Welcome everybody. With me on the call today are John Evans, our CEO, and Ricardo Rosa, our CFO. The results press release is available to download on our website, along with the presentation slides that we'll be referring to during today's call. May I remind you that this call includes forward-looking statements that reflect our current views and are subject to risks, uncertainties, and assumptions. Similar wording is also found in our press release. I'll now turn the call over to John. Thank you, and good afternoon, everyone. I will start with highlights from the fourth quarter before passing over to Ricardo to cover the quarterly and full-year financial results. Turning to slide four. In the face of a challenging year with difficult macro conditions, Subsea7 has delivered well, particularly in the fourth quarter. Our activity levels in Q4 improved sequentially from the third quarter, driven mainly by SURF and Conventional. Revenues were up approximately 14% year-on-year, and our EBITDA margins improved to 16%. We ended the year with a strong balance sheet, with $512 million of cash and equivalents and net cash of $49 million. During the quarter, we mobilized our new vessel, Seven Vega, to the Gulf of Mexico, and it started its first job a few weeks ago. Bacalhau FEED was completed. Finally, advancing our energy transition goals, we launched the Subsea7 carbon estimator, which I'll talk more about later. Turning to slide five and our operational highlights. In the fourth quarter, we were active in the U.K. for both an oil major as well as a new generation of independent. For Shell, we executed the offshore installation scope for the Arran tie-back and continued work on the Pierce project, as well as the Penguins redevelopment. For IOG, the Seven Arctic was busy installing pipelines for Phase 1 of the client's southern North Sea gas project at Blythe. In Brazil, Subsea completed the installation of flexibles and umbilicals on Lapa North East. In the Gulf of Mexico, along with our partners in the Subsea Integration Alliance, we made good progress on the Mad Dog 2 project. In Angola, Seven Borealis and Seven Arctic were both active, tying back Zinia to the Pazflor FPSO, and this project was over 90% complete at the end of the quarter. Engineering work continued on Sangomar in Senegal, as well as on a variety of projects in the Gulf of Mexico, including Anchor, King's Quay, and Jack/St. Malo. The Life of Field business unit achieved high vessel utilization in the fourth quarter with work on its three long-term contracts in Azerbaijan, U.K., and Norway, as well as activity in the North Sea and the Gulf of Mexico. The Renewables business unit continues to make good progress on Seagreen, with fabrication of the jackets and inner array cables well underway. Meanwhile, work in Taiwan did not resume as planned, and some of this activity has now been rephased into 2021. Turning to slide six. As we've noted before, large new orders in this business can be lumpy. We had a quiet fourth quarter, but intake for the year was a robust $4.4 billion, resulting in a book-to-bill ratio for the year of 1.3. Since the quarter end, we've announced two contract awards, including our first carbon capture and storage project for Equinor at Northern Lights. At the year end, we had a backlog of $6.2 billion, our workload for execution in 2021 is $4 billion, giving us good visibility on the project activity in the coming 12 months. Now, I'll pass over to Ricardo, who will run through the financial results in more detail. Thank you, John. Good afternoon, everyone. Slide seven shows our income statement highlights. Fourth-quarter revenue was $1 billion, 14% higher than the prior year period, reflecting higher levels of activity in our Renewables business. Adjusted EBITDA of $165 million, including net costs associated with COVID-19 of approximately $5 million, was flat year-on-year. This resulted in an Adjusted EBITDA margin of 16%, about 260 basis points lower than the margin achieved in the prior year quarter due to lower activity and fewer project completions in SURF, partly offset by improved activity in Renewables. In the fourth quarter, we recognized asset impairments of $94 million, mainly related to vessels, including the Seven Mar, which had been classified as an asset held for sale at the beginning of 2020. In addition, the quarter includes goodwill impairment charges of $27 million, split equally between the Life of Field business unit and SURF and Conventional. The net loss was $103 million, equivalent to a diluted loss per share of $0.35. Turning to the full year, revenue in 2020 was $3.5 billion, down 5% year-on-year due to lower activity levels in SURF and Conventional, partly offset by higher activity in Renewables. Adjusted EBITDA was $337 million, after incurring restructuring charges of $86 million and net costs associated with COVID-19 of approximately $70 million. This equates to an Adjusted EBITDA margin for the year of 10%, a reduction of around 7 percentage points compared with the prior year. In the full year, we recognized goodwill impairment charges totaling $605 million, as well as asset impairments of $323 million, mainly recognized in the second quarter and reflecting the deterioration in outlook for oil and gas markets. The net loss was $1.1 billion for the year, equivalent to a diluted loss per share of $3.67. Turning to slide eight for additional details of the income statement. Administrative expenses in the fourth quarter included $15 million of office lease impairment. Excluding the impairment, fourth quarter administrative expenses diminished by $27 million compared with the prior period, and for the full year, they declined by $40 million compared with 2019. The reductions were driven by reduced staffing levels, lower tendering activity and travel costs, reflecting our cash cost reduction initiative. For the full year, administrative expenses included $11 million of costs related to the group's resizing program. Full year depreciation and amortization decreased by $42 million compared to 2019, reflecting the exit of Seven Pelican and Seven Mar from the fleet, partially offset by depreciation associated with Seven Vega, which entered the fleet in the fourth quarter. The tax charge of $33 million in the full year reflects the fact that we were unable to recognize tax credits on losses incurred in certain jurisdictions, the limited tax relief associated with impairment charges, as well as the impact of irrecoverable withholding taxes. On slide nine, we revisit our cost histogram that shows our expenses divided into four main categories. In 2018 and 2019, we highlighted the tight rein we had kept on costs as the offshore recovery got underway. In 2020, you can begin to see the impact of the cost reduction plan as we realigned our business to a new macroeconomic outlook. Vessel and other costs, excluding impairment charges, fell to approximately $300 million. We ended the year with 30 vessels in our active fleet, down from 32 at the end of 2019. We released two chartered vessels and stacked two of our own vessels during the year. We had planned to stack an additional two vessels, but in September, we received an extension of the contract on Seven Sun, and we took the decision to convert Seven Phoenix for use in renewables as a cable lay vessel. Our intention remains to reduce the fleet as activity levels dictate. Our personnel costs fell to approximately $900 million in 2020 as the planned headcount reduction progressed during the second half. Direct project costs are a function of the volume, mix, and phasing of our activities and the pricing environment for procurement. In 2020, we saw a slight increase in our procurement costs, driven by the mix and phasing of our portfolio of projects, particularly Seagreen. Supply chain pricing remained stable in 2020. On slide 10, we summarize the performance of our operating business units after excluding all goodwill and asset impairment charges in the current and prior year quarters, and for the full year 2020 and 2019. The SURF and Conventional business unit generated $715 million of revenue in the fourth quarter, 6% below the prior year, mainly due to weaker activity in the Middle East and lower conventional activity in Africa. Our SURF activity in Africa has been more resilient. This quarter, the Zinia project in Angola made a significant contribution, as did Sangomar in Senegal. We recorded strong revenue in the Gulf of Mexico on Mad Dog 2, King's Quay, and Ichalkil, and in Brazil from the PLSVs. The U.K. was also a bright spot this quarter, with contributions from the Blythe, Penguins, Pierce, and Arran projects. Life of Field revenue in the quarter was broadly in line with last year at $66 million. Renewables and Heavy Lifting revenue was $234 million, a fourfold increase compared to the prior year, mainly driven by activity on the Seagreen project. It represented 23% of group revenue. Net operating income for SURF and Conventional was $38 million compared to $99 million in the prior year quarter, mainly due to fewer project completions as well as the adverse impact of COVID-19. Life of Field reported net operating income of $10 million in the quarter, a significant favorable swing from the loss of $3 million in the prior year period. Renewables and Heavy Lifting recorded a net operating loss of $1 million, compared with a loss of $26 million in the prior year quarter, driven mainly by significantly higher revenue related to the Seagreen project. Turning to the full year, SURF and Conventional revenue fell 19% year-on-year, while revenue from Renewables increased nearly threefold and represented 18% of the group total. Seagreen was the largest contributor to the group's revenue in the full year, with good contributions as well from Zinia and Mad Dog 2. Life of Field revenue was broadly flat compared with 2019. Net operating income fell sharply in SURF and Conventional and remained negative in Renewables. Life of Field reported a $28 million net operating income, a significant improvement year- on- year, driven by successful efforts to right-size the organization, increase activity in Brazil, and steady IRM work in the North Sea. Slide 11 shows our cash flow waterfall chart for the full year. Net cash generated from operating activities was $447 million, including a $192 million favorable movement in working capital. The latter was driven by the timing of milestone payments on EPCI projects, including Seagreen, and lower working capital requirements due mainly to much-reduced activity in the Middle East. Our capital expenditure was $183 million, below our guided range of $200 million-$230 million, and reflecting our continued focus on capital discipline and preserving cash. We spent approximately $70 million completing the construction of Seven Vega and $5 million on the conversion of Seven Phoenix, which is due for completion in the second quarter of 2021. During the year, we incurred $104 million in lease payments, mainly related to chartered vessels. At the end of the year, we had $512 million in cash and cash equivalents, an increase of $114 million from end 2019. Our net cash position improved to $49 million, including lease liabilities of $254 million. Our capital allocation strategy, as shown on slide 12, remains unchanged. You are familiar with our three objectives: reinvesting in the business, protecting the balance sheet, and returning excess cash to shareholders. As I mentioned in the previous slide, we continue to invest in the business in a disciplined manner with a focus on digitalization and technology, as well as selective investments in Renewables. We maintained a strong balance sheet during the year, helped by our swift and decisive action to realign our cost base with the reality of the new macroeconomic environment. We also enhanced our liquidity position this year with the addition of a Euro Commercial Paper program equivalent to approximately $800 million. This, along with our revolving credit facility of $656 million, remained undrawn at the year end. As we announced separately this morning, we have entered into a $500 million five-year amortizing loan facility backed by a $400 million guarantee from the U.K. Export Finance. The group has a two-year availability period during which to draw on the facility, and the facility has a five-year tenor, which commences at the end of the availability period or when the facility is fully drawn, if earlier. The facility can be used for general corporate purposes, including to provide working capital financing for services provided from the U.K. Marking its confidence in the final position and outlook for the group, the board has recommended that shareholders approve a dividend per share of NOK 2, equivalent to approximately $70 million. This continues our consistent track record of returning excess cash to shareholders, which, over the past decade, has amounted to nearly $2 billion. Slide 13 shows our guidance for the full year. Last quarter, we provided guidance on revenue, EBITDA, and net operating income for the full year 2021. This remains unchanged, today we provide more color on the outlook for the year. The operational and financial impact of COVID-19 remain very difficult to predict, but early indications are that we will likely incur a charge in the first quarter not dissimilar to Q2 and Q3 of 2020. In addition, we expect the impact of seasonality on the first quarter to be quite pronounced. Turning to the full year, and bearing in mind my comments on COVID-19, we expect revenue and Adjusted EBITDA to be above 2020 levels, and we expect net operating income to be positive. Our administrative expenses are expected to range between $220 million and $240 million. Net finance cost is expected to fall between $15 million and $20 million, while depreciation and amortization expense is expected to be between $430 million and $450 million. Our tax charge for the year is anticipated to be in the range of $20 million to $30 million. Capital expenditure in 2021 is expected to fall within the range of $120 million-$140 million, inclusive of the completion of the conversion of Seven Phoenix and dry docking expenditures on the existing fleet. I will now pass you back to John. Thank you, Ricardo. As you know, we clarified our strategy during 2020 and introduced the two elements, the Subsea Field of the Future system and delivery, and our proactive participation in the energy transition. Today, I'd like to talk to you about a technology we launched to enable lower carbon developments, and I'll give you an update on our offshore wind activities. Turning to slide 15. In quarter four, we launched the Subsea7 carbon estimator. this is a proprietary Subsea7 tool that allows us and our clients to optimize the CO₂ emissions associated with their projects. It considers all aspects of the development solution, from the impact of various fabrication and procurement options, to the contributions made by a combination of vessels and different field layouts. Ultimately, we can refine all the elements of the supply chain and the field design to reduce emissions of each project. It also helps us, long term, make informed decisions about strategic investments in vessel hybridization, digitalization, and remote operations. The carbon estimator has been rolled out globally, we now utilize this on 100% of our early engagement studies. Ultimately, it's an important tool in enabling our clients, as well as ourselves, to achieve the desired sustainability goals. Moving to slide 16, an update on our progress in Renewables. Our $1.4 billion EPCI contract for the Seagreen offshore wind development is making good progress. At the year end, it was 18% complete, fabrication at all sites was well underway. We're fabricating the jackets at Lamprell's yard in the U.A.E., as well as at two yards in China. Between them, they're working on around 15 jackets at any one time, we'll begin shipping these to our marshaling site in Scotland in Q2. Seagreen's cables are being manufactured at Hellenic in Greece. At over 300 km, it's our largest cable project to date. Overall, Seagreen is a major undertaking with a complex supply chain, but our successful track record of project and risk management are both part of our differentiating Renewables offering. Our operations in Taiwan are suffering the teething issues of an emerging market, but we are confident that this market offers good opportunities for profitable growth. The profitability of the Renewables business unit should improve as we start work on the 2021 execution portfolio of Hornsea 2, Kaskasi, Hollandse Kust Zuid, and the initial phase of Seagreen. Overall, our backlog for Renewables remains high at $2 billion, including contracts involving the installation of 339 foundations and nearly 1,900 km of inter-array cable. To provide some context, the latter is more than double the quantity of cable we've installed in our entire 10-year history. Of the $2 billion backlog, over $1 billion should be executed in 2021, and we're working on replenishing this order book, and we expect awards to the market in 9 to 12 months' time. To conclude, it's our aim to build a sustainable, robust Renewables business that can deliver revenues in excess of $1 billion per year, with EBITDA margins of over 10%. In 2021, we're making good progress to achieve this goal. On slide 17, we come onto an important topic for many aspects of our business, sustainability. We continue making good progress, both on improving our sustainability of our operations, and importantly, in our sustainability disclosures. 2020 saw the introduction of new sustainability metrics for measuring and reporting our progress, and we've improved our rating with both Dow Jones Sustainability Index and the ISS. The journey will continue with the publication of our second sustainability report next month, which will contain more details of our strategy, our KPIs, our targets, and I hope you'll all read it and find it useful. On slide 18, we have a view of the outlook for tendering in the coming 12 months. As you can see, compared with the last quarter, the bid pipeline for oil and gas projects is improving, although it remains centered on those regions with low oil price breakevens, as well as specific projects with advantaged economics. Tendering in Brazil remains active with Mero 3, Búzios 6, and BMC- 33 all to be bid in the next year. In parallel, we're also bidding in March the next batch of PLSV opportunities with Petrobras. In quarter four, we finished the FEED for Bacalhau, and we expect conversion to a full EPCI in the first half of this year, subject to FID by the client. In Norway, following the introduction of the tax relief for new developments, we're seeing greater activity, both in terms of engineering and tendering for EPCI contracts. Although activity is patchier in Africa, we've started work on the tender for the next phase of CLOV in Angola. In Australia, we continue to monitor progress towards the sanction of Scarborough, for which we are the preferred supplier. In Renewables, we're seeing good opportunities in the longer term in Europe and the U.S., with increasingly ambitious targets for many of our oil and gas clients in expanding their offshore wind portfolio. We have seen BP, Equinor, and Total successfully winning leases in the U.K. and the U.S. in the last few weeks. As we've noted at the Investor Day that we ran in September last year, a reduction in the market is forecast for 2023, but we expect strong growth from 2024 and 2025 onwards. In floating wind, whilst commercial scale projects remain some way off, we see growing interest from energy companies in reducing the carbon intensity of their hydrocarbon production, and they do this through electrification of the infrastructure using offshore wind power. To conclude, we'll turn to slide 19. We finished 2020 in a strong position with a resilient backlog of $6.2 billion, including $4 billion for execution in 2021. We grew the backlog by 20% in 2020, despite the challenging conditions, thanks in part to our focus on oil and gas markets with favorable breakevens and our track record in key markets such as Brazil and of course, Renewables. As Ricardo mentioned, COVID-19 remains a concern in 2021, and we're likely to incur continued incremental cost at least in the first half of the year. However, our financial position and outlook has given the board the confidence to recommend to shareholders a dividend of NOK 2 per share, extending our decade-long track record of capital returns. Now, we'll be happy to take your questions. Thank you. Ladies and gentlemen, a s a reminder, if you'd like to ask a question, please press star and one on your telephone, and wait for your name to be announced. Once again, it is star and one for any questions you may have. And your first question is from the line of Michael Alsford from Citi. Please go ahead. Great. Thanks for taking my questions. I've got a couple if I could on Renewables, please. Firstly, I was just wondering whether you could talk a little bit more about the opportunity in the pipeline. You mentioned about U.S. recent auctions, I just wondered if you could talk a little bit about the opportunities and challenges of operating in the U.S. Then more broadly, you've made some changes to your reporting lines. I was just wondering what was the reason behind that, and does that mean that you maybe would consider spinning the Renewables business out of the group? Those are my questions. Thank you. Thank you very much. Two very interesting questions. My reference to the leases is around the fact that we saw some very good lease awards in both in the U.K. and the U.S., Michael. We saw that the prime winners of those leases were not the traditional utility companies that we deal with, but our Equinors, our BPs, and Totals. At the moment, there's a batch of projects which are on the slide that we show, which are out for bid in the U.S. market, and they are for leases that were awarded a couple of years ago with companies such as Ørsted and Dominion leading that. There will be opportunities this year to bid those projects, and we expect probably those to be awarded to the market either at the very back end of this year or at the start of next year. Working in the U.S. is something we're very familiar with. We've been there for over 35 years. There are Jones Act requirements in terms of local vessels required and such like. As you know, we did the demonstrator project actually for Dominion on that project last year. Again, we have been there. We have executed work in the U.S. Again, we feel comfortable that it's a complex market with its own set of rules, but that's very common in whichever country you work in. In terms of reporting, it was really around the fact that we did very little heavy lift work in oil and gas, and it's a very small percentage of that work. We just tidied up our reporting lines to show that it's purely a renewables business, and if we do any heavy lifting work, that will be covered in the other side of our reporting lines. I hasten to add we've done very little work in the oil and gas space in the last couple of years. In terms of a spin-off, at the moment, we're very clear that there is value for Subsea7 to keep the two businesses together. I come back to the point I made about the fact that our traditional oil and gas clients are moving very heavily into offshore wind. We also see the benefit of flexing our workforce backwards and forwards across the different projects as well as assets. We're redeploying a couple of assets that we may have stacked in oil and gas into wind this year. For us at the moment, we're very comfortable that we have a model which has two different reporting lines, but one common backbone, one common way of working, and we can move our resources around. As the markets will grow, we think that's a good place for Subsea7 to be. Okay. Thank you very much. Thank you. Your next question is from the line of Nick Constantakis from Exane. Please go ahead. Hi, guys. Thank you for taking the questions. A couple, if I may, one on renewables, actually. Starting there, we had one of your peers this morning announcing or discussing execution issues on an offshore wind project. Could you just remind us a bit how you're thinking about risk management, the hurdle rate on this business, and the safeguards you have in place? I'm thinking, for example, contractual terms or how selective actually are you around the operator and the work you're bidding on who is your client? The second one, I guess, Ricardo, the $400 million increase on the backlog for 2021, I'm assuming that's Taiwan. Could you just help us understand the moving parts around the margins year-over-year? I'm thinking in particular change in mix. Do you have a few projects close to completion, are there contingency releases, et cetera? I'll take the first question, Nick. Then I'll ask Ricardo to take the second. What's very important in Subsea7, whether it's in oil and gas projects or as renewables projects, is that go through our gated review process, where we make sure that we understand the risks and the contractual terms in which we're working under. That's a system we worked for many years. It works exactly the same whether it's renewables or oil and gas. There are needs sometimes not to take contracts because of the risk profile that you take on board. For us, we bid that project that's affected. We didn't win it. It was about contract terms. For us, we do have a very clear path where we will take work. We have a very clear path where we won't take work. For me, it's around making sure that we use our governance processes well, and we use our judgment well, and that's how we've built this company up over the years. We know that taking fixed price contracts brings in risk. It's about quantifying the risks and, more importantly, whether you can actually influence the risks. If you can't influence the risk, it's a very dangerous place to be taking that. For us, we use that governance system. We're comfortable with that governance system, and that's the way we run our business. I'll hand you over to Ricardo. Yes, Nick, good afternoon. Taking the first part of your second question, I believe you were referring to the fact that we've increased the level of revenue that we expect to generate from backlog in 2021. That's how I understood your comment. Yes. We had previously indicated we were expecting to execute $3.6 billion. We're now saying that we expect to execute $4 billion in 2021. The reason for that is, if you like, the uncertainty and the impact of COVID on activity in 2020. This was particularly evident in the Middle East, where we had a number of projects that we thought would be delayed, but not to the extent that they have been. We're seeing them now, the likelihood is that the execution will take place largely in 2021 rather than in 2020. This has happened to a lesser extent in other regions and on other projects, but the main drivers being the Middle East. With regard to your second question on margins, here I hope that I've understood the thrust of your question. Our margin recognition is very much based on the percentage of completion method. We review our projects as they progress throughout the year and make sure that our forecasts of costs and overall profitability of the project through its life are as accurate as we can make them. As we progress the project, we execute well to the extent that we minimize risks, we're able to adjust our view on the necessary contingencies and the remaining costs. As a result, you will tend to get a slight hockey stick effect when there are project completions. I mean, an upward hockey stick effect, as the project reaches the end of the execution phase. This, to an extent, has explained some of the improvement in profitability that we've seen in the fourth quarter as compared to the third. Sorry, just on that, would you mind telling us which projects, I guess, you would expect to complete in 2021? Just trying to assess, can that offset the higher proportion of renewables, for example, you have year-on-year? I think I'm not going to run through each individual project, Nick. I think you can determine that from one of the slides in the appendix. I think it's slide 22, which shows major project progression. There you can see those projects which already have achieved a high level of POC, percentage of completion, and they're therefore likely to be completed in 2021. Excellent. Thank you. Thank you. Your next question is from the line of Sasikanth Chilukuru from Morgan Stanley. Please go ahead. Hi. Good afternoon. I had two questions, please. Essentially relating to what's not in the presentation or today's presentation as opposed to what's in the presentation. The first was related to the cost savings program. Last quarter, you had mentioned a delay in achieving this analyzed cash cost savings of $400 million to end 2021. This quarter, I hardly see a mention of that. I was just wondering, does that target still hold true? If yes, if you can provide the progress of that target now, that would be helpful. The second one was related to the slide on the opportunity side. I noticed that the NOAKA project, developed by Aker BP, had been taken off the list of opportunities in today's presentation. I was just wondering why that was, especially given Aker BP is your alliance partner. Thanks. Thank you. I'll take the second and the first, and then Ricardo can talk a bit more about the cost saving. I think Ricardo did make mention of the cost saving in his prepared remarks, and he will give you more clarity on that. NOAKA is still alive. We were just trying to give a list of where we think there were tenders in the next 12 months. NOAKA is a project which will really be pushing in the second half of next year to attempt to get sanction at the end of 2022. NOAKA will be sanctioned, we believe, at the back end of next year. It is very much something that we're working on in the partnership arrangement we have with Aker BP. I'll pass you over to Ricardo just to talk a bit further on the cost savings. Thank you, John. Good afternoon, Sasi. I would draw your attention again to slide nine, where we show our cost histograms over time. If you look at the composition of 2019 and 2020, you can already see that we are on the right track in terms of reducing our cost structure. You can see the impact already on our people costs, which are down $100 million, and on vessel and other costs, which are down $100 million as well. To be more precise, we believe that in the course of 2020, we've achieved over $200 million of savings against our target. This is inclusive of the fact that the resizing program, as far as people are concerned, only really started having effect in the third and fourth quarters of the year. You have to evaluate it from an annualized perspective. In 2021, I believe in our comments on Q3, we indicated that we were still targeting a total of $400 million in cash cost savings on an annualized basis, but that we would not achieve that until the fourth quarter of 2021, as opposed to the end of the second quarter. This was purely because of the phasing of our activity, which, as I mentioned in response to a previous question, has resulted in more work being done in 2021 than in 2020. There's been a slippage there. I think we have covered that topic sufficiently. Sure. Very helpful. Thank you very much. Okay. Thank you. Your next question is from the line of Mick Pickup from Barclays. Please go ahead. Good afternoon, everybody. Hopefully, a couple of simple questions from me. Just on the EBITDA guidance, can you just clarify when you say it's going to improve year-on-year, what we're talking about? What level? Obviously, it's a moving parts issue. I know you can't forecast them, what's the clean number I should be thinking about? Secondly, we've talked about risks here. Obviously, you do about $2 billion of procurement every year, steel prices have just seen this unprecedented rise. Can you just talk how you're protected from that, given the speed of that change in your bidding pipeline? Thanks, Mick. Good afternoon. I'll do the procurement question, then Ricardo can give clarity on the EBITDA guidance. I think as Ricardo mentioned, interestingly, during the year of 2020, we saw supply chain reasonably well controlled and managed. What we have seen is at the very back end of 2020, and as we're now going into the first couple of months of this year, certainly we are seeing certain commodity prices moving upwards. We generally have a methodology where we work with our clients as to how that risk is to be managed. If the clients can give us a commitment early enough, we'll lock it down, and we might purchase materials in advance of a sanction, where we have protection with the clients. If the project doesn't sanction, they're the proud owners of the material. There's other mechanisms then where we will work with the supplier, where we will fix the cost, for example, of fabricating the pipe, but we'll have a escalation and de-escalation mechanism in the contract that will protect a certain percentage of the total value, and that then is referenced to the price of iron ore, for example, or the price of copper, if we're buying power cables and such like. There are a variety of different mechanisms that we have in our agreements, and we try to work them in a manner which is collaborative with our clients, to make sure here that we pass through the risk backwards and forwards in a manner which works. That, in a nutshell, is how we try to do it through two or three different mechanisms that we have along those lines. On the EBITDA, I'll let Ricardo just clarify that for you. Good afternoon, Mick, I'll try and give you a straightforward answer to your simple question on this point. I think our reference EBITDA for 2020 is to effectively add back the restructuring charge, which we see as a one-off cost. As we've highlighted, that represents $86 million on 2020. $86 million plus the $337 million that we reported gives you a reference EBITDA of $423 million. We do call out COVID-19 costs. As far as we're concerned, unfortunately, it's part of the reality of our business today. Any guidance that we give will include assumptions regarding COVID. In my prepared remarks, I did emphasize that this is a variable that is a challenge, and that we continue to minimize. John has reemphasized that in his comments about the first half and the possible impact that it could have. In essence, our guidance on EBITDA for 2021 is inclusive of COVID costs. Thank you. Just a very quick one. You mentioned Renewables being $ 1 billion. Is that enough to make it positive given where you are phasing-wise in the book's procurement? We believe we'll be well on the way to our target this year, Mick, it's our objective this year. T hanks. Cheers. Have a good one. Thank you. Thank you. Your next question is from the line of Vlad Sergievskiy from BofA. Please go ahead. Gentlemen, thanks very much for taking my questions. The first two would be on the backlog phasing, $4 billion for execution this year. Is there any risk or chances of a material rephasing of that? Just trying to compare to our consensus revenues for this year, which is only slightly above $4 billion. Also along those lines, also on the project pipeline. On your graph with potential projects, you mentioned new phase of Guyana development. Are you going to tender for it? Because obviously the prior phases were directly awarded to one of your competitors. Also, in this sense, a lot of projects are in Brazil in this pipeline. Are you expecting any impact from Petrobras' leadership change on the timing of those awards? Thank you, Vlad. There's a number of questions in there. We'll try to answer them for you. If I go backwards, and then you can pick me up if I've missed any of your questions. Brazil, yes, is busy at the moment. We are bidding Mero 3. We are bidding the PLSV extensions at the moment. We expect the next phases of Búzios 6 to be out, and Búzios 7 and Búzios 8 will be out at some point in quite close order. At the moment, we see no change in timing, but it's very early days from the changes that have been made to the leadership of Petrobras. I think, as you can see there, though, there are orders for SPS, there are orders for FPSOs and things being placed for those projects. I do think that we should probably see the momentum keep going, despite any changes in senior leadership. Yellowtail is a project which is the next project for ExxonMobil in Guyana, and that is out for bid, and we are bidding that at the moment. That's not a negotiation. That is a market bid, where after a series of negotiations, Exxon have come out to the market. In terms of the phasing of the backlog, I think Ricardo answered in the last question. The impact of COVID and where work will spill over between one year and the next is the big unknown. We have quite a large program of work in the Middle East, and it's fair to say it's not very easy at the moment to work in the Middle East, to get people in, people out of different countries. The whole logistics chain that we have there is a question for us. I think for us, it's around just how COVID impacts the actual distribution of the projects, and I think that will be what will determine how much of that backlog will come in this year and how much stability we'll have around that. Perfect. That's great color. Thanks, John. If I can squeeze one quick one for Ricardo, please. Any initial thoughts on working capital trajectory during 2021? You are starting some work in the Middle East. Seagreen is progressing. Any other factors to keep in mind here? Yes. Good afternoon, Vlad. It's a good question. I think that my frank answer with regard to 2020 is that I was a little disappointed about our cash balance at the year end. Frankly, we were expecting an even better one. The reason that there was a bit of a shortfall and our working capital movements were not as positive as we'd hoped it would be, is because a number of clients opted to pay us in the first two weeks of January rather than in December, as we expected. To give you an idea, we have been, for the last few weeks, working with a cash balance much closer to $600 million than to $500 million. This being said, you're right to ask the question on working capital. We do expect there to be working capital outflows on a number of major projects in the course of 2021. Both on the renewable side, where we have a heavy procurement activity for Seagreen in particular, but also because the Middle East is picking up. As you know, the payment terms of major clients there tend to result in negative cash flow for the majority of the life of the project. We're ready for it. We have good cash resources, we have good access to liquidity, and we reinforce that access thanks to the new loan facility that we've just entered into and that we announced today. Ricardo, John, thanks very much. Thank you. Thank you. Your next question is from the line of Frederik Lunde from Carnegie. Please go ahead. Thank you, and good afternoon. My question comes back to the backlog. You obviously have very solid coverage for this year. A fairly good backlog position for next year as well. We're coming from six months with virtually no orders, but also currently a very strong oil price. I'm just curious how you see timing of awards being critical for filling up backlog for 2022. Thank you, Frederik. That's a very pertinent question. I guess there's two moving parts to that question for me. One is the fact that 2022, when we physically go offshore in 2022, will be the challenge for our industry of not much work awarded in the back end of 2020 and the front end of 2021. We will need to get our fleet sized and ourselves organized for offshore delivery in 2022 about what exactly we can implement. That's one side of the equation. The other side of the equation is a brightening, I think, in the distance, with our oil and gas clients around the opportunities that they have. As we've been quite open with the market, there are a number of projects where we are the preferred bidder, such as Bacalhau and Scarborough, and longer-term projects such as Pecan and Rovuma become economic and get sanctioned. We're also well-positioned there. For us, it's around the timing of which those projects do ultimately get sanctioned and how they fit together, and how all that comes together in terms of a backlog portfolio that we'll actually have. The question really will be, which we'll have to see over the next six months, is the appetite of our oil and gas clients, whether they feel comfortable to push work further forward. We see the Norwegian market being one where the sanctioning of projects will be the end of 2022, because that's where the cutoff is for the tax benefit. Really, we can see a pickup coming. It's the timing of how all that fits together, I guess, is the puzzle we're all trying to work on at the moment, Frederik. Thank you. Just on the CapEx side, you've been highlighting that you have a fleet suited for the future, but as you see the offshore wind market now picking up speed. D o you have any sort of thoughts on future new builds or picking up secondhand tonnage for that market? Well, I think, Frederik, as I touched on in my prepared remarks and as we discussed in the Investor Day, actually the renewables has a bit of a dip in 2023, then it picks up very strongly in 2024 and 2025. I think our thinking is around where do we need to be in terms of asset base for 2025 onwards. That's a piece of thinking we're starting on at the moment, so we'll keep our minds open to that. It's more around that growth, if you recall in the curve, that there's quite substantial growth from 2025 onwards. We will be putting our minds to what we need to look at there. In the near term, I think we will work our existing fleet, plus the Seven Phoenix, which will come in this year to work the workload we see in the next 2022, 2023, 2024 period. Super. Thanks very much. Thank you. Thank you. Your next question is from the line of Mark Wilson from Jefferies. Please go ahead. Hi, good morning. Thank you for taking my questions. Just one point on 4Q, you mentioned the closeout of the Brazil Lapa project. I'm just wondering how much that contributed to the very good result in the quarter. Are there any projects that close out in a similar fashion in 2021? The second point is the lower carbon estimator. I'd just like to know if you see that as a tangible bidding differentiator or something that all companies are having to include in bids these days. Thank you. Thank you, Mark. I guess as both Ricardo and I touched on in our prepared remarks, the end of the year, generally, a number of our clients want to tidy up their accounts, want to finish off. It's generally to do with projects we've done far earlier than Lapa, which concluded in quarter four. We won't go into individual projects. It's really around certain clients who will generally in life make sure that their position at the year end is clear to them and clear to us. That was one of the benefits we saw in quarter four, along with a good utilization. I guess one thing to think about for us is as we get into quarter one, we will have lower utilization, and we won't have any settlements. We're comfortable with the year, but we will get the bounciness of our quarters. I would ask everybody to bear that in mind as you think ahead for this year. I think that's the first question. The carbon estimator is something that we feel— If you recall, we showed to the market, in one of our technology days, and we've talked about it previously on one of our earnings call, the Subsea Planner, which is a tool that the Subsea Integration Alliance, Schlumberger, and ourselves have developed, which allows you to take the reservoir, then to lay out different field layouts and get the economics and the depletion models run, as well as a graphics package that allows you to see what it all looks like. The one piece we felt that was missing out of that was trying to understand the CO₂ impact of all that. We developed, on a standalone basis, the Subsea7 carbon estimator. It's about a series of packages that we work with our clients on early engagement to allow them to understand fully, because you can trade off recovery, you can trade off CapEx cost, you can trade off OpEx cost, and you can trade off CO₂ emissions. In life in the future, we believe it'll be the combination of those things that will get projects to sanction or not. For us, it was around trying to have the last piece of the toolkit that we wanted to allow us to have a mature discussion with our clients. We're using it now 100% on all our early engagement studies, and we think there'll be merit in that. Whether other people will do that, who knows? I think it's important that we're there and relevant at the table to help make the right decisions, because sometimes it'll be CO₂, and sometimes it'll be CapEx, sometimes it'll be OpEx, sometimes it'll be depletion models that'll define what a field layout looks like. Thank you very much. Very clear. Thank you. Your next question is from the line of Kévin Roger from Kepler Cheuvreux. Please go ahead. Yes, good afternoon. Thanks for taking my question. It is basically related to the fact that, John, during the presentation, you mentioned the floating wind. Over the past years, you have focused your work on the floating wind with the French company Ideol. Recently, BW Offshore, they have announced that they took a majority stake in Ideol. I was wondering what are the impact for you in terms of access to the technology for the floating wind in the next years in terms of business, et cetera? What are the implications for you, please? T hank you, Kévin. Yes, we had a very small share in Ideol, and we decided not to make any competing offer to the BW offer that was made to purchase 100% of the company. It doesn't mean that we're not interested in floating wind. It was part of a portfolio that we had of being involved in projects such as the Equinor. We're doing a number of floating wind studies through Xodus, our early engagement engineering house, as well as us in-house looking at different technologies and where we need to be. I guess the answer to the question is Subsea7 is still very interested in the floating wind arena, and we will continue to look at different technologies and where do we need to fit in that ecosystem as that ecosystem develops over the next few years. That the percentage we had, there was no preemption rights. There was nothing with us on that. We looked at it and decided the best thing to do as a shareholder in Ideol was for BW to purchase their share, Kévin. Sorry for that. Maybe as a follow-up, does it mean that if I well understand it's possible that, let's say in the next 24 months we have a news saying that Subsea7 has developed a new internal technology for the floating wind because you are working on it? We're very open-minded to the technology on wind, I think is the main answer, and we are looking at it very carefully. We're looking as to whether or not we can be technology agnostic and therefore use our project and management engineering skills to run the big EPCI contracts that go with it. Do we need to develop our own technology? Do we need to acquire another technology? We're trying to keep a very open mind as to what we need to do there. This is a race where there are 15 horses running on the track, and we need to try to work out which horses are going to make it to the end of this journey. For us, that's the process we're going through at the moment, Kévin. T hanks. Have a good day. Thank you. Your next question is from the line of Haakon Amundsen of ABG. Please go ahead. Thank you, guys. A question a little bit related to some of the previous questions. You have announced a new loan facility of $500 million, and you say that it will support your strategy of being proactive in the energy transition. I just wondered if you can put some color on what potential investments or use of proceeds from this increased capacity. Haakon, yes, good afternoon. This is an attractive facility as far as we're concerned. As we've indicated, it is designed to further strengthen our balance sheet through diversification. It's relatively long-term, and what is also attractive about it is that we have a two-year availability period before drawdown, which gives us a lot of flexibility. It is designed both for in support of any working capital needs that we may have, particularly where there are U.K. exports involved. At the same time, it's of a sufficient length that it could also assist us with capital investments to the extent that they will support our initiatives in energy transition. At this stage, I don't think we will get specific with regard to particular initiatives or projects that we're involved in. We just see opportunities for growth in renewables, and in particular offshore wind farms. This additional liquidity provides us the reassurance and flexibility we need to grasp opportunities as they arise. All right. Understood. Thank you. I think we've got time for one more question. Thank you. Your final question today is from the line of Amy Wong from UBS. Please go ahead. Hi, guys. Thanks for squeezing me in. Most of my questions have been asked actually at this point. Maybe just one to round out the discussion around order intake, particularly for your oil and gas business. Given, I understand the lumpiness and timing is difficult, would you say oil and gas this year orders will be up year-on-year? W e expect our order intake in oil and gas to be up in the next 12 months. Yes, we do, Amy. We've indicated we believe that Scarborough will sanction. We believe Bacalhau will sanction. There are a number of other projects that we are tendering at the moment that we believe some of the Brazilian projects will come to the market this year. We feel reasonably comfortable that that order intake will be higher in oil and gas this year than last year. Great. Thank you very much. I think I'll just hand over to John to wrap up then. Well, thank you very much for sharing the time on a very busy day today with every one of us all announcing the same day. Thank you very much, and we look forward to talking to you again quite soon, I expect, with the end of quarter one 2021 results. Thank you very much.