Good morning, everyone, welcome to this presentation of PetroNor E&P's half-year results. My name is Eyas Alhomouz. I'm the Chairman of the Board, with me today is Interim CEO Jens Pace. During 2022, we successfully increased our production capacity as a result of the ongoing infill drilling program on the PNGF Sud in Congo. Today we are pleased to report production levels not seen in that field for more than a decade. While there were no liftings of our oil inventory during the first half of the year, more than 800,000 bbl were lifted in the second half of the year, generating solid revenue growth supported by higher oil prices. We have also reached several other important milestones during the past half-year period, such as the completion of the Aje agreement and the award of The Gambia A4 license. Earlier this year, 2023, we have also welcomed two new directors to our board. I will now leave the word to Jens, who will share further details about our operational and financial performance. Jens? Thank you, Eyas. A very good morning to all of you who are watching this online. It's a privilege to be able to present some color around the numbers in the interim report that we sent out earlier this morning. I have a few slides to help me do that. I will be taking questions after that. Please, please do send them in, and we will try to get to those at the end of this presentation. As Eyas has already set up here, the second half of the year in 2022 was all about the success of the infill drilling program in Congo, which has given us rising production throughout the year. The second half-year production on a working interest basis for PetroNor was 4,400 bbl of oil per day, and this is an increase over the first half average of about 3,600 bbl of oil per day. Our exit rates in the end of December was over 5,000 bbl of oil per day. We've started the year well, and current rates through 2023 are actually over 5,200 bbl of oil per day. A great record of growth here throughout the year, and this is coming from the additional well capacity that we've added in the Congo, with four new wells on the Litanzi field as part of the PNGF Sud complex and two wells on the Tchibeli North East field. One of those wells on Tchibeli North East was deepened to an underlying exploration target, which was successful. We are now producing from that underlying reservoir, and evaluating what the regional significance of that discovery is in the license area. You know, a good story on production, but in the end, it's also about crystallizing that in terms of value. We had a difficult beginning of the year with no sales of oil. It came good in the fourth quarter with two liftings of entitlement oil, which totaled 800,000 bbl at an average price of just over NOK 90 a barrel. That yielded some NOK 73 million. We've started this year well with a lifting already achieved in February of 317, 318,000 bbl, with a realized price of about NOK 76 a barrel, which has given us another NOK 24 million in the first quarter. We have another lifting planned in April of this year. We've got more visibility on cash flow as a result. Just having a look at the numbers here. The cash that we have it on our balance sheet at the end of the year is just shy of NOK 25 million. We have net debt of NOK 13.8 million, that is some movement on facilities that we've had through the year. We've refinanced a working capital facility of NOK 11 million, paid off the residual of the previous loan and also cleared out some shareholder debt, legacy shareholder debt that we had. Assets have increased to NOK 180 million, and that's largely because we've brought the Panoro interests in Aje onto our balance sheet. That has increased the gross assets. Looking at the second half, specifically, revenue of NOK 108.5 million, reflecting both the increased production and also the higher oil prices we've enjoyed this last year. That's given us an EBITDA of NOK 75 million. That's a significant increase on 2021. A cash flow from operations, and this is cash flow after taking into account the cost of running the company. Our net cash flow is just shy of NOK 40 million. The chart you see there with oil sales from the barrels lifted kind of tells the story. In 2021, we had pretty regular liftings in each quarter. In 2022, it was all about the fourth quarter. We've had a lifting already this year, we're off to a better start. This is a breakdown of the use of cash during the half year. We were running quite low at the mid-year point with about NOK 7.7 million in the accounts. Net cash from operations during the fourth quarter has, as I mentioned before, is just shy of NOK 40 million. NOK 22 million of that is reinvested back into the asset. This is largely our contribution to the infill drilling program in Congo. We had some investment in our exploration assets. There was a signature bonus and some license fees associated with Gambia and Guinea-Bissau. The new facility, working capital facility I've already described, and the loan repayments of our existing shareholder debt and the residual of the previous facility is in the NOK 8.1 million. NOK 1.6 million is leakage of dividends to our minority shareholders in the Congo subsidiary, as we've moved money up through the company structure to the Topco. Which leaves us with the cash at the end of the year of just shy of NOK 25 million. I'm gonna go through the portfolio at a high level just to bring out some highlights here. This is a snapshot of where our assets are. Production base is in Congo-Brazzaville in the PNGF Sud license. Our gross field production there is about 32,000 bbl of oil per day, operated by Perenco. That production level, as Eyas Alhomouz has already said, is at a 10-year high from the field, which shows, you know, what a good job Perenco are doing in managing the tail end of this field, and bringing up production levels from when it was acquired in 2017. In Nigeria, we have a redevelopment project in the Aje field and that is something which we've just acquired in the last year through the acquisition of Panoro's interests. We still have some commercial transactions to do to complete what our plan is there to, in terms of a joint venture with the operator YFP. We're looking at a development plan which is largely gas and would be flowing at about 25 bbl of oil, 25,000 bbl of oil equivalent, if we can get that realized. Gas is, it has a strong ESG profile in this part of Africa. It's recognized as a transition fuel for Nigeria. We're getting good interest from the financial sector in terms of project finance for this project. Last but not least is our exploration portfolio around on the west's margin of the Africa, in Senegal and Gambia and Guinea-Bissau. High- impact exploration in deep water in a proven basin and some significant discoveries made along Trend. We're continuing to keep our interest on that. The headline numbers here, I'll just draw two of them to your attention here is 19.1 million bbl of 2P reserves, and that reflects the production during 2022. At 2C resources is of 35 million bbl. That's about 22 of that is in the Aje field, and the remainder is yet to be realized as 2P reserves in Congo. Focusing on Congo here. This complex is a large complex of fields which holds about 2 billion bbl of oil originally in place and less than 500 million bbl recovered to date. At a very low recovery factor by industry standards. The success of the infill drilling program and also the discovery of this underlying reservoir under the Tchibeli North East kind of gives support to the old industry adage here that big fields tend to get bigger as you work them. This seems to be no exception. It's high- margin production. Our OpEx here in shallow water with this infrastructure is around NOK 11 a barrel. You know, there's been a consistent track record of adding 2P reserves in excess of annual production via technical work and the infill drilling program. Also, PetroNor has acquired interest from minority partners to deepen our interest in the license over the years. That progression is shown in the bottom chart there. We are just in the process of updating our CPR. I expect that there will be another increment based on that which is going to incorporate the early results from the infill drilling program. The gross production profile is shown in the bottom right, you can see, you know, the base production from all the fields in dark blue. In the slightly lighter blue is the input from the infill drilling in Litanzi. The very light blue is Tchibeli North East. In the greens, we have this year's target. We're taking a bit of a break from the drilling right now. We will anticipate coming back to it in starting in April, May. That will be focused on the Tchibeli field, where we have six new wells planned in Tchibeli, and then moving on to the Tchendo field, with additional drilling planned there, which we'll probably get to before the end of the year. Looking in Nigeria at the Aje redevelopment, we've got a seat at the partnership license group now. We're finalizing our arrangements with the license operator, YFP, to hold a 52% interest in a jointly owned company called Aje Production. In parallel, we're advancing a plan for redevelopment with partners and potential offtakers of gas, which, you know, comprises an upgraded FPSO. The previous FPSO did not have any gas processing capacity, and as a result, was flaring a lot of gas, which we see as the wrong thing to do here. We are looking for an FPSO with gas processing capability, and we have a number of options that have been inspected in the last year or so. The plan would then be to drill three new wells and recomplete and maybe sidetrack a couple of others that are already drilled in the field. This is quite a well-appraised resource, as all the wells have gone through the gas to get to the underlying liquids which were being targeted previously. It's a well-understood and a good reservoir, so we have a high confidence in the level of gas. It's a relatively modest size field with about 500 Bcf of gas, 20 million bbl of condensate, and 7 million bbl of oil. It's valuable because it is so close to shore and so close to markets. We would be looking to have a 30-km gas pipeline from the FPSO to shore, where we would have an LPG facility to enable the production to meet the specifications of the West African Gas Pipeline system. We're talking to buyers on that are part of that system and in the local area. As I've mentioned before, because it's gas, largely a gas- focused project, we're having positive discussions with sources of finance for project finance in that need to be able to demonstrate that they are investing in an energy transition in Africa as opposed to an oil development. In terms of the development, the 500 Bcf of gas versus the 27 million bbl of liquids, they're about equal value in our economic assessment. The gas is a significant value, but the liquids are important as well for the overall economics. Finally to exploration. We had an option on a license in The Gambia, which we chose to exercise last year in October. We negotiated a modified work program with the government such that we didn't take a well commitment immediately. We have some 18 months to reevaluate a new version of the 3D seismic that we have leased. We would have an option to enter into a second phase in 18 months' time to take a well commitment. We're doing this at the same time that we are marketing the acreage to potential partners. We have a high working interest here with 90%, alongside a state-owned oil company partner, GNPC. We're looking to introduce a new partner into this license. Also having encouragement in a similar way in Guinea-Bissau. In support of that, we are in the stages of planning a well this year, based on encouraging third-party discussions. Although we have met our financial commitments in these licenses in Guinea-Bissau, we and the government would like to see the play concept tested. We are putting in place the plans for a well later this year, discussing this with the government and third parties. We have observed a revival in the interest of the industry in exploration acreage around this margin. That's supporting our discussions. It's also worth mentioning that we have completed our side of a long-running dispute and arbitration with Senegal over our legacy licenses in that part of the margin. We had the final hearing of this conducted early last year, and we are still waiting on the ICSID tribunal to come forth with their ruling. It's been taking a while, but we could expect that really any day in the this year. Just to wrap up here, continued strong delivery from the Congo assets, which has really got 2023 off to a good start. The infill drilling program has given evidence to the long-term reserve growth that is possible in this license. And then we're crystallizing that in terms of cash from liftings, and with the first lifting already achieved and visibility on the next one in Q2. We're at the table on Aje and getting alignment on the redevelopment plans that we have for the area. You know, I think the cash flow from our Congo asset gives us an opportunity to execute our growth strategy. It's fully funded at these production levels and these oil prices, so we can recycle that money into the growth of the asset. Also it's largely unleveraged apart from that working capital facility we have. We have the opportunity to leverage that further in terms of executing M&A opportunities. We're still active in this space. I know we've said that quite regularly in these sorts of updates, but it doesn't belie the effort that my team has been doing to evaluate opportunities and we have, you know, we've found that the world is quite a competitive place. Maybe that's because we're quite choosy about the deals we want to get into. Finally, I think we recognize that if we build up a cash position in the company that we need to consider other options for shareholder value. This is a fairly recent conversation that is starting at the board level. We, we hope to address that in the coming year. That's really all I had in terms of an overall introduction. I'm happy to take any questions that you have from participants. Thank you very much. Thank you, Jens. We will now move on to the Q&A section, and we have already received quite a few questions. The first one is regarding PNGF-Bis. Could you please give us an update on that field? Yes. Well, we have a right to enter this license, PNGF-Bis, in the Congo with Perenco as an operator. It's not been a high priority for the partnership because we've seen so many other investment opportunities in the PNGF Sud license, as we've demonstrated with this infill drilling program. What's changed is the underlying success in Tchibeli North East in a formation called the Vandji Sands, which is one of the reservoir targets in the Bis license. The success there has given us perhaps has raised Bis up the agenda. Our discussions with the operator recently suggest that we will re-engage with the government on the production sharing agreement on Bis. I can't put a timeline on that, but it is something that is definitely moved up the agenda as a result of the discovery underlying Tchibeli North East. Thank you. Guinea-Bissau, can you please elaborate on your plans to drill there? Well, our license comes to the next milestone in October this year. We would like to see a well drilled or at least started before then. We're in discussion with the government about that. We are looking at potential rig options, and we have an existing contract with a well service provider that is looking at all of the planning steps necessary to make that well a possibility. Our strategy here as we've said all along is to use our working interest in these licenses to fund our drilling operations here. we are in discussions with third party, and that well will only be done if those are successful and that we're able to do a transaction in the, in the coming months. In readiness for that, we are looking at rig options. Thank you. Total drilling cost for PNGF Sud, how are those covered? As a partnership group, we're investing about NOK 200 million a year into the assets for the infill drilling program and the some of the infrastructure changes around bringing that on production. That was this last year, and it will be the same this year in terms of the plan. That's all funded out of the production income from the assets. It's not something that we have to go elsewhere to fund. It is recycled from our production base. Thank you. How many barrels of oil from Aje field is PetroNor expecting? Well, I think on a gross basis we see about 7 million bbl in our current estimate of the resource volumes there, and that's part of our 2C numbers that I mentioned earlier on. Also significant is the barrels of condensate, and there's about 20 million bbl of condensate because the gas is quite rich, and that's very valuable. You know, just shy of 30 million bbl of liquids which is an important part of the economics of the redevelopment. Thank you. How much finance, or costs perhaps, is PetroNor expecting until Aje is coming into production? Well, our redevelopment project involves our estimate is around NOK 400 million of CapEx is required. We would expect to fund the majority of that with project finance. You know, this is in contrast to previous plans for the redevelopment which cost over NOK 1 billion. We've taken a very efficient in terms of CapEx view of the redevelopment with recycling a secondhand FPSO and looking at redeploying some of the existing well stock that goes through the gas leg into the, with some sidetracks to turn them into production wells. I think it's a very cost-efficient development. Clearly a big step for the partnership group and one that we have a lot of work in front of us to get alignment on. Thank you. Fantastic result. Congratulations. What strategy does the company have to attract more investors, or more major investors to invest? Stock price is suffering from minimal interest in the market. Well, I think, you know, our message here is to highlight the underlying health of the company, which as you can see from this performance is certainly easy to demonstrate. In terms of shareholder value, we are looking at other options to support our share price. This is something that the board is considering. There are some mechanical elements to this that need to be taken into account. PetroNor E&P ASA is a young company. It's never declared a profit because it only really has come into being in the last year. We need to be able to declare profits on an audited accounts before we can consider returning money to shareholders. It is something that the board has asked our finance team to look into, and we report on it regularly in our board meetings now. It's clearly part of the discussion at the new board level. Thank you. We have also on that note a couple of questions. Why did the stock split get delayed? Not the stock split but the merger, I guess. Yeah. I understand. You know, we have an obligation to address the share price being below NOK 1. If it's below NOK 1 over a certain period of time, then we need to do a consolidation. We've been discussing with the market what kind of consolidation that we should ideally do. That led to a deferment of the plan to do it at the last EGM. We have a normal AGM coming up later this year, and we can address it then, and we've discussed that plan with the Oslo Børs, and they're aligned with it. We'll be making an announcement about that nearer the time. Thank you. Why was the board expanded with the two new directors? I think that we've had a lot of discussion as to what the appropriate size of board is and the board was somewhat depleted by the fact I stepped down off the board as a result of taking a management role as an interim CEO. The idea is to make sure we have a broad set of views and experiences at a director level, and I think we've achieved that with these new directors. Thank you. A couple of questions on your previous long-term targets. Have you scrapped the former three-year target by now? I've stood in front of a target, a very ambitious target of 30,000 bbl of oil per day in three years' time, and I was painfully aware of the fact that three years was kind of coming up. You know, that's not to say we've scrapped a growth target. We are definitely interested in looking at accretive M&A deals. We are actively working on some. They would significantly increase our production. We haven't as a board set a new target for the company yet, but we have to be realistic that the 30,000 bbl a day envisage that we would make more headways into the M&A space than we have been able to. Thank you. Other options for shareholder value, is it supposed to be a dividend or a buyback of shares at first instance? I think that will be subject to a board decision, as the capacity to exercise either sort of plan is realized in the company. I can't be drawn on that right now. I can tell you that it is part of the discussion. Thank you. We are the final questions for now. What is the expected time schedule on the drilling of the Atum-1X? Is it still planned for 2023, and is it pending a farm out or will PetroNor drill this alone if no farm out is agreed? Yeah, we will not drill this 100%. This well will only happen if we have a commercial transaction that that funds it. We are nonetheless planning for a well that could be drilled in 2023, or indeed in early part of 2024. That's something that we're discussing with the government because that would involve an extension to the license. All of that is on the table and actively being worked at the moment. We would not drill at 100%. Thank you. There seems to be no further questions. That will conclude today's webcast. Thank you all for joining.