Hey everyone, and welcome. With me today, Birte Norheim, the CFO, will present the financial details and some of the key data from this quarter. The highlights are, and starting with what is the most important for us, of course, is our operations on Draugen. They have been run smoothly, and the quarter is 16,557 thousand barrels per day. Financially, we had a good quarter. Revenues was NOK 536 million. Birte will go into the details why that is a bit different to last quarter. EBITDA was better than last quarter, NOK 240 million. We had a net profit of NOK 23 million, and we are still growing our cash position. With another NOK 100 million, we are now almost NOK 1 billion in the accounts. We are positioned for further growth, and most importantly this year, the startup of the Yme is expected later this year. The investment decision on Hasselmus is expected within a few weeks. That will be the first tie-in resources to be produced on Draugen. We are presently drilling an exploration well at the Ilse prospect. I'll get back to that. We also plan, as a partner, to drill the Ginny prospect later this year. Of course, we continue to look for— And this quarter. You see we increased the production. However, we sold less petroleum than the previous quarter, and that has to do with the lifting program, and Birte will go into those figures in detail. That also means that we had less crude, in particular, to sell, which led actually to a bit smaller petroleum income, but with much less volume than in the fourth quarter. Let me start with Draugen, our most important asset, which we operate, and half of our income comes from Draugen. We have, since we took over the operatorship, worked very hard to have high regularity and good operating performance, and we have been quite successful in that. We now have 97% reliability on the platform. We earlier this quarter started to import gas from the Åsgard Transport System rather than spending diesel to fuel the turbines to get the power on the field. That, of course, led to a reduction of the CO2 emissions from the field. The planned investment now where we reach 70% recovery rate, and we are now working on the old formalities to extend the lifetime of the Draugen field to 2040. Succeeding in that, we will actually double the remaining reserves from the field. The announced high CO2 taxes on the Norwegian shelf do, of course, incentivize us to see if we can have other power sources than gas. We are together with Equinor, looking at the possibility of bringing hydropower from shore to both Draugen and Njord. We expect to make a final decision whether that should be an investment or not in 2022. Gjøa is the other asset for income for the time being. New production wells was put on stream earlier this year. Presently, we have a 30-day shutdown, actually two more weeks on that, to tie in the Duva and the Nova field to Gjøa. We will be, as I will show later, also be compensated for the loss of production that we incur because of this. In this area of Gjøa, we are already engaged in several exploration licenses to the west of Gjøa, and we operate ourselves the Aurora discovery to get the better samples of the gas from Aurora in order to have a proper arrangement with Gjøa to produce that gas. An appraisal well on Aurora is a necessity. Of course, Yme, which is the project that OKEA has been involved in the longest. It's finally now approaching production. We see production from the field later this year. Behind me here, you see pictures taken during the tow out of Mærsk Inspirer to the field. To the left, you see picture of all the tubes and things have been hooked up between the well platform and the Mærsk Inspirer itself, preparing it for production. The remaining part of the hook-up operation and everything that has to be done before production is on schedule for a production start later this year, hopefully not in a too long time. The net effect for OKEA when this is on plateau will be 7,500 barrels a day, which, of course, is quite significant for a company presently producing 16,500. We are also, as we speak, in a partner in drilling the Ilder prospect, just some joining forces in using the same equipment, using the same production unit between Vette and Grevling that actually make this, in effect, 100-million-barrel development, which looks promising. Of course, a discovery on Ilder will change the game a little bit here because sufficient amount to make Grevling a standalone development will also impact the strategy between those fields. We will see when we have the result of Ilder. Then I leave the word to Birte, who will explain and go into details with the financial data. Thank you, and Birte, please. Production reliability continues at high levels both at Gjøa and Draugen also during the first quarter. The production of 16,557 barrels per day represents an increase of 2%, or nearly 300 barrels per day, compared to last quarter, mainly due to the P1 wells which came on stream in February. Sold volumes of 15,198 barrels per day is 19% lower than previous quarter, mainly due to an additionally large lifting allocated to OKEA in the previous quarter, and only one lifting from Gjøa in the first quarter compared to two in the previous quarter. In the previous quarter, OKEA was also allocated about 100,000 barrels from Ivar Aasen, which occurs quite regularly given that OKEA only holds about 0.5% working interest in the Ivar Aasen fields. As for realized prices, we have observed quite significant improvement. Rise of liquids was still 27% up compared to last quarter at $49.50 a barrel, compared to $39 realized in the previous quarter. The realized price for natural gas as the prices has continued to increase, we have realized a price 28% above what we realized in the previous quarter, which is more than a doubling of the prices in the first quarter last year. This brings the petroleum revenue to NOK 536 million, a decrease of 8% compared to last quarter and an increase of 6% compared to previous year. We have added a new slide to illustrate the impact of timing of the Draugen liftings. In volatile markets, the timing can have quite a significant impact on the realized prices for the quarter. The recent OKEA-allocated liftings from Draugen have occurred early in fourth quarter and early in the first quarter. When the market prices have continued to increase, when we look at the quarter in isolation, this does not fully represent the average pricing for the month. we have, of course, benefited from the recent price developments, but not to the full effect as the prices have continued to increase during the quarter. The graph outlines the differences in the average Brent price for the first quarter of NOK 61 compared to the average realized liquids price to OKEA of just about NOK 50 a barrel. as can be seen, the key difference relates to the timing effect, which represents NOK 7.60 a barrel of the difference, and the NGL impact, which is about NOK 3.30 a barrel of the difference. The quality and price adjustments can vary over time, but is quite insignificant in the quarter. The OKEA-allocated liftings in the last five quarters, including the lifting that took place now in the second quarter in April, which happened at pricing market prices of about $65 a barrel. The next lifting from Gjøa is planned for May, and the next lifting from Draugen is planned for third quarter. As for the income statement, we deliver an increase in EBITDA of NOK 240 million compared to NOK 229 in the previous quarter. However, the high net profit of NOK 182 million in the previous quarter has been reduced to NOK 23 million in the current quarter. This is mainly due to the very positive impacts of the reversal of impairment on Yme of NOK 117 million, as well as unrealized foreign exchange gains in the fourth quarter not being repeated in the current quarter. In addition, in the current quarter, we are expensing the Jerv well of NOK 92 million, following concluding Jerv a non-commercial discovery in March. The operating income of NOK 524 million mainly consists of the NOK 536 million in petroleum revenue and also tariff revenue from Gjøa and are NOK 102 per barrel compared to NOK 110 in the previous quarter. The lower cost per barrel was mainly due to continued stable production and reliability at both Gjøa and Draugen, as well as the additional volumes from the P1 segment. Exploration and operating expense consists of NOK 109 million in exploration expense, mainly relating to the mentioned expensing of the Jerv well of NOK 92 million, as well as field evaluation activities on Aurora, Vette and Grevling. SG&A cost of NOK 16 million represents OKEA's share of cost after allocation to license activities. The net financial items of NOK 5 million in cost mainly relates to expensed interest, partly offset by foreign exchange gain. As the dollar/NOK relationship has remained quite stable during the quarter, the impact of foreign exchange on our dollar -denominated bond loans is quite limited in this quarter of $10 million. The tax expense for the quarter amounted to NOK 40 million, an effective tax rate of 64%, which brings the net profit for the quarter to NOK 23 million. As for the balance sheet, the cash and cash equivalents amounted to NOK 978 million, and as always, we will get into the further details of this. We have a current tax refund of NOK 211 million, of which NOK 86 million relates to a refund of exploration expense from 2020, and NOK 113 million relates to the remaining tax installments for 2020. The interest-bearing debt amounted to NOK 2.4 million of NOK 4.2 billion is partly offset by the NOK 3 billion in non-current receivables due to Shell carrying the cost of removal from Gjøa and Draugen. Our cash position has increased by NOK 107 million during the quarter, ending at the closing balance of NOK 978 million. The increase is mainly due to cash from operating activities of NOK 224 million, which reflects a fairly good operating margin as the market prices have recovered and partly offset by the payment of the Jerv exploration expense. Taxes received of NOK 97 million is one of the three remaining tax installments for 2020. We expect to receive two more in the second quarter. We have a payment estimated to NOK 81 million, which is due in Q4. Cash to investment activities of NOK 182 million mainly relates to Yme and the P1 wells, which was completed in February. The interest paid of NOK 24 million relates to the quarterly payment of the OKEA02 interest. On that note, I'll give the word back to Erik. Thank you. Thank you, Birte. I will wrap up this presentation by going through some of the outlook for the future. As we have already guided, is that we expect a slightly higher production, about the same as we did last year. In 2022, we will have a significantly higher production for two reasons. One is, of course, that Yme will be in production. You see here that we have added another 1.2 to 1.5 compensation to us because of the tie-in of the fields Nova and Duva into the Gjøa field. That is a compensation for the lost production in 2020 and 2021, that will be repaid in a way in kind during the remaining part of the field. This is just a time effect of production that we otherwise would have had in 2020 and 2021, which we now get in 2022. Also looking at the CapEx, we have had two field developments ongoing for a while, and in 2020, we both had heavy investments on Yme and the development on the Gjøa P1 segment. That will be finished or are finished for the Gjøa's case. The investment in 2021 will be significantly lower than it was last year. These are figures based on a project that is ongoing or approved. What we promise you to deliver are basically listed here. I am sure and confident that Repsol will get Yme on stream later this year. Hopefully, earlier than later. We will submit to the partnership and we expect an approval of investment for the Hasselmus development, which we will present when this is finally approved. it's a very lucrative development, has a break-even price well below $30 a barrel. That looks like a very good project to be handled by OKEA and be in production already in 2023. Ilder, I mentioned, is currently being drilled, so we are excited to see if we have a positive result on that or not within a few days. Ginny will be drilled later. Whether Aurora will be drilled this year or later depends very much on whether we get a partner into that project. We expect to make the concept selection for Vette Grevling, both with or without success on Ilder later this year. We are, of course, maturing our portfolio around the assets we are operating and where we are partners, and there are several decisions for appraisal and exploration wells lined up during this year and next year. That will be really exciting. We received eight new discoveries in the portfolio that we had in the last APA round, and a lot of additional prospects that will be interesting to pursue. We are, of course, looking for other opportunities on the Norwegian shelf. Being the only smaller oil company that is a prudent operator of actually physically fields on the Norwegian shelf, we think that the business opportunities for mergers and acquisitions is quite good for OKEA. There's not much competition in that segment where we have positioned ourselves besides the bigger companies, of course. That is also something that you may expect some movements during the next couple of years. Finally, this is also my final quarterly presentations to you since we started this in 2015. I've been running OKEA, and since we listed the company, I, of course, had numerous of presentations like this. The 1st of June, I will step down and Svein Likne s will take over my position as CEO of the company. The company look really forward to see him on board, and all the employees are really excited what he can contribute to the further growth of the company. I will still be with the company for a couple of years as advisor, but it's now run by Svein from the 1st of June. I will thank you all for not only listening to this presentation, but having listened to me on several occasions before. Thank you very much, and then we will continue with questions where both Birte, myself, and Trond Omdal will be available. Thank you very much. Ladies and gentlemen, if you wish to ask a question, please press five star on your telephone keypad. To withdraw your question, please press five star again. We'll have a brief pause while questions are being registered. Thank you. The first question comes from the line of Teodor Sveen-Nilsen from SpareBank. Please go ahead. Your line will now be unmuted. Good morning. Thanks for taking my questions. also thanks to you, Erik, for a good effort and good luck with your new adventures. Three questions from me. First on Yme, it looks like you expect first oil pretty soon. I just wonder, what are the key milestones remaining until first oil, and is it fair to assume that actually we'll see first oil this summer and not late in second half as you have guided for a couple of quarters now? That's my first question. Second question is on this Yme compensation. How much will actually that be in kroner or dollars? how is that compensation constructed? Is it a dollar per barrel or any other kind of mechanism? My final question is related to cash refund. Birte, did you say NOK 64 million for Q2 expected? Are you in position to provide any guidance for Q3 and forecast refund? Thank you. Yeah. Thank you, Teodor. First on the Yme timing. Most of the physical hookup operations are finished, but there's some work remaining. All that is done by Aker Solutions. In addition, Aker Solutions also have the contract on their commissioning. The commissioning, I think Repsol has been out in the market saying that the startup will be during Q3. Commissioning is always something that partly weather dependent, even though we are approaching the summer. Just to take height for if commissioning discovers anything, that has to be, of course, amended, et cetera. The purpose of the commissioning is that when you push a button, the expected response of that must be correct. If it's not, you have to do a lot of electrical and computer data programs that needs to be checked before we can start production. If it goes smoothly, we expect production in the mid third quarter, just after summer. If there are hiccups, they need the necessary time. We are very confident that the production will start during this year. With respect to the compensation regarding the delays because of tie-in, that's a normal thing in Norway that you get paid in kind. All the oil that were kind of pushed out in time because we have to stop because of this tie-in of the other field, which accumulates to 650,000 barrels, that will be kind of delivered, subtracted from the owners of the tie-in fields when production starts. That will mainly happen in 2022. It will be leveled out throughout the rest of the lifetime on the field. That the end result will basically be as was expected as if this tie-in never happened. In addition, of course, on the mother platform, we get a tariff for the work of producing a third-party gas in this case. Perhaps, Birte, do you answer the last questions? Yes, I can, Teodor. For the 2020 tax refund, we expect two installments in Q2, which is equal to the one we received in the first quarter. Two times NOK 97 million expected to be received. We have estimated a residual tax to be paid in fourth quarter of NOK 81 million. That's for the 2020 tax return. On top of that, we have an exploration refund of NOK 86 million, which we also expect to receive in the fourth quarter. Okay, thank you. You don't expect any tax refund in third quarter? No, not in third quarter. Okay, thank you. That's clear. That's all from me. Thank you. The next question comes from the line of Anders Holte from Kepler Cheuvreux. Please go ahead. Your line will now be unmuted. Yeah, good morning, guys. First of all, I'd like to take the opportunity to thank Erik for a true and trusted service over a number of years. I guess as you leave OKEA, it would be good to hear your thoughts on where you see the company heading in terms of bit of a longer view. I'd also like to just pick up on your comments when it comes to the M&A front. Do you see any larger movements? Is there assets between the sets, is it widening, or do you see any kind of shakeups in terms of any divestment programs coming from the larger holders of assets on the Norwegian Continental Shelf? Thank you. Yes, we see the movements already, of course. As you all know that some companies are in the process of pulling out from the Norwegian shelf because of changing their strategies. There are companies who have announced that they are changing their strategy away from fossil fuels, and they are still in Norway, so they will eventually go out. We see an opportunity along three columns. Those companies who's actually divesting. There are the bigger companies, I think they need to continue to prioritize because of their internal resources. Hence, there will be some assets that they will either relinquish or sell out. Thirdly is that there is still a group of pure exploration companies that will have financially and perhaps organizationally difficulties to also engage in field development and production, because their funding is based on the annual refund of the exploration expenses, which will not happen when they invest in developments. Successful exploration from any of these companies will, of course, also give us access to fields and discoveries that we can develop with our capacity. Also, of course, with the expected good cash flow we see in OKEA, I expect that also OKEA will grow organically with doing more, both appraisal drillings, exploration drillings, and eventually also field developments. As we also explained now in the presentation, we go ahead with the Hasselmus development, which we will present the details of as soon as the licenses approve the development plan. That's also not only an investment but also a project where OKEA can kind of demonstrate our capabilities in various new ways. I think OKEA is very well-positioned for significant growth going forward. Thank you. Yep. Thank you. As a reminder, please press five star on your telephone keypad to ask a question. The next question comes from the line of Carl Pedersen from ABG. Please go ahead. Your line will now be unmuted. Hi, guys. This is Carl Fredrik with ABG, so now OKEA. Two questions from me. The first question relates to the compensation. Is it fair to view this as a kind of cash flow boost in the near term, and then you will have the interest component that you'll have to repay over time? The second question is, can you elaborate on the work streams that is required in order to extend the life of the Draugen? What are the main hurdles as you see it? Thank you. You just want to answer. Yes. I would look at it as a cash flow boost. It's basically we're getting volumes now that we have to repay later. It's like a contribution in kind, and in addition to the interest element. We will get additional volumes for sale on top of what we produce in 2022 mainly, and we will repay those volumes over the remaining life of year. I think it's a correct way of looking at it. I assume you meant Yme, your second question? No, just to follow up on that question before we go to Draugen. That means that the net volumes will be approximately the same. It's only the interest component that will be the difference between the EUR boost in 2021, 2022, and what you have to repay over the following set of years. Yes, that is correctly understood. Perfect. I wouldn't call it interest, because you get the same volumes in kind. You don't pay anything, but you get cash flow effect of it. Yeah, you get those interest paid in volumes- Yeah On top of the actual amount. Yeah, okay. Yeah. Regarding Draugen extension, I think the formal extension is very straightforward. It is just lots of documentation about the field's infrastructure actually are capable of staying there and the way it's maintained for the next 20 years. With respect to the production, I think we are home free for a production with the present plan into the 2034. We are working on one other project that we will embark on probably next year is some sidetrack from existing wells. We do plan for a more extensive water injection program pretty fast, and then also later new infill wells on Draugen. To enhance the production on Draugen is basically a question of investments in additional wells if we shall reach 70% recovery, as I mentioned in the presentation. There is no kind of specific obstacle that has to be passed. Okay. Essentially it's an investment decision that will trigger more drilling and consequently increased reserve base. Yes. Okay. Thank you. Yeah. Thank you so much for your efforts. Good luck with your new endeavors. Thank you. I'm not planning to start a new oil company, that's for sure. As there are no further questions, I'll hand the word back to the speakers. Yeah. Okay. There is a couple of questions from the web. First one is, after Ginny, what's next when it comes to drilling campaign? How many wells does OKEA plan to drill or explore in 2022? There are two groups of wells. One is the exploration wells, where the Calypso prospect west of Draugen with Neptune operator going to be drilled next year. We'll probably also drill Mistral, which is a gas. Actually, there's more like an appraisal well because of the gas discovery south of Tyrihans. We have Aurora, which we also would like to drill an appraisal exploration well on as soon as we get the partner. It may happen this year, but definitely next year. Of course, the Hasselmus production well. We are planning one sidetrack from an existing well on Draugen also next year. Depending on how that well produces addition, we will do that sidetrack when existing production in that particular well is dropping below a specific level. That may be delayed if it produces too well. We see four to five well operations in 2022. Which one of them is a pure exploration well, actually. Okay, thank you. One other question from the web. Your CapEx, you maintain the CapEx guiding of NOK 600 million-NOK 700 million. Does that not include post-FID investment in Hasselmus, or will that change and you update your CapEx estimates after the FID? That includes the investment this year that is on Hasselmus. We assume that will be approved, so that's why we have it in our cash forecast. Okay. That's all. Thank you again to the analysts and for the questions and those who have followed on the web. If there are any requests, you can contact Erik Haugane, Birte Norheim or myself, Trond Omdal, and the contact details are on our webpage. Also if any investors want one-on-one meetings. Next time, it will be our new CEO, Svein Liknes who will head the Q2 presentation. Look forward to seeing and hearing you then, hopefully live post-COVID. Yeah. Thank you very much, everyone.