Hello and good morning. My name is Jens Pace, and as the CEO of PetroNor, it's my pleasure to be back here in Oslo to present the company's fourth quarter results. It doesn't seem that long ago I was standing in front of this camera, so it's been a busy quarter, and I look forward to telling you a few of the highlights of that. We sent out a report earlier this morning, as well as the slides that I'm going to use in a few minutes here. My main point of being here is to answer your questions, so please send them in, and we'll address that after this brief presentation. I'm going to flick through the disclaimer slide, and this is the kind of general outline of the presentation, which is somewhat standardized. I think you'll be familiar with this if you've been following the company. A brief operational update, some comments on the financial performance, the portfolio overview, what I can tell you about investigations, and then a summary before we get to your questions. In terms of the operational update, when I last spoke to you, we were forecasting a lifting over Christmas. We were able to lift and sell 881,000 barrels of oil just over Christmas Day and Boxing Day, and we realized a price for that of $73 a barrel. This actually brings our total sales for 2024 up to 1.8 million barrels, which generated income of $140 million. That is a record year for us. It was a record lifting and a record year in total. Underpinning that was the production for the quarter. It was just shy of 4,800 barrels of oil per day, and that is pretty flat with the third quarter. There are two trends there. One is an increasing production efficiency as we've been able to make more of the wells that are available to us and have had more stable operating conditions with the infrastructure. There is also some reservoir decline offsetting that, which is normal, and we are looking to address that in the course of this year. We've got plans for an additional infill drilling program that will start middle of the year, and we'll hopefully see the benefit of that in the second half of the year. You can see the average net working interest production has been fairly flat over the course of this year, but last year we had production over 5,000 barrels a day, and we hope to return to that in the course of this year. In terms of financial delivery, this is a pretty standardized set of numbers that we talk about each quarter. The one I always focus on is in the top left there, which is how much cash have we got in the bank as of the end of the year, which is just shy of $80 million. There's no debt associated with that, so it's a strong balance sheet. Gross assets have crept up to just over $300 million. The revenue for the year, of which that $140 million that I mentioned before, the total revenue, which includes what we've paid in royalty and production share to the government, is $204.5 million. EBITDA for the year is $100 million. That's a little lower than last year because we've had to account for an overlifting position. You can see from the chart here the oil sales for the year include in the fourth quarter an overlift. What we mean by that is that we actually sold more oil than we had in our inventory. We are allowed to do that under the rules of the Djeno terminal. Since the lifting, we have been in the process of paying that back, and we will be paying that back through the course of the first part of this year. I think we will reach balance sometime at the end of April and start building up a new inventory through the second half of the year. What that does mean is that we are unlikely to see another lifting or oil sale until probably the fourth quarter of this year as we pay back that inventory and then build up a new one. That will be a different pattern to the lifting that we have had in the last couple of years where we have seen a lifting every quarter more or less. I'm not complaining about that because we can enjoy the benefits of the overlift early, and that was the point of doing that. If you actually look at the kind of source and use of cash through the year on an accounting basis, we started out the year with $46.2 million, and we've ended the year just shy of $80 million, $49.7 million. Oil sales of 140. There's an accounting adjustment of $35.8 million to accommodate the overlift that I mentioned. OpEx costs of $20.5 million, which equates to about $11.5 per barrel, which is a pretty good, on a global scale, is a very competitive OpEx cost for a field of this nature. CapEx investments were quite modest this year. We've obviously had some commissioning of the new platform at Tchendo, but not a big infill drilling campaign in the last year. Only $13.1 million in CapEx. We look to increase that slightly as we entertain the drilling program that we have planned starting in April, May this year. Admin costs $14 million. We talked about this in the last quarterly report, higher than we would like. In that is about $6 million for people costs, and within that is also some restructuring costs because we have reduced the size of the company in terms of people over the course of this year. We will see a structural change in these costs going forward this year. There is also a large amount of money for professional services, and that is about $5.5 million for professional services, and that includes our auditors. We did an interim audit, you may remember, to support the shareholder distribution. The big moving part is the legal fees associated with our cooperation with the investigations in the U.S. and Norway, which was about $3.5 million in total for the year. The remainder of that $14 million is office costs and IT, and we're making some steps to reduce them as well. You should see a lower number when we get into 2025 on the admin costs. The rest here, I think, is pretty formulaic and working capital changes and debt repayments. We finished off the working capital loan that we had outstanding at the beginning of 2024, and we're debt-free now, as I said earlier. Nearly $8 million as dividends from the Congo asset go to our minority shareholders in that entity. That leaves us with a total of $80 million in cash. This is part of the story because we've been paid for the significant lifting over Christmas. We've been paid for that in January, which is an input of $64 million that arrived at the end of January. At about the same time, we also made a distribution to shareholders of about $26 million. In the round, we have, as I stand today, cash of about $115 million in the bank earning interest. Just comment on shareholder value, and it's been pointed out to me that I probably wouldn't stand in front of a share price performance if it wasn't a good story here, so I don't make any apologies for that. The operational strategy has delivered cash that we've been able to share with the shareholders and has obviously also driven a growth in the share price. We've had a buildup of cash in the year, and that's been very evident to the market. A 37% increase in the share price over the last 12 months. At its peak of NOK 14 per share, we did the distribution to shareholders of NOK 2 per share, offering another 14% return to shareholders. I think there's a very positive story here. I think the main point, though, in discussing this is that with the strong cash position that I just mentioned, the board is in a strong position to evaluate options for an additional distribution that will be recommended to the AGM later this year. A brief portfolio overview. If you're not familiar with PetroNor, our production comes from Congo- Brazzaville, the PNGF Sud license. Gross production from that field is just shy today of 28,000 barrels of oil per day. It's operated by Perenco, and our net share is 16.83% on a working interest basis. As I've mentioned, it's high-margin production. We have a redevelopment project in Nigeria in the Aje field. Our main efforts there have been in consolidating the partnership through an acquisition. Our current position is an economic interest of about 20%, which we acquired from Panoro a few years ago. Through the acquisition of New Age's Nigerian interests, we look to increase that to an economic interest of just over 50%. That is about achieving alignment in the partnership for the way forward, as well as establishing our position in the group. We see the potential for an attractive development there that would yield about 25,000 barrels a day of oil equivalent, but largely gas. Gas is considered a transition fuel for Africa, and we could see that as something that is a very investable proposition in that part of Africa. Although we've got exploration potential in both Congo and outside of the Aje field in Nigeria, our pure exploration play is in The Gambia in the A4 license, which is a proven basin now with production immediately to the north of us and prospects in our acreage that's analogous to that production. Prospects that are beginning to, from the work we've been doing, we're beginning to see seismic attributes that support the chance for finding hydrocarbons in these prospects. We are working on that with some excitement. Looking at the bottom chart here, the kind of numbers that I'd like to draw your attention to is 2 C resources of 36.7 million barrels of oil equivalent and 2 P reserves of 17.2 million barrels. If you look at the Congo production, which is the PNGF Sud field complex, those reserve levels and resource levels mean that at current levels of production, we have over a decade of production in 2 P reserves. If you then take into account the Congo part of the 2 C resources, there is the opportunity on what we understand today to double that. This is long-lived production and a very attractive asset. The chart on the bottom right shows you something that we measure on a monthly basis, which is the production efficiency, which is what is the, if everything is working, what would the field be capable of doing versus what it's actually doing on any month on average. We're used to having this at pretty high levels. Through 2023, it was averaging about 93%. We had experienced some production instability through the first half of 2024 because of infrastructure interruptions, as well as a building list of wells that required workers. Thankfully, we're seeing both of those issues being addressed now, and you can see on the fourth quarter the increase in production efficiency that was being achieved. We're now back at the levels that we're used to this field performing at, above 90% in terms of overall efficiency. That is down to good work on the workover program and also better stability in power generation now that the field is self-sufficient in generating its own power rather than relying on third-party power. This has led to just much more stable production. It also leads to less workovers because it is those interruptions that actually stress the downhole pumps, which like to keep working rather than being switched on and off all the time, like many things. Outside of the improvements in efficiency, we are also hoping to have an increase in the productive capacity of the field through the infill drilling program that will be focused on Tchibouela East. We have five wells planned. The rig is arriving in Congo from Gabon in April, and we will hope to see the benefits of that program start to take effect in the second half of the year, with us getting back up to, as I said, above 30,000 barrels a day before the end of the year. Brief summary of Aje, just so you can see what it is. It's just sitting offshore Lagos, right on the landing of the West Africa gas pipeline, which runs across the African margin in that position. The project is about half a TCF of gas with associated liquids and at least 5 million barrels of oil underlying that. We think that that may be more, and we're working on that to define an upside, which has been identified. Around the Aje field, we see exploration potential within the license that we have, as well as nearby discoveries that need infrastructure. It is well positioned to be a leading piece of development for this part of the basin just offshore Lagos, which is an important population center in Nigeria. The plan for redevelopment involves an FPSO with gas processing capability with a pipeline to shore and four or five wells, either reentering some existing wells that have been suspended or drilling a couple of new ones to produce the gas and also the underlying liquids. A 30 km gas pipeline runs from the FPSO to the shore. We have bought land in the landing point for that, where we would plan to site an LPG facility right next door to the compression station for the West Africa gas pipeline. It is very well located in terms of that infrastructure. Our current effort, as I said, is awaiting the approval in completing the deal we've done with New Age to get us to 50% economic interest in the license. We have meetings that are being scheduled, we hope, later this month to complete that process. These things can take time in Nigeria, but we've done all of the due diligence meetings with the ministry, and we hope it will be fairly straightforward to raise this up their to-do list. We're looking to get this done as quickly as possible. While we're waiting on that, we're focusing on the subsurface description of the reservoirs and particularly on the depth image of the deeper oil. We're just finishing off some depth image processing that has been ongoing for the last few months and should be complete in the next couple of weeks. We'll be confirming the potential upside that has been identified underneath the existing gas reservoir for this additional oil potential, which has a big driver on the economics because the liquids do count here. Alongside that, obviously, we have a regulatory requirement as well as a policy to conduct an environmental impact assessment, and sampling has been underway on that. We'll have a feedback into the planning for the project development. Just to touch on the exploration potential in The Gambia, as I said, we're conducting a technical work program, which really is showing some promise on giving us seismic attribute support for the prospects. The target reservoirs are well understood. They're being produced in the Sangomar field immediately to the north of us. We're looking to finalize that prospect description with a view to conducting additional conversations with potential partners. The license phase that we're currently in comes to an end towards the end of this year, and to move into the next phase, which involves a drilling commitment, we would like to have a partner to do that. That is the focus of attention in the course of the rest of this year. We have companies that are accessing the data around the new work that we're doing under NDA, so we're hopeful that those conversations will mature. In Guinea-Bissau, you'll recall that we farmed out our position there, and this led to the drilling of the Atum- 1 X well. That was completed in September last year, and you'll have to forgive me for being a little coy about the results of that well. If there is a formal announcement of that, then it's down to the government of Guinea-Bissau and the new operator, APUS Energy, to make that. Having said that, there is a general kind of opinion in the industry that this was not a commercial success. I can say that it did confirm all the major play elements that we had forecast for the area that have a bearing on future potential of the license. We understand that the operator is evaluating the final results of the well with a view to making a decision on a second well that could be drilled in 2026. That is all we know at this stage, and we wait with interest to see what announcements come out of that. Obviously, there is a deferred element to the farm out that we did that is contingent on future success. I'd have to say that with the results that we know of the Atum- 1 well, that's probably less likely than it was before that well was drilled. It hasn't completely gone away because if there is a second well, then there is still the potential for that deferred payment to be due on approval of a field development plan and subsequent continuous production. That's a kind of run through the portfolio. In terms of the ongoing investigation, I think that's really all I can say about that, that they're ongoing. It's been over three years now that we've been on this journey, and we're cooperating fully with the process in both Norway and the U.S. to help the authorities with their investigation. We don't have any real control over the timeline for this. I think given the passage of time and the work that's been done, that we will be seeing decisions being made in the course of this year. I don't have any insight as to that timing beyond just that belief that we must be at an advanced stage after the work that's gone into this. This has involved a significant commitment of legal resources by the company, and I look forward to a day when we don't have that to contend with. In summary, stable production from the Congo assets with an infill drilling program to resume in the second quarter of this year and have an impact before the end of the year. Company strategy is focused on maximizing the value of the existing portfolio and returning excess cash to shareholders. We have built a significant cash position again, despite the distribution of the return of capital to shareholders of $26 million that was done in January. The board will be in a position to consider an additional distribution in 2025, and that will be recommended to our Annual General Meeting. A positive outlook for that. That concludes my presentation, and I'd be very happy to take your questions now if you have any. Thank you, Jens. First question is, how big is the next dividend? Straight to the meat. Yeah, I think the board has got a strong position to consider here with cash in the bank today of about $115 million. We have to weigh that against a couple of factors here. One, as I've pointed out, the next lifting will likely be towards the end of the year given the overlift position. We need to make sure that we have provision for any expenditure that is planned during the course of this year. One of the major parts of that will be the infill drilling program. I think in balance, when we look at that, I think that you can expect that the quantum of an additional return of capital shareholders will be at least as much as the one we achieved at the end of January. We will look to inform the market of what that is once we have the final audited annual report, which will be coming out to us in April. Another question on the dividend and the timing. The stated dividend policy is 30% of result. Can we, based on this, assume a distribution in May 2025? We'd look to do it as early as possible. With the normal cycle, it would be our AGM in May with any return of capital to shareholders made immediately after that. We are looking at those dates. It kind of depends on when our audit is finished for the annual report and that sort of thing. We are working on the detailed timing, but as we stand here today, the annual general meeting is in May, and if that changes, then we will inform the market as soon as possible. What can you say about Økokrim and their view on distributing cash to shareholders? We have not had specific conversations with the authorities on normal course dividends or anything like that. We did hold back our payment of dividend from our Congo subsidiary last year until we were satisfied that it would not affect our position as a cooperating company. There was a dialogue then. As far as dividends from Topco, we have not made any provision for any potential outcome from the current investigations, and we see it as part of our normal business. What do the changes in the DOJ mean for the company? Yeah, that's an interesting one and a good question. I don't know if you've been following the kind of presidential orders that have been issued in the new administration in the U.S., but there have been some big changes announced in the focus of the DOJ and the priorities for that organization. It seems to be driven by more of an America First Agenda and a focus on domestic issues rather than international ones. We don't know what that means for the company. We've written to the DOJ as part of the normal communication that we've been having with them to ask for clarity. Given the magnitude of the changes and the scale of the organization that is being impacted by them, I'm not expecting an answer very quickly. Obviously, if there are any changes in the investigation, either from the U.S. or from Norway, we would be disclosing that to shareholders immediately. Thank you. Are you able or allowed to buy out your partner in Congo to increase your field share to 20%? There are no restrictions on buying out partners, and this is certainly something that is a possibility. It's not one that there's been any active conversations about. If we might be a willing buyer, there needs to be a willing seller. That is something that I can't really comment on at this stage. Thank you. You have said Perenco plans to restore the PNGF Sud facility back towards 35,000 barrels per day capacity in 2025. Will this be possible following the five well drilling campaign, and how would this impact cash flow versus 2024? What we need to do in terms of increasing production, now that we've got the efficiency of the existing infrastructure and wells back towards the levels that we expected, what we need to do to increase production is to increase the well capacity. Drilling new wells into these reservoirs both adds new reserves as well as improves recovery factor in the existing field. Our modeled outcome of the five well program in Tchibouela East is that we would see production rising above 30,000 barrels a day at least. That forecast is shared, by the way, by the operator. We look forward to a successful drilling campaign. Certainly, if the previous infill program is anything to go by, then this is certainly possible, and we would see a return to that kind of level of production. In terms of cash flow, cash flow is driven not just by production, but also by oil sales. We have to convert the production into inventory of oil and then also to get it to market. We have been selling our oil to ADNOC, with a strategic partnership with ADNOC, and we will be looking to mature the discussions with them as to the timing of our next lifting. There may be some opportunities to pool with others to bring that forward, but we are not looking at a lifting really at the moment realistically until towards the end of third quarter, early fourth quarter. We will have to see how that plays out. That will be the main determinant of the cash flow position. Good. Can you elaborate on what is happening with PNGF Bis? Yeah, good question. I think in the end of 2023, we announced that the Council of Ministers had approved the award of PNGF Bis to a Perenco operated group in which we would have a 25% interest. Those discussions have been continuing, and what remains to be agreed is a new production sharing contract. That discussion is one which we are letting the field operator, if PNGF Sud Perenco, take charge of that. There isn't a huge urgency from either the operator or from us on the timing of this because we've demonstrated that we have more than enough opportunities to invest in the PNGF Sud complex. It would be good to get this situation cleared up and a new production sharing contract so that in future we can also start to look at the potential for investing in the discoveries that are known in that license. Thank you. Moving on to Aje. What would be PetroNor's share of the Aje development, and are you looking at a non-recourse financing for the project? We are looking at economic interest for PetroNor once we've finished the outstanding acquisition of around 50%. Yes, for sure, we need project finance for the whole group needs project finance to see that project move forward. Previously, we were having some very encouraging conversations with some of the regional banks in Africa who viewed this favorably because it was essentially a gas project and aligned with their strategy for developing gas in Africa where it displaces or has the opportunity to displace heavy fuel oil and diesel in power generation. We would look to continue those conversations once we've had a bit more definition on the project and particularly on the underlying oil potential. This is a story that will develop over the course of this year. Good. Have you found any new candidates for the board? That is a very timely question. Indeed, we have, and we will be making an announcement for a new extraordinary general meeting to get approval for the nomination in the very near future. We have been looking at several factors here, one of which is our compliance with the balance of European versus non-European board members as well as gender balance, which is obviously very important. We are looking to come more into compliance than we are with our current arrangements, and that will be announced very soon. Thank you. There are no further questions. I will now give the floor back to you, Jens, for your final remarks. Thank you very much. To reiterate my summary, we have stable production, plan to increase it from our Congo assets, strong cash position that has developed with the lifting that was done at Christmas Day that supported the first return of capital to shareholders that we did in January, and we look to repeat that experience as soon as we have the audited accounts for the year available to the board. I think a positive outlook on the return of capital to shareholders. Thank you very much, and look forward to the next quarter's results.