau and arresting the decline are two opportunities where we can see significant potential and we're doing pieces of work to try and identify and understand what that potential looks like. Secondly, there's some constraints around some of the facility's capacity and reservoir management that we're trying to understand and investigate here. And especially around water handling and water injection, we see some significant upside there. And finally, you can see here the development so far has been concentrated in the field center. And we still see significant opportunity and uncertainty around the outside and the flanks of the field where there's opportunity for further understanding, potentially increased thickness of the reservoir, And further to that, further development, which could see some of those volumes being produced. So with all three of these, acceleration through infill drilling, an improvement in capacity and further understanding and development of the flanks of the field, we see significant running room in Johansvedrup. And that, in the fullness of time, we'll be able to share more details of what that looks like. The Phase 2 project on Johansvedrup is firmly on schedule for Q4 of this year. We're around 70% complete now. We've started drilling on some of the satellite areas and the P2 processing platform will be installed in late Q1 of this year with the hookup and commissioning in Q2. And the project teams are doing a phenomenal job at managing all of the risks and uncertainties with this project, notwithstanding COVID over the last two years and being able to keep this project firmly on track. And not only on track on schedule, we're on cost as well. So we still sit with costs in line with the PDO estimate for Phase 2. Moving now on to the greater Edvard Grieg area. And this really is a core area for Lundin Energy and one where we've seen significant growth and significant upside. And there's still a significant amount of activity in this region. We started with Edvard Grieg at 186 million barrels of 2p reserves when we sanctioned the project. And now in the greater area, we see that growing to 450. If we include the upsides and some potential exploration success, we could be between 600 and 800 million barrels of reserves and resources in this area, which is over four times what we started with. And Edvard Grieg itself is performing well. We've seen outperformance reserves increase. Solveig has grown over the years. This year as well we see reserves increase because of the results of drilling. And we've got three projects in the area. A further development on Solveig, Rolfsnes full field and Lillprinsen to the north where we see future potential to grow in the Edvard Grieg area. Edvard Grieg itself, we announced just shy of 30 million barrels increase in the 2p reserves from Edvard Grieg. And you can see in the bottom left here how much this has grown since PDO. 186 million barrels is now just shy of 380, and we still have upsides to continue to grow that. And where we see upsides, we completed the info wells this year on schedule, on budget, and the productivity from two of these wells with the fish bones is significantly higher than what we expected to see. And so we see further potential to deploy the fish bones more towards the eastern flanks of the field and the eastern core of the field where we have slightly poorer reservoir quality. And that's where we see the real benefit of these fish bone completions by increasing productivity. We drilled for the first time production wells into the Jorvik High and the Jorvik Basin. And we see further running room, which we'll understand a little bit more through the production performance of the wells. In the northern area, we have two wells already producing from the Telus area, where we see a very small layer of Asgard sand sitting above basement. And those two wells in the north have seen a really good charge from the basement into this thin sand, giving us good production performance. And so we'll talk in a slide or two around the whole basement potential in the region, but already we have wells on production in the basement. In Jorvik and in Telus, we have further opportunity in the field to explore what the basement potential could be on top of where this Asgard sand will sit in those regions. On top of that, we have further infill drilling planned in the core of the field as well. So although we've already seen significant resource growth in Edvard Grieg, I don't think we're yet finished with Edvard Grieg. In Solveig, we started this field in Q3 of 2021, and we've seen an increase in reservoir properties due to the results of the drilling campaign on Solveig. And so that drives the increase of 11 million barrels to our 2p reserves. We're now getting ready for a phase two development, which will take into account the D segment discovery we made last year. And there's a well towards the northeast of the field. And in the southwest, you see two wells in the Sinrift section. And so we'll be maturing this project through towards PDO. And we're looking at opportunities. We see segment A there. We're looking at opportunities to further explore and expand Solveig to continue this growth story. And finally, on the Edvard Grieg area, a little bit around Lillprinsen and the regional basement potential in Rolfsnes. So in Rolfsnes, if we start in the south of this, Rolfsnes has a resource potential of between 14 and 78 million barrels of resources. We have the extended well test, which we started up last year. And this well test aims to prove a number of things in the basement. One, that we have productivity over a long period of time. And two, that we have a water cut development that allows for a full field development. And so the stability of the water cut development is key to ensure that the fractured and weathered basement continues to contribute to a well over a long period of time. And we see matrix flow, not only fracture flow, where we see water coming up from underneath the field. And what we've seen in Rolesness is our water cut is stabilising around 45% to 50%. And the key thing is that the stability in the water cut development means we're seeing a lot more contribution from the weathered basement and a lot more contribution from the matrix. And so because we're starting to see this water cut stabilise, it suggests that we've got a significant running room on Rolesness to continue with a full field development. And I think what you'll see on that development is a phased development where we take small steps to further understand the resource potential. And so if we take that knowledge on the basement and step up to Lillprinsen, last year we completed a transaction with Equinor to acquire an extra 20% and take operatorship of Lillprinsen. And then we drilled a suite of exploration and appraisal wells this year. And what we've found is some good quality sands in Lillprinson, but we've also found basement potential below. And so what you see here in the resource range is primarily the good quality sands with a small amount of basement potential. But what we found in that basement is we have three times the thickness or up to three times the thickness of what we do in Rolfsnes. And we also have the oil in Lillprinsen is the same as Edvergrieg and roughly in pressure communication, potentially through the aquifer. So you have this basement potential that extends from Rolfsnes all the way up to Lillprinsen. And we have the ability to go and phase the development in Lillprinsen as well to test some of this basement potential on top of the base. And so if we put our arms around all of that, there's potentially up to 300 million barrels of gross potential in this area due to basement alone on top of what we have in the field and the non-basement potential. And so we'll be spending a little bit more time this year with both the PDOs and the understanding in the area to try and explore what further potential we have in the regional basement in the Atzira High. Stepping out of the Etsira high into Wisting, this will become a new core production area for Lundin Energy. And as Nick touched on earlier, it's a really strategic acquisition for us that adds long life resources into a window where we're looking for that growth. And so we remain firmly on track with engineering and the work required to submit the PDO at the end of this year. And we've also been awarded a further license in the latest APA round, and we'll take a 35% working interest in all of the acreage around wisting and the operatorship of the exploration phase. And there's running room of up to 500 million barrels as identified today on that exploration potential. And we'll be working with Equinor, the operator, to mature that forward. So really exciting area. I think there's more to hear regarding Wisting as we move forwards. In the Alfheim area, the fantastic work that ACA BP have been doing in Alfheim really continues. We see new projects, Cobra East and Cobra East Gecko and Frost were sanctioned last year and they're moving into the execution phase and we should see Trell and Treen moving through the same process this year. And those material additions add significant volumes but also significant production into the profile for the Alfheim area and I think that will continue into the future. Looking at the future growth potential, we have three projects in execution just now, Keg Frosk and Johansvedrup phase two, and then five more progressing to PDO. And those five represent 240 million barrels net resource. And so that project is our short to medium term production growth. And then we have a remaining program of five E&A wells in 2022 targeting around 140 million barrels. And so we'll see those being drilled through the course of the year. And then we have a material program ongoing with still around 100 licenses in Norway and an exciting program for 2023 and beyond as well. My final two slides, looking at reserves, resources and production. On the reserves and resources position, we touched on the 200% resource replacement ratio for 2021. And that's made up of primarily Wisting, Edvard Grieg and Solveig. And so if we look at the reconciliation of our 2P reserves and 2C resources, we see the production of 71 million barrels, We see the Edvard Grieg and Solveig 2p reserve additions of 39, corresponding to around 55% reserve replacement ratio. And then we see the Wisting transaction coming in, less some of the stranded assets in the Barrens, which we took off the books at the end of last year. And all of that together points towards a strong resource replacement ratio, two barrels added for every barrel produced. and over a billion BOEs of 2C resources and 2P reserves. And then my final slide before I hand over to Taita is our long-term production outlook. And we've shared this for the last few years at CMD. And year on year, we see that the 2P reserves position continues to increase. And so you can see on here in the dark blue bars our current 2P reserves position. And you see in the red line what the 2P reserves were at the year end 2020, so 12 months ago. And you see in nearly every year an increase. And our role as a technical and management team is to turn some of the 3P and upsides into 2P reserves over time. And I think you've seen our track record of doing that year after year. And you see the potential in our asset base to continue to do that over time. And so we all believe that 3P and upsides will continue to be added into the 2P and new opportunities will come on top of that. And so our production growth outlook is greater than 200 by 2023 and significantly more, as you can see here. And we will sustain that greater than 200 with this pipeline of projects and new opportunities. And so it's been a fantastic year in 2021, really strong performance across all of the assets. And I think there's a really exciting portfolio for this year to continue. And putting this portfolio together with ACA BP, as Nick touched on, creates one of the world's or certainly Europe's leading and one of the world's leading low cost, low carbon companies with significant growth into the future. And with that, I'll pass over to Taita.

OK, thanks, Stan, for that. And good afternoon, everybody. Or good morning, depending on where you are. So we are now going to go through Q4 financial numbers, which, again, are going to show a very strong quarterly performance. And we're also touching on the full year results for the company. And then towards the end, we will give a brief guidance on the 2022 results. numbers as we see them. And just a comment on the accounting implications from the announced deal with Acker BP, whereby we combine our EMP business with Acker BP. What that means is that from the fourth quarter onward, we will present all the numbers relating to the EMP business as discontinued operations in our consolidated income statement. Similarly, on our consolidated balance sheet, we will present the liabilities and assets associated with that business as assets and liabilities held for distribution. But in terms of the numbers we are presenting here today, you will see everything as normal as we are combining this continued and continued operation together in one financial metric. So starting off with the key highlights for the fourth quarter and also Q4, for the full year and Q4. As we announced ahead of release is that we have had an overlift in the fourth quarter. So the sales volume is 199,000 BOE per day. And that is then the number that drives all the financial numbers we're reporting for the quarter. And similarly, for the full year, we were also over-lifted on an annualized basis by around about 6,000 barrels, so 196,000 BOE per day in terms of sold volume. Oil prices have been very strong, similar to gas prices, $77 a barrel for the crude oil we sold in the fourth quarter, and actually over $200 a barrel in BOE terms for gas, around about $34 per MCF. Obviously, the gas market in Europe has been well advertised to be extremely tight, and that's certainly shown through in our realized gas prices. Costs, we've been through those to some degree, but $3.81 per barrel for the fourth quarter. And we had oil and gas investments of just over $230 million. And also we completed the visiting acquisition in the fourth quarter, so that led to a $320 million cash consideration to OMV for the 25% we acquired. In terms of cash generation for the full year, you can see on the top right here, EBITDA generation of over $4.8 billion for the full year, and cash flows from our operating activities over $3 billion, and then generating free cash flow of $1.6 billion for the full year. And that delivered the debt position of the company down to just over $2.7 billion. And as Nick mentioned, we are again increasing dividends. That was the criteria we set out when we started off paying dividends in 2018. And we've essentially increased dividends in line with financial earnings over that period, except for the year 2020 when we had the COVID impact. But again, a material increase in dividend proposed to the AGM this year of 25%, which equates to just over 56 cents per quarter in quarterly dividend payments. If we then look at some of the key financial metrics that we normally report on as we go through the year, starting off with EBITDA at $1.46 billion for the quarter, that's generated off revenue of 1.55%. And as you can see in the top right corner, very strong sales price for the quarter, $84 per BOE. Obviously, as I mentioned, the gas price is pulling up the BOE number quite significantly, so 94% up on the same quarter last year. And also the sales volume is up 18.3 million barrels, up 6% on the same quarter last year. The cash flows from operation in the fourth quarter came in just below $560 million. In the fourth quarter, we always have a higher tax installment in Norway, given how the phasing of tax installments works. So we paid $710 million in cash taxes in the quarter. And in addition, we also had a working capital build of over $140 million yesterday. given the continued strong oil price performance as we went through the year. So also, CFFO is up more than doubled on the same period last year. Free cash flow before dividend payments, $22 million. That was also impacted by the settlement of the visiting acquisition of $320 million. So we had all in investment levels of $530 million in the quarter. And then in terms of adjusted net results, $293 million for the fourth quarter. But on the face of the income statement, if you combine discontinued and continued operation, we came in at $122 million. Again, the announced acquisition with Accra BP has led to a certain one-off financial items, which we normally just moved through equity, is now having to be charged through the income statement, such as FX and interest rate swaps, which are now all deemed ineffective, given the transaction we have announced. So that movement normally went through equity, whereas now, going forward, that will be fully charged through the income statement. And then a similar outlook for the full year. We generated $5.1 billion of revenue for the full year. So that led, as I said, to EBITDA of $4.8 billion. And at our Q3 numbers, we actually guided EBITDA, full year EBITDA between 4.8 to 4.9. So we came roughly in at the middle of that guidance. And then CFFO came in at, as I said, just above $3 billion. That then includes cash tax payment for the full year of $1.4 billion and also working capital built for the full year of $230 million. So very strong cash flow generation and more than doubling from 2020 numbers. And as Nick said, free cash flow before dividend payments, $1.6 billion for the full year. That's actually covering dividends three and a half times the cash dividend we've paid out over the last year. And then adjusted net results just below $800 million when we take out the non-cash FX impacts we have on numbers. And on the face of the income statement, we have reported just below $500 million in net profit for the full year. Just touching a bit more in detail on our realized crude prices as we've gone through the year. You can see on the chart to the right here that we are showing the timing difference, which is the orange bar on the average stated breadth for each quarter. And you can see in the first half of the year, The timing of our lifting led to us actually outperforming on realized prices, half a dollar in the first quarter and one dollar in the second. But you can see that trend then reversing in Q3, Q4. Particularly in Q4, you can see on the chart to the left, we had a high lifted volume in December just as the dated Brent was dropping. And that's therefore led to a timing difference of $1.70 for the fourth quarter, negative impact on our realized prices. And the red bars you see here are then the differentials to the dated brand. And we've sold between half a dollar to two dollars differentials in each of these quarters. But it's been a very busy year for our crude oil marketing department. We've sold close to 100 cargoes for the year, so almost two cargoes per week. So the team here in Geneva has done a great job in firstly marketing and then selling all these cargoes. And on gas, gas prices, it's been very much an increasing trend as we've gone through the year. And actually, in December alone, we realized the $240 barrel per BUE equivalent in realized gas prices. So a very strong macro environment here on gas sales in Europe. We are selling both into the U.K. market and into the Dutch market. gas market on pricing ahead. And of course, importantly, when Edward Greek will be fully electrified at the end of this year, our gas sales volume will obviously increase since we are not going to burn any gas on the gas turbines on Edward Greek. So that will lead to even further revenues from our gas production when we look into 2023 and beyond. Then looking at operating costs and EBITDA margin, we continue to very much have industry-leading unit operating costs out there, which is leading to an exceptionally high EBITDA margin. You can see here 94% in Q4, and in fact, it's been around about 94% over the last five quarters. On the chart to the left, you can see there was a little bit of an uptick in unit OPEX for the fourth quarter. And Dan touched upon this already, but you can see at the bottom of the bars here, you can see the actual impact from higher electricity prices and also higher CO2 prices. Both of those prices increased roughly 50% from Q3 to Q4. So that was leading to a somewhat higher unit OPEX, also combined with a somewhat stronger Norwegian kroner compared to previous quarters. So all in that has pushed the unit OPEX to $3.81, but nevertheless still extremely low. And for the full year, as Dan said, we came in at $3.10 for the year as average. Then looking at tax, the top two charts show the Q4 effective tax rate on the face of the income statement of 89%. But if we then again adjust for the non-cash financial items, which have very little tax impact for us, then you can see we get to a 79% effective tax rate, which is very much in line with what you would expect, given that we operate in Norway, where you have a 78% effective tax rate. And then the chart on the bottom here shows you the facing of our cash tax installments. As I mentioned, in Q4, we had a significantly higher tax installment given that you make two tax installments in that quarter. So $711 million installed in Q4. and if you sum up all of the quarter last year we paid 1.4 billion dollars but you'll also see on our balance sheet that we have a tax liability current tax liability of close to 1.6 billion dollars and that's then the cash tax catch-up payment we have to make in first half this year to fully settle the 2021 tax due so you can see we have already locked in these tax installments of $510 million in Q1 and just over a billion dollars in Q2 based on the year-end FX rate of 8.8 NOC to the dollar. So those are the locked-in tax installments we already know we have to make in Q1 and Q2. Then looking at the full-year cash generation for the business, which, as I said, was very strong, the organic CFFO before we adjust for the working capital came in at close to $3.3 billion, and after working capital, $3.58 billion. We have total investments during the year of just over $1.4 billion. Around about $300 million relates to E&A, and $320 million relates to the listing acquisition. And then the delta is split roughly a third, a third, a third for Edward Grieg, Johan Sverdrup and Edward Grieg, with some smaller items also on the on the Alfheim area. So that's how we define the free cash flow before dividends of 1.6 billion dollars for the full year. And you can see here the total dividend payment of $455 million and debt reduction of close to $800 million, which therefore gave us a cash build of $370 million. So we're exiting 2021 with a cash balance of $450 million. In terms of debt position and liquidity headroom for the company, at year-end we had gross debt of $3.2 billion, which consists of bonds amounting to $2 billion, and term loans spread over three-, four-, and five-year maturities of $1.2 billion, so in total $3.2 billion. And as I said, rounded, we have cash of just below half a billion dollars. leaving the net debt of $2.7 billion. In terms of available liquidity for the group, we have an undrawn revolving credit facility of $1.5 billion. So in addition to the cash we're holding, we have in total around about $2 billion of liquidity headroom as of year end 2021. If we now turn into guidance for 2022, and what I should emphasize here is that this guidance is provided on a Lundin standalone basis, as if the Acker BP combination is not happening. But as I said in my introduction, from now up to closing, we will continue to report the E&P business as discontinued operations. So the numbers here are essentially reflecting no deal happening at all and the year would be as a normal EMP year for us. So the guidance here, the key highlights are, as I said earlier, the dividend of $2.25 per share, and that will be proposed to the AGM in 2022. And we will then commence our quarterly dividends as normal until the deal with Accra BP completes. The CFFO guidance we are giving here is between $1.3 to $2.1 billion for the full year, and that's on an oil price range between $0.65 to $0.85 billion. dated Brent average for the full year. And on the midpoint of the price bracket we give, which is $75 Brent, we anticipate to generate free cash flow after dividend payments for the year. So that will reduce net debt to EBITDA down still further to roughly 0.5 times the ratio at year-end 2022. We've been through the OPEX guidance, and as we announced this morning, the oil and gas investment is estimated to amount to $760 million, and then renewable and natural carbon capture projects amounting to around about $70 million. And then running through the details of our guidance as we normally do. So if we focus on the mid column here, which is our base case planning assumption on oil price in 2022, $75 and 100 pence a term in gas price. That will then generate a revenue per barrel of $76.70, which is $5.3 billion in absolute revenue, giving a cash margin of $5.1 billion, or around about $73 a barrel, and an EBITDA net back of $72.40 per barrel, or just above $5 billion in EBITDA generation, based on our midpoint scenario of $75 Brent. And then in terms of P&L impact, as I said, the cash margin, $73 a barrel. We have a depletion charge of just below $11 a barrel, which is slightly above the depletion rate we ran with in 2021. And the GNA is running, as usual, at a very low rate, 60 cents per barrel produced for the year. And then financial items, which includes income from joint ventures, which are our renewable projects in Finland and like Hungary and Norway, amounting to $2 a barrel, so giving us profit before tax. just below $60 a barrel. And then the tax charge, around about $47 a barrel, giving us a net after-tax profit of $12 a barrel. And you can see here the current tax as a percentage of the EBITDA generation in the midpoint oil price scenario, 61%. And that will equate to roughly just over $3 billion in current tax for the year 2022. And that tax calculation is based on the proposed new tax legislation in Norway, which is going through Parliament soon, but hasn't been ratified as yet. But the numbers are based on that it will be. And then the last slide on net back guidance for us here. This is the cash flows from operation for 2022. And we are sitting, as I said, between $1.3 billion at the $65 case up to $2.1 billion in the $85 case. And in this year, we will have the cash tax payments will actually mirror to a large degree the current tax that we will charge to the income statement, given that we have a $1.6 billion cash up cash tax payment to make this year relating to the 2021 tax bill. And you can see here all the capital items are amounting up to $12 a barrel, around about $830 million. So that will therefore give us a free cash flow available for dividends of between $6.8 to $18.3 a barrel. So certainly in the $75 and $85 cases, you can see that we are more than funding the dividend payments we are proposing. And in the $65 case, we are slightly drawing on debt to fund the dividend to the tune of $140 million. But the bottom line here is that it's a low OPEX business and it's also a very low CAPEX intensity business. All in CAPEX to grow production further is only $12 a barrel for the full year. And if we then look out in time and focus on the CAPEX profile we have, if we focus on the 2P plus firm, which is essentially our 2P reserves plus visiting and some of the projects in the this year and a similar level next year. And then when investing expenditure starts to ramp up, you can see that we are running at around about $700 million per year for out to 2026. So it'll continue to be a business with relatively low CapEx intensity as we look out in time. And then the lighter blue bars here are the growth projects that Dan talked about, mainly relating to Rolsnes and Solveig expenditures. In 2024, the majority of this spend would relate to Rolsnes. And then in 2025, you have a roughly 50-50 split between Rolsnes and Solveig Phase 2 in terms of development expenditure. And my final slide before I hand back to Nick is just a quick summary of the guidance we have set out in our press release this morning. So 180,000 to 200,000 BOE per day for the full year guidance. And all our numbers in terms of net back guidance was based on the midpoint of this, 190,000 BOE per day for the full year. We've been through the OPEX, which is slightly up, $3.60 for this year, but dropping down to $3.10 again in 2023, when we have a full year worth of Phase 2 Johan Sverdrup contribution. And the capital items that we went through earlier amounting to $830 million, including renewables and carbon capture expenditure and some decommissioning costs. So with that, I will hand back to Nick with some concluding remarks.

Well, thanks, Dan and Taita. I've just got one final slide before we open up for questions. I just want to leave you with these three key messages. First, we delivered record operational and record financial results in the year, supporting increased dividend proposal to the AGM. Secondly, the proposed combination of Lundin Energy's E&P business and ACA BP creates a leading European independent E&P company, which I'm convinced is a win-win outcome for both sets of shareholders. And it's expected that that transaction will complete around the middle of this year. And then thirdly, the remaining Lundin Energy is a new renewable energy business positioned for growth. And we'll provide you more details about that and the strategy for that business in early March so you can understand the opportunity. So those are our full year 2021 results and our outlook for this year. Thanks for your time. And we'd now like to open up the call for your questions. And I think Ed is going to run that process for us.

Thanks very much, Nick. Mark, we'll open up for questions from your conference call line first, and then you can hand back to me and I'll see if there's any from the web. So over to you, Mark.

Thank you. To the callers on the phones, if you do wish to ask a question, please dial 01 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 02 to cancel. So once again, that's 01 to ask a question, or 02 if you need to counsel. Our first question comes from the line of Sachikant Chiluru of Morgan Stanley. Please go ahead. Your line is open.

Hi. Thanks for taking my questions. I had two, please. The first was related to the 2022 to 2026 CAPEX guidance. If I were to compare today's guidance with the one presented in last year's Capital Markets Day, It appears there is a significant increase in the underlying capex levels. And here I'm comparing the capex required for the 2P reserves with last year's total capex projections. If you could let us know the key reasons for the increase. You mentioned capex for Raltsnes and Solveig. Is that the only reason for the increase or are there other reasons as well? Also, if you could reconfirm, again, the CAPEX guidance for the discovered and the contingent resource upside, that is primarily for the visiting development, I suppose. The second question was regarding the comment made on the reduction of the 2C contingent resource base that was related to the standard assets in the Barents Sea. I was just wondering if they could provide more details on what these resources were, if there were any key discoveries that you had previously highlighted that would be helpful. Thanks.

Tite, do you want to get the first one and maybe Dan the second?

Yeah, I can. On the CapEx guidance, so what we call 2P plus firm includes obviously all our 2P reserves and the bulk of that remaining expenditure really relates to the build-out of Johannesburg Phase 2. But what we call firm here is the majority of that is the visiting development, which is a material CAPEX project, obviously, up in the Barents Sea. When we guided last year, we only had 10% of visiting in our numbers, whereas with the acquisition with OMV this year, that number is now 35% equity in the visiting development. And from 2024 onward, the bulk of the 2P Plus firm really relates to the visiting, the building out of the visiting development. So that is the answer to that.

I think on the Barents Sea assets, the small discoveries are Nidans, Salina, Filakuti, small 10 to 20 million barrel gas or small oil stranded assets. So nothing of any materiality in the Barents.

Great. Thank you very much.

Thank you. Our next question comes from the line of Johan Chalenton of Société Générale. Please go ahead. Your line is open.

Yes, good afternoon, everyone. Thank you to Taito to provide that much granularity on the financial section of the presentation. I would like to come back onto this slide showing the CAPEX profile. interesting to know is that it's possible to understand how much of wasting project is shown here because of course as you said wasting will only start to impact capex from 2024 onwards first oil as we speak also the project has yet to be sanctioned is lately slated sorry for 2028 so on this slide basically what is the share of of the full capex associated with Wisting that is shown. And then the second question will be trying to come back onto some content you used to provide to the investment community that was your free cash flow breakeven sort of level over the mid-term. Are you able to provide any color on this on your E&P portfolio indeed over the mid-term? What sort of free cash flow breakeven we should sort of have in mind. And then the final question is in relation to the portfolio or the inventory of resources that could be CNFID by the end of this year to benefit from tax relief. Are you able to provide a bit more color on the share looking away from wasting as part of this inventory? Thank you.

Yeah, shall I take the topics? Yeah, I mean, we guide out to 2026 here, and I should say... The visiting project is scheduled to start up in 2028, so obviously there will be continued CAPEX both in 2027 and 2028, and probably some drilling beyond that even. But we align the CAPEX guidance here with our production guidance, which we're also showing out to 2026. But what we are giving guidance on is the full-scale CAPEX of visiting projects. 65 to 75 billion NOK, I think the number is, or thereabout. So I think you can take your 35% net from that and you can roughly eyeball it because from, obviously we will have some Johan Sverdrup numbers in 2023 and beyond for drilling. And there will also be the cake and frost developments in the Alvheim area. But as I said, the bulk of this will be visiting development. So I think you can eyeball roughly what 2027 and 2028 expenditure will look like without knowing the exact facing of that. And, of course, the PDO on this thing hasn't been submitted as yet. So the caveat on this is, of course, also that we need to see a more exact facing of the CAPEX when we submit the PDO. And then in terms of your free cash flow breakeven, I mean, we didn't feel it was appropriate for us, given the deal with Accra BP, to guide beyond 2022. Otherwise, we normally would have done that. Well, I think it suffices to say you again look at the CapEx profile we're showing here and you see the growing production profile that we're showing. That should explain to you that the capex intensity per barrel will remain low, and our long-term opex guidance between $3 to $4 a barrel is also a very low number. And with reducing debt and cheaper debt with investment rates in place now, all the elements are in place for us to continue to have an extremely low free cash flow break-even price for the business as we look forward.

I think your question on the resources, so on the slide we said 240 million barrels. In Wisting, we're 35% of the 500 million barrel discovery, so just shy of 180 of that is Wisting. The remainder net resources in the remaining four projects. Hope that helps.

Okay, thank you both.

Thank you. Our next question comes from the line of Carl Peterson of ABG Sandal Collier. Please go ahead. Your line is open.

Thank you, guys. I just wondered about the production profile for this year. If you could elaborate on the magnitude of the program on Svrgruppe during the second quarter and also on Edvard Grieg, for how long time will there be downtime on those assets? And then looking ahead, I guess, are there Do you have any indications on the development of the regulatory process regarding the merger with or the transaction with OckerBP?

So, Dan, why don't you get the first one and I can take the second. No problem. We're not going to give exact guidance for exactly how long it's going to be shut down because we have a range in our profiles. I think you can see from Q1 and Q3 where there are no outages, the rough level of where our production would normally sit. And I think if you think in the order of a small number of weeks for those outages on both Edvard Grieg and Svedrup, that's around the right ballpark.

And in terms of the regulatory process for approval, as I mentioned when I spoke for the transaction, both sets of shareholders will vote, ours at the end of March and ACCA BPs early April. We also have government approval to achieve and also competition authority approval in Norway, and those are the only competitors. real regulatory approvals that we have to get. And I think our feeling is that those are really a formality. It just takes a bit of time, and that's why it takes from now until around the middle of the year to close the transaction. So it's very low risk to this deal not going ahead, given the nature of the shareholding of both companies and the quality of the transaction and the regulatory approvals that are required. I hope that gives you a clear understanding.

Yeah.

Thank you. There's currently one further question in the phone line. So just as a reminder to participants, if you do wish to ask a question, please dial 01 now. The next question comes from Al Stanton of Royal Bank of Canada. Please go ahead. Your line is open.

Yes. Good afternoon, guys. Just two simple questions, really. With respect to development and exploration spending in 2022. Can you give us any flavor of the timing, whether it's just chunked in 25% per quarter or whether there's any additional guidance or color you'd provide on that, whether there's any heavy quarters? And then a separate question on gas. I'm just wondering if gas sales are purely driven by the GOR or whether there is some pressure maintenance that consumes gas that you might be able to redirect towards additional gas sales, as you've mentioned, with the electrification of a degree. Thank you.

Dan, why don't you cover both of those? Yeah. Firstly, on the gas side, I think most of it's associated gas. We don't have a big gas injection program that we can swing in and move the amounts of produced gas. So I think, Al, the amount of gas production you've seen over the past period, you'll probably see going forwards as well. And I think the E&A and development spending, most of, if we focus on the appraisal spending first, most of that is linked to studies and activities towards the PDOs. So I think you'll see that roughly spread over the course of the year. And similarly with the exploration spend, it'll be spread between the wells and with five wells spread over the course of the year, you'll see a rough spread rather than all of it being done in one quarter.

And the development standard of 590 is that basically whatever it is, 150 a quarter is the best guidance.

Yeah, so the... And, Taito, you jump in if there's anything to add. But the... So, Johannes Fedrup makes up a big portion of the development spend there, and most of that will be spent as you roll between now, evenly, until you get into the final commissioning and start-up phase. So you'll see that fairly linearly over the course of the year. And then, depending on the final out-term on cost, we may see some of that coming out over time. Let's see. On the remaining spend, we will finish the development drilling on Solveig in Q1, and so you won't see heavy development spend in the Edvard Grieg area after that period, other than for the Edvard Grieg Power From Shore project, which will be linear through most of the year until we get into the commissioning at the end. So I think you should roughly see most of this, Al, on both the development and E&A spread fairly evenly through the year. Obvious ups and downs as you go.

Cool. Perfect. Thank you. Thank you. We've had one further question come through on the phone lines. That's from James Thompson at JP Morgan. Please go ahead. Your line is open.

Great. Thanks, guys, for the presentation. Just a quick one for me. Obviously, you know, stronger oil price backdrop. Everyone's making a little bit more money in the upstream. I just wondered if you could maybe talk to us a little bit about The differentials, particularly on the low-carbon crew front, the idea that you may well start to get a bit of a premium for Sverdrup cargoes because of the low-carbon nature and also Edward Greaves. So it feels like the environment is probably better to be testing the walls on that. Could you maybe talk a little bit about any success or otherwise that you've had in trying to capture some of that delta?

Titus, do you want to have a go?

Yeah, I can. Hi, James. I mean, it's been a story we've been telling for some time now, and we've been working really hard at getting to the great position we now are in, which means that sort of 60% of our production is produced carbon neutrally, and it's actually fully certified, both in terms of the emissions and also the offsets. that we have purchased for Johan Sverdrup. So it essentially means that every time we now lift a Johan Sverdrup cargo, it is essentially a carbon zero cargo. And whilst it's still not showing true in the numbers we presented today, but we have actually now sold a few cargoes on Johan Sverdrup with a carbon premium implied price. on the overall price is still selling at a discount to data brain, but at a lower discount than it otherwise would have. But I would say the numbers are relatively modest at the moment. But you know, we continue to, to tell the story and to articulate the benefits to our buyers from buying carbon neutral cargos. And we firmly believe that over time, that will be manifested in the in the in the prices we're going to achieve.

Brilliant. Thanks, Peter.

Thank you. And there are no further questions on the phones at this time. So I'll hand back to the room for the questions from the webcast.

Thanks very much, Mark. I'm just checking on the web here. I think because of our unbelievably good disclosure, there's no further questions from the web either. So with that, I'll draw the meeting to a close. But if anyone has any other questions that they need answering, please don't hesitate to drop me a line and we can take it offline. So thanks very much for joining.