Good afternoon or good morning to everyone who's joining us. Thank you very much for joining the Noreco fourth quarter results for 2020. Just a quick reminder that as we go through the presentations, you will be able to ask questions via the site, which we will then be addressing at the end of the presentation. Go ahead and go to the next slide, please. Just a quick set of highlights for the quarter. It's been another solid quarter for Noreco. We've had very solid production, and we've ended the year with our net production out of the DUC at above 28,000 bbl of oil equivalent a day. We continue to see that the three currently producing hubs are providing very stable production, very low decline rates, and will continue to sort of carry us through the Tyra redevelopment period in 2023. We also have seen that the risk mitigation of our successful hedging strategy has given us a fourth quarter price in excess of $63 a bbl equivalent. That, as a result, has delivered a $73 million EBITDA, adjusted EBITDA for the quarter. Euan will be covering all these as we go through the financial summary and financial review today. I think one of the most important things to point out is this has given us $96 million in the quarter in operating cash flow, leaving us with cash on the balance sheet of $259 million. We also have announced the new schedule for the redevelopment of the Tyra hub, and that will now be targeted for first gas in Q2 2023. This has been done to mitigate the risks of the past and ongoing impact of the COVID pandemic. We also, subsequent to the quarter, have announced that we have a fully underwritten $1.1 million RBL with an additional two-year extension, which has been a huge piece of positive news for us going forward. These will be covered as we go through the financial review. Next slide. A quick review of the operations. As I've already noted, we did conclude the year with very strong production, and we continue to see a very low decline rate as we go forward. Therefore, we are quite confident in the cash generation that we will be able to get through the Tyra redevelopment period, in which case, we'll see a significant increase in the cash flow as well. Our full year production did average 28,500 bbl of oil equivalent a day. Our operating efficiency was at approximately 82%. This is a bit lower than we would be desiring, of course, this has had significant COVID impact in 2020. What we did do, however, is identify and ultimately add an additional 200 bbl of oil equivalent a day just in the fourth quarter through gas lift optimization. Something that, on the back of that success, we'll be looking to try to apply throughout the rest of the assets where it's applicable. We also, as of October, have been able to return our offshore manning to the pre-COVID levels. Therefore, we'll be able to get back fully on track with our programs. On the back of the 28,500 bbl of oil equivalent a day coming out of 2020, we'll be guiding to somewhere between 25.5-27.5 going through 2021 in our production. The hydrocarbon split will be approximately 80% to oil and 20% to gas. This is a ratio that will pretty much be consistent through, again, the beginning of the Tyra hub, when we will see a greater proportion of gas. Next slide, please. On the Tyra redevelopment, just to give people a sense of where we are, the year ahead is an exciting year, actually. A lot of work to be done. Fabrication continuing in the yards, and we have the sail away of three of our main components with the accommodation, the TEH sail away, as well as two of the wellhead riser platforms in Q3 of 2021. That will also therefore begin the initiation of our overall offshore hookup campaign. These are significant milestones, and the achievement of these will be a great indication of the project's pace and delivery per schedule. We'll have one last significant sail away in 2022. An awful lot of the brownfield and hookup and commissioning work that then goes on through 2022 as well. Again, targeting first gas in Q2 of 2023. We hit our 2020 spend estimate for Tyra very much right in the middle, with approximately $291 million of cost throughout the year. That's given us, if you want to work up your own foreign exchange rates, the spend to date on the project since FID of about DKK 13.3 billion. We expect, if you see in the lower right corner, the spend going out for the remainder of the project to be very much front-end loaded between 2021 and 2022, with the finish of the work in the yards and the fabrication, and the sail aways and the initiation of hookup. What will be left as we go into 2023 will just be the last part of the hookup and installation, and then we'll have the first gas. We thought it was important to look at Tyra and what the value of the project is once we see that initiation of first gas in 2023. We benchmarked against, via Rystad Energy's data, benchmarked against the other North Sea projects that are out there right now, and I think it's very, very clear that the value of Tyra to the DUC, to Denmark, and to the North Sea is clearly top of the line, where we see a forward NPV from first gas or from project initiation puts Tyra at the top of all these projects. It's one of the reasons we see it as being so critical, and it's one of the reasons we're very excited to actually finish the delivery of the project. Next slide, please. The other thing that's made some recent news in the fourth quarter was the Danish so-called 2050 North Sea Agreement. This was the statement by the Danish government that they intended to cease all oil and gas production from the Danish continental shelf in 2050. We think this actually provides tremendous visibility and stability for us, and it comes from statements we've made even before the 2050 agreement was made. First thing to point out, of course, is this is 30 years ahead that we're talking, and that's even eight years beyond the end of the DUC concession inside of the Danish continental shelf. Although this does terminate licensing rounds going forward, it does not stop many licensing rounds which are associated and tied to existing concessions, and the neighbor licenses are also to be permitted for application. This is something I said long before the 2050 agreement was ever announced. We within the DUC have a significant number of low-cost value creative projects inside of our development portfolio. Therefore, these projects and these development opportunities are not going to be impacted by the 2050 agreement, nor will they be impacted by the lack of any forward licensing rounds. One of the other unique elements of the 2050 agreement is the focus on how it promotes ESG, and in particular, not only promotes but supports things like carbon capture and storage and agreements to be put in place for electrification of the offshore installations. Both of these are things that we feel may fit well within our portfolio and are certainly things, when you speak of electrification in particular, that we are not only will be, but already are pursuing along with our DUC partners. Overall, the 2050 North Sea Agreement and the Danish continental shelf, we find a tremendous piece of forward stability for all of the industry, for all of the players on the continental shelf. Gives us not only predictability and certainty as to how this will all come to an end, but it gives us the framework for developing our existing DUC projects and development opportunities. With that quick overview of the operations and latest sort of conditions for us, I'd like to hand over to Euan Shirlaw, who will handle the financial review. Thank you very much, David. I think it's worthwhile as we report our 2020 results today, looking back and noting the unprecedented backdrop over the year that has impacted everybody, but not least the oil and gas industry. It's probably not at this stage worthwhile emphasizing, but it is still helpful to note that I think COVID has created a number of challenges and obstacles that have had to be overcome, risks to operations and people, and also lower potential activity levels. It also led to and contributed to significant volatility in commodity prices in a broader uncertain macro environment. There were challenges in the physical oil markets, bringing all this together has created a context that has required swift and proactive management of the situation. It's also highlighted fundamentally the value of our approach to risk mitigation that we had already put in place prior to the start of the current situation. In the DUC, as David's outlined, Total has done a good job of managing the operations and mitigating risks. Costs were reduced, both as a result of lower potential activity levels, also a desire to frame spending in a way that was appropriate for the prevailing commodity price environment. For Noreco specifically, we've benefited significantly throughout the year from our hedging arrangements. Over a period where the Brent price has ranged from $17-$69 a barrel averaged $42 throughout the period, we have consistently received realizations that are significantly above where the market has been. Our realizations over the period have averaged $67. Our realizations in Q4 particularly were $64 or $63.6. In addition to that, under the Shell liquids guarantee arrangement, we received a contribution from Shell of $98 million throughout the course of 2020, of which roughly a third or $31 million was received in Q4, and that has reflected the level of production that was achieved during the period. From a financial performance perspective, this has enabled us to report strong results through difficult circumstances. Our revenue for the year is $566 million, of which $146 million was generated in Q4. We had an adjusted EBITDA contribution of $358 million, with $73 million in Q4, and operating cash flow of $346 million, with $96 million of that coming in the fourth quarter of the year. Looking forward, the macro environment, certainly from a commodity price perspective, is improving. While COVID remains a risk that we all have to be conscious of, within Noreco, I think we take comfort from the fact that during 2020, there have been successful mitigating actions taken. That provides us with a stable read-through for the future. Looking at Noreco specifically as we go forward, we're well-positioned going into 2021. We have significant liquidity with cash on the balance sheet of $259 million. Beyond that, we announced in February of this year an underwritten amend, extend, and increase of our RBL to $1.1 billion. This will enhance our funding profile, address the disconnect between Tyra startup and when RBL amortizations were scheduled to commence, and therefore provide a strong foundation to deliver Tyra. Which, as David has highlighted a couple of slides ago, is an extremely attractive project compared to the alternatives that are within the North Sea peer set. It will also enable us to generate significant free cash flow from 2023 onwards. Moving on to cover the change in RBL in some more detail. As I mentioned, we announced an underwritten new $1.1 billion facility, which is expected to close towards the end of Q1 or early Q2 of this year. That is an amend, extend, and increase of our existing $900 million facility that will have a maturity in 2028 and will amortize from the second half of 2024. It will also significantly increase our drawing capacity and support our liquidity profile. The expected drawing capacity on close will be $1 billion, which will represent roughly $249 million of undrawn RBL on closing. We have, as part of the RBL process, included a linkage to ESG goals as part of this facility. We will be able to communicate more on what exactly those are once the process of syndicating the loan has closed. I think what we can say now is that the focus is on working towards, as Noreco, a clear and quantifiable path towards significant emissions reduction. More broadly, what the RBL increase demonstrates is that in a relatively difficult environment, there are probably two key messages. We continue to benefit significantly from the ongoing support of our existing bank group, and it's also a testament to the long-term value proposition of Noreco's DUC assets. While first production from Tyra has moved into 2023, it's clear that that hasn't fundamentally altered the strength of Noreco's underlying case. The next slide, we have a summary of effectively the operational performance and how that flows into the financial results that we have reported during Q4. We had production of 25.5 thousand barrels of oil equivalent per day and an overlift of 2.8, which led to sales of 28.3 thousand barrels a day. Our realized liquids price in the quarter was $63.60 per barrel. That compares to an average dated Brent price during the period of roughly $46 per barrel. That has allowed us to generate revenue of $146 million over the last three months. Moving on to cover our hedging arrangements. As I've noted, we benefited significantly from the hedging arrangements that we had in place throughout 2020. We have a minimum hedging requirement from a price perspective under our RBL. Given the volatile conditions throughout 2020 and a recognition on both parts that we didn't want to hedge at the bottom or close to the bottom of the market, we received a waiver from the bank group in both June 2020 and December 2020 of part of this minimum hedging requirement. In June, we waived the first six months of 2023's hedging requirement, and in December 2020, we waived the entirety of 2023's hedging requirement. This waiver will remain in place until the end of June of this year. However, we have taken advantage of the uptick in oil prices during 2021 so far to put hedging in place for that 2023 period. We have placed 3.3 million barrels of Brent hedges at an average price of roughly $52 per bbl. As a result of that, from the 1st of January 2021, our hedge portfolio covers roughly 14 million barrels over the next three years at an average price that is significantly above the current market. Finally, on this page, the Shell volume guarantee, which we've benefited from throughout 2020, generated $31 million of contribution in Q4, and the protection period under this agreement expired at the end of 2020. Moving on to slide 14. This reflects a summary of the Q4 financial report, I'm not going to run through it in a great amount of detail. I would highlight again the fact that we have, throughout the period, both in terms of revenue and also our profitability and also cash flow, generated strong results. That's reflective of our overall performance in 2020 as a whole. We exit the period with a strong cash balance and a strong liquidity profile against the backdrop of, again, as I've probably mentioned a couple of times now, a challenging environment that we have faced during 2020. Moving on to the final slide of the finance section, we have an overview here of the capital structure. I think most people should be familiar with it now, but we have a reserve-based lending facility, which was drawn at $751 million at the end of 2020. We have agreed to, on an underwritten basis, increase that facility to $1.1 billion, and that will, as I've noted, add significant liquidity and borrowing capacity. We have two publicly traded bond instruments, NOR13, which is a mandatory convertible bond, has a principal of $171 million. That reflects the payment of a PIK interest coupon during the period. NOR14, which is a senior unsecured bond with a principal of $175 million and a maturity in 2026. Bringing that together with our cash balance of $259 million, we have net interest-bearing debt on an accounting basis of $862 million. Given the structure of the convertible bond as a mandatory conversion to equity, that is excluded from the covenants that we operate under. Our net interest-bearing debt, excluding that convert, NOR13, is $692 million. I think I just close by really re-emphasizing some of the messages that I've provided throughout this overview. We have generated robust financial performance throughout 2020, and we exit the year with significant liquidity and a strong forward profile based on both the position of the business at the end of the year and also the revised RBL structure that we have announced in early 2021. With that, I will hand back over to David for some closing reflections. Very good. Thank you, Euan. Again, I think we've been able to show and highlight a very strong quarter for Noreco, bringing out a close to the rather unprecedented and challenging 2020. Nonetheless, I think we've come through that year as about as good as we could have hoped. What's really important, I think, in the excitement is when we look forward in the long-term value that sits inside of Noreco. We continue to sit on a very large and material reserves and resource base. Our 2P reserves still in excess of 200 million barrels equivalent, and we have that 2C resource of another almost 200 million. That 2P is helping us to deliver very consistent production, which therefore drives the operational cash flow that Euan's been able to outline, and we continue to see the reservoirs and the overall performance from the DUC deliver very low decline rates. We do have opportunities within that DUC to further offset the decline through additional investment. We've outlined and is actually supported through that 2050 North Sea Agreement that we do have near-term growth opportunities. We expect to grow through Tyra by almost 70% to 50,000 bbl of oil equivalent a day. We have a lot of milestones that are going to be demonstrating the success of that project coming up through 2021, as I've highlighted as well. Very exciting year ahead. We do have this set of growth opportunities that sit within our own backyard, sit within the DUC. We've identified these as high value, and we see that they're actually low development cost projects. This includes projects like Halfdan North, Valdemar Bo South, and several others that we have sitting inside of our portfolio. We also sit in a place where we have advantageous tax balances working to support some of not only the work we have in Denmark, but potential inorganic value-added opportunities. Our cash flow has been, and we continue to mitigate the risk of the market, through our hedging program with almost 14 million barrels of price hedges already in place from 2021 to 2023. An average hedge price of $56 per barrel oil equivalent in 2021 and 2022, and just over $ 50 in 2023 when we see the Tyra start up. All this is underpinned by a very strong financial position. We have a diversified source of funding in place, and we have no near-term debt maturities or capital repayments coming due, which gives us great confidence in our position going forward. With that, I'll close this simply with the statement that it's a pleasure to be able to speak to you. We look forward to answering your questions. We continue to be very confident in what we can bring forward for Noreco and to our investors. With that, I'll hand over to Cathrine so we can receive and address questions. Thank you, David. The first question goes to you. How should we think about OpEx going forward? With slightly lower production, is this quarter a proxy for what we should expect? The production impact we saw in Q4 was impacted by primarily a third-party pipeline shutdown in some of our deliveries. If you will, we did have the denominator lower than we would have liked. We are doing a lot of activity to sort of continue to do catch-up from COVID, and that does mean getting the people offshore and getting the work in place again. I don't think we're going to see significant changes in our OpEx level as we go through 2021. We will be focusing on doing everything we can to optimize not only that spend, but in particular, the barrels that we're able to bring back from that. As a full proxy, I think that's probably, and up through at least 2021 while we recover, not far off, and we'll certainly want to be transparent on that as we go forward. With raw material prices sharply rising, how does this impact the Tyra redevelopment costs? We continue to forecast the project sort of at budget. A lot of the fabrication and supply chain and procurement has already been completed. I think we are not anticipating significant impact from that piece. The contracts we've had around the project have been in place for some time. What's really left is the work in the yard. It's the man-hours, and bringing the necessary kit and equipment in to get it in place so we can make our sail away dates. Less directly concerned with the actual raw material prices at this point in time due to the position of our existing contracts. Next question, do you have any cost guidance for 2021? I think if I can handle that one, David. I think what we have guided in terms of cost is around particularly the Tyra CapEx around the development project. We have guided that roughly 40%-50% of the remaining CapEx on the project will come during 2021. That's a fairly good proxy for where we will be spending our CapEx during the coming 12 months. The next one is for Euan as well. When you talk about drawing capacity of $1 billion under the RBL, does that mean your borrowing base is at least that much? Yes. I think is the simple answer, yes. The borrowing base is over $1 billion, yes. For David, your guidance implies a 7% decline rate. You also said that your decline rate is very low. Are these two statements consistent? Yes, they are. We have seen a decline through 2019 to 2020 of almost exactly 7.5%. If we can hit the top end of our range, then that decline sits at closer to 4%-5%. The bottom end, we're still around nine, a little more. This is a testimony, if you will, to the types of reservoirs we have. If you look at overall North Sea decline rates, if we can be sitting in single digits, in particular if we can be sort of in that 5%-8% or 9% decline rate, that's what we would expect, and that is indeed a low decline rate through these reservoirs. Total has previously indicated some interest in potentially electrifying parts of its Danish production, and you also mentioned that parts of the RBL could be linked to ESG milestones in a previous press release. Can you elaborate on these milestones and what your view is on potential electrification? I think that almost gets picked up by both of us. As Euan noted, we will speak more to the specific ESG milestones associated with the RBL a little bit in the future. Overall, we are very aligned with both with Total and Nordsøfonden on our direction for the DUC, and we do see tremendous opportunities for electrification. We sit in probably one of the greatest renewable economies in the world in the backyard of Denmark. Given that the source of much of their power is already through renewables, we would want to be able to tap onto that if at all possible. It's something we're already very much focused on and spending time on. I don't know, Euan, anything further on the RBL you'd like to add on that? Not particularly. I think as I mentioned, we'll be able to give further guidance on specifically the RBL metrics once the facility has closed. I think the only thing I would add is that clearly, as David's highlighted, the sort of overall backdrop around the direction of travel or the push towards a continuation of the kind of broad ESG goals that we have, I think there are still steps being taken and scoping work to be done around what those specific projects look like. I think it's quite difficult to comment or give any specific indication on how that will manifest itself through our business as we move forward. I think what I would say, though, certainly from our perspective, is that we are conscious of the fact that while we're very clearly consistent and want to operate consistently with the kind of sustainability or ESG outlook that we think is important to have, we also do recognize the importance of balancing that against the capital requirements for these projects as they come up. I think that's why, as I pointed to the scoping work in terms of determining what the options and what the forward plan looks like is very important. Contribution from volume guarantee is $ 31 million. When this expired end of 2020, you will lose a major contributor for the next one and a half years. How do you see this? Just to clarify on that point, the contribution in terms of the protection period expired at the end of 2020. There has been a significant benefit from that agreement throughout 2020. I think it is always worthwhile when we look at the volume guarantee from bearing in mind the fact that that was something that was put in place where our contribution from that agreement doesn't necessarily reflect underperformance of the assets from our side. The levels that were guaranteed were higher than where I think we would have set our forecasts from an asset performance perspective as we were looking forward. It is clearly something that we have benefited from. I think as we look forward, the work that we have done around forecasting the outlook for the business clearly takes account of the fact that that agreement will no longer exist. I think to frame it slightly differently, rather than being something that we have lost and will not benefit from going forward, I think we have to rather focus on the fact that we have benefited from something that typically you wouldn't have expected to as part of an M&A transaction over the effectively the 17 months that we've owned the assets up to the end of Q4. Thank you. David, yesterday Total announced that they have sent in plans for new wells on the Halfdan North and Valdemar. Can you please comment on this? Yeah. Both Halfdan North and Valdemar South are some of these high-value, low-cost development projects that we've talked about sitting inside our DUC backyard. We have done the scoping work to the point that we can and have submitted for these two field development plans to the Danish Energy Agency. Upon approval of that, there would be a choice and a final decision for investment made by the partnership. That step has to be taken before we move any further. In both of these cases, we're talking about putting in unmanned platforms, which basically tie into our existing infrastructure, that will produce not only new volumes, but produce volumes at significantly lower carbon footprint. We expect these to be somewhere in the order of 30% lower in terms of emissions versus the existing portfolio in the DUC. Both of these have very attractive-looking development opportunities. We need the DEA to approve the FDPs. We then, as a partnership, need to finalize the details and make a decision whether we will FID these and take them forward. David, do you have any OpEx cost guidance for 2021? I think the short answer is we're not going to provide a guidance on that. I think what we heard was the proxy that we've seen from 2020 is not too far off for what we'll be dealing with. I think the other thing to point out is if we look at the long-term trend, we've brought OpEx to a significantly lower number than it was historically inside of the DUC. There is a period where we're still dealing with the development without the benefit of Tyra. I think what the proxy has mentioned earlier is probably the best guidance that we can offer at this time. In what countries or regions could inorganic growth be relevant? Again, we need to look and make sure that this would be smart investment. We have the opportunity, and primarily, we would focus on where we see potential tax balances. That really limits us specifically to the North Sea. Obviously, Denmark and the U.K. is where we hold specific tax balances. That's probably the best focus I could give is, we're going to look first in our backyard. We're going to then look at where we have our tax balances. We're not looking at doing anything beyond sort of the North Sea. The final question. Production GNA for the quarter was DKK 18 million. That implies almost DKK 50 million on 100% basis for the field. Can you please give us a sense of what the major components of this are and why these costs are going up? DKK 50 million seems like a lot for GNA for a field for one quarter. I think if I can start on that one, David. I think one of the underlying points that's important to note, and we haven't actually touched on this particularly in the presentation so far, but a substantial portion of the costs that we experience in the DUC or that we pay on the DUC are denominated in DKK. As a result of the strengthening of the currency over the Q4 period, which was quite material, we have had a sort of underlying headwind around an increasing cost. I think that is one element to bear in mind. I think as an overall point, I think it is fair to recognize that as you highlight that cost is relatively high for the current environment and the current level. I think what we can say is we are taking as active steps as we can to look at ways in which the organization that is in place around the DUC could be improved or could be enhanced. It does also reflect the fact that there is an organization within the DUC that is effectively for a four-hub relatively large scale infrastructure asset base, and that has a cost associated with it. I think, clearly it is a number that is at the upper end of what you would expect. When Tyra is on stream, obviously that will be spread across a larger production base. I think what I would say as a sort of conclusion on that point is that it is fair to say that it's also something that we recognize as part of our OpEx level as a whole, and that is an area where there is certainly scope for further improvement, and that is something that we are very much focused on achieving as we go forward. Thank you. That concludes the Q&A session. Thank you for participating.