Good morning. My name is Jens Pace. I'm the Chief Executive Officer of PetroNor, and it's good to be back here in a somewhat wintry Oslo to follow up the fourth quarter results report that we put out at 6:30 this morning. I have a brief presentation, which we'll go through, but my main purpose here is to answer your questions. Please send them in, and we'll deal with them after a few slides. First, the disclaimer. I can't imagine there's many of you that look at these things, but there is a change from the last time we've had this up on a screen. With the relinquishment of our position in The Gambia, the A4 license in The Gambia, we've removed references to Dr. Adam Law of ERCE, who did our independent assessment of prospective resources, so he no longer appears on the disclaimer. So those eagle-eyed of you might have noticed that. So first of all, an outline of the presentation, and while the fourth quarter results show very strong operational story, I can't avoid dealing with the announcement that we made a couple of weeks ago regarding Økokrim's decision to indict a subsidiary of the company. So we're gonna deal with that up front, and then get into the operational update, financial performance, a brief overview of the portfolio, and then a summary. So look forward to your questions at the end of that. So first up then, an update on the Økokrim investigation. So as you know, Økokrim has decided to indict Hemla Africa Holding AS, which is a subsidiary of PetroNor E&P. It's an indirect subsidiary that holds our shares in the Congolese company that has our share of the PNGF Sud license in Congo. So it's been indicted in relation to suspected corruption committed on behalf of the company. And the company categorically contests this indictment and welcomes the opportunity to have this case thoroughly reviewed in court. We understand that a hearing will commence on the twenty-third of November this year. So we're looking to that date as the beginning of the process. Probably worth also noting that the Økokrim decided not to press charges against Topco, against PetroNor E&P for suspected market manipulation, it was lack of evidence. So I'm personally pleased about that, and our messages to the market is something that we all take very seriously. So I'm pleased that that that's not not been put in question here. This is the beginning of a process which I understand could take quite a long time. The trial itself initially will last for about 10 weeks, I'm told. So we won't hear a result, a ruling on that until probably March or April in 2027. Whatever happens, there'll likely be appeals on either side. So, you know, with this going to another court and then maybe ultimately to a Supreme Court, we're looking actually at the result of this only being known at the back end of 2028 or early 2029. So we clearly have a long process here of uncertainty that's kind of in some ways is, you know, it's welcome at least that we know.. Perversely, we know that the process going forward, it's been four years that this investigation has been hanging over the company. So, while we're deeply disappointed in this situation, we at least know that there is a process now to resolve it. In the meantime, PetroNor needs to continue to operate in normal course of business, and that's the job of me and my team to try and make sure that that is done as much as possible. Moving on to what that means, and looking at the last quarter, we've seen the production that has resulted from the infill wells that were drilled in Tchibouela East in PNGF Sud. They came online at the end of the year and added a wedge of production.. I'll show you a chart later on, but that added up to nearly 7,000 bbl of oil per day gross from these new wells at year-end, and that raised the overall gross rate of the field to 32,000 bbl a day. If you look at the chart underlying this, you can see that this is a reversal of a decline that we've noticed over the last three quarters. And it brings the average production for the year up to 4,600 bbl a day net. And, you know, the new capacity of these wells, is shown perhaps most markedly on the exit rate of the year, which was at above 5,000 bbl a day, 5,400 bbl a day. And that's how we are starting 2026. This production is adding to our oil inventory. It's currently... We had a lifting in November, you may recall, last year, so it was down to zero then, but it's now up to 250,000 bbl of oil, and we're adding to that at approximately 100,000 bbl a month. So we anticipate being in a situation to have another lifting and sale of oil in the second quarter. Well, that means in terms of the financial delivery for 2025, the cash that we have in the bank as of the end of the year was just shy of $60 million. And this with no debt, gross assets have somewhat reduced because of an impairment of our position in The Gambia with that relinquishment. And the revenue for the year was some $83 million, EBITDA of $63 million, and cash flows from operations of $61 million. So very healthy numbers there. You can see from the pattern of oil sales that's shown in the chart there, that we had only one lifting in 2025, and the reason for that was because of the record liftings we'd had in 2024, which included a significant overlift that we effectively had to pay back during the course of last year. And you know, the realized average price of those liftings for each year is shown. So if I'm going to have an overlift and have to pay it back, I'd rather do it where we are able to sell oil at a higher price than we have to pay it back. But that's sometimes the way it goes and sometimes not. So looking at the bridge for cash, based on the report that we've just sent out, over the course of 2025, we started the year with about $80 million, oil sales of $33 million, and then the overlift that I mentioned, we account for that in the course of 2025. So that's another $36 million. Some working capital movements that this year were in our favor, so an additional $23 million on the positive side of the ledger there. And then in terms of costs, $20 million in OpEx costs, works out at around $12 million a bbl, which is, I think. So, sorry, $12 a bbl, which is, I think, a high margin, representative of the high margin production that we enjoy at PNGF Sud. $20 million on gross investments, and that's on CapEx. That's largely the infill drilling program that we're enjoying the benefits of now. $8 million on admin costs for running the company, and this includes our legal costs, all our professional services costs, as well as people and the costs of our listing and board, and so forth. And that's come down over the years as we've kind of run the company as lean as possible. Then the big flying brick there that's in orange is the return of capital to shareholders, nearly $56 million that we made over the course of 2025, and some leakage of dividends to our minority shareholders in $8 million. Which leaves us with this cash position of just shy of $60 million as we enter 2026. So a 30,000-foot flyover the portfolio, and it's really focused on two areas now. Production is from the Congo-Brazzaville, PNGF Sud license, a gross field production of over 30,000 bbl a day. It's operated by Perenco, specialist operator for mature fields. Been doing a good job there. PetroNor's working interest is 16.83%, and as I've mentioned, high, high margin production. Moving to Nigeria, this is a redevelopment project that we have in the OML 113, which is the Aje Field. We have a redevelopment plan there that would yield some 25,000 bbl of oil equivalent per day. 70% of that is gas. Gas is considered a transition fuel in Nigeria because it displaces the use of heavy fuel oil and diesel for power generation. So it's an environmental alternative to the current situation. And our working interest now with the acquisition, the completion of the acquisition of New Age, which is interests in Nigeria, is now at 52% effective in the Aje Field development. So this increases our 2C resources to 78.2 million bbl. So seventy of that is associated with the Aje field. 2P reserves in the Congo of 17 million bbl, and with our current production, that at current rates, that would be 10 years of production. So a pretty healthy resource base to be operating from. Diving into the PNGF Sud asset a little bit more now. It's a field complex of a number of different fields with different reservoirs in each field. Some 2.3 billion bbl of oil originally in place and only 500 million bbl extracted to date. So we think that there's an opportunity for recovery of as much, again, as has already been recovered. So a long tail of production with, as we've demonstrated, a production rate that responds well to investment in new well capacity. And so the 5-well infill program that was drilled in Tchibouela East was completed in December. All the wells found good reservoir as expected. And you know, we're the rig has now moved on to a different assets that Perenco operate in the Congo. The plan is to bring it back in 2027 for more infill drilling programs, and we're looking at candidates now, either in the Tchendo field, Tchibouela, or even returning to Tchibouela East for one of the upper reservoirs that has proven to have worked out very well in this last campaign. You can see the wedge in the production that ramped up at the end of 2025 there from Tchibouela East, so that's the sort of thing we want to replicate from future programs. Going to look at Aje now, and I think it's worth stepping back a little bit and looking at what PetroNor has set out to achieve with the Aje redevelopment. I think that we recognized that this was a field that would benefit from a fresh look. And we wanted to do a few things up front. First is to align the partnership and consolidate our position there. This was. There was a history of misalignment between the partnership that had been partly a result of that had partly resulted in holding the field progress back. So we've formed a joint venture with the operator, YFP, and with the New Age transaction completed now, we have a leading position in the partnership, and I think we have a great opportunity to have an aligned partnership going forward. Second area that we've been focused on is defining a project with attractive economics. And this is something that, you know, we've done quite a bit of work on, with vendor cost estimates and a view of what would work here. So it... The idea is for an FPSO with gas processing capacity that would flow gas condensates to shore with a gas pipeline. And where we have bought land near the compression site plant of the West African Gas Pipeline, so a clear export route for the gas and extraction of LPGs on shore. We would be able to use some of the existing well stock and drill a few more wells to produce both liquids and gas. And so there'd be offshore export for the liquids and gas going to shore. So we've defined that project, and it, in our estimate, has some very attractive economics. And that's the basis in which we think the project should move forward. The other thing that we set out to do was to improve the subsurface description. Aje Field does lie in a kind of area of complex geology and overlying geology with a steeply dipping canyonized seabed. So there is a technical issue to be overcome in really refining the subsurface description so that it's fit for purpose for a redevelopment. And there have been surprises in wells that have been drilled in the past, so we knew this was an area that needed to be addressed. We've had two rounds of 3D depth migration of the seismic, and I think we're satisfied now that we have a stable product that we're taking into rebuilding a static and dynamic reservoir model. So a solid basis in which to plan the location of future wells. So I think we, we've ticked the box in a lot of those areas that we set out to come into this project with. I think what's now in front of the partnership is really the project financing that's needed to move forward powerfully with this. I think it's fair to say that with this company's situation in Norway, we recognize that PetroNor is probably not the right company to lead the project financing of Aje. So we're in discussion with advisors as to what the commercial solution would be to realize the value of Aje and secure project finance. So I expect that we'll be able to make more information available to the market in the future, but that's the focus right now of looking for the commercial solution with our partners. So in summary then, good fourth quarter production, with the production capacity increased by new wells, giving us a net production of over 5,000 bbl of oil per day. Building inventory of oil for sale at a rate of 100,000 bbl per month, and so we're planning for the next lifting and sale of oil in Q2, and entering 2026 with a strong balance sheet. And our focus is, apart from running that business, to prepare ourselves for the legal defense of the Hemla indictment in the hearing that starts in the fourth quarter. So thank you very much. I'm looking forward to trying to address your questions. Do we have any? Yes, we do. We will start with a couple on the dividend outlook. Is there any dividend policy in mind for 2026? The company has a dividend policy that was proposed a few years ago to an AGM that remains in place. We would see the concept of dividend or further shareholder distributions as part of the normal course of business. Probably too early for me to say what the situation is. The board will be looking at the company's situation, legal, operational, and financial, in order to make the recommendation to our AGM in May on that. So there'll be more news on the possibility of shareholder distributions at that point. Thank you. Moving on to a couple of questions on Aje. What is the current tentative high-level timeline to reach a final investment decision? Our budget is based on the basis of a FID early in 2027. So, we're looking at more project definition and commercial work through the course of this year, and that's been reviewed with our partners and agreed. So that's the... The work we're doing at the moment is on completing the subsurface definition and drilling planning, with a view to having a good cost basis for moving into an FID in the following year. What about the CapEx associated with the Aje plans? In terms of the development, we're looking at CapEx within a range, and the main determining factor of where it ends up in the range is the cost of an FPSO with gas handling capability. There are options here of refurbishing an existing FPSO, extending its life and adding the kit that's needed to it, or converting a tanker. So the range of CapEx is determined largely by that. But an average would be of the order of $500 million needed for the development based on our estimates. Also, with respect to the Aje field, can you say a little about the nearby discoveries at Ogo and Sèmè? Have the Sèmè project difficulties any bearing on the Aje development, and what is the forward plan on at Ogo? So let's deal with the development in Benin, and yeah, I could—I've been reading the articles about the drilling issues that they've had on that project. I think some of the previous wells in Aje have also experienced some of the same problems. I think the issue is an unstable shale layer in the overburden of the main reservoirs that needs to be handled with great care in drilling and is particularly difficult for deviated drilling. And that's something that we're taking account of in the drilling plan assessment that we are currently embarking on Aje. So we recognize the issue. There are technical solutions, but it does need to be handled with great care. And you know, I think in terms of the neighboring developments, they're producing or they're planning to start producing oil in Benin to the west of us, and the Ogo field to the east needs further appraisal. I can't really comment on what that group's plans are for doing that. But there's clearly a significant advantage here in being the first mover for gas evacuation from this area. That infrastructure, there's no room for multiple gas pipelines from this area to the West African Gas Pipeline route. I think there are economies of scale and synergies in doing something with those neighboring developments in the future. It's not part of the base case economics that we've been looking at for Aje, but clearly, it would be a source of value for all parties going forward. Do you still see the possibility for a payout in Guinea-Bissau? Guinea-Bissau is, you may recall, was farmed out 100% to Apus Energy. They drilled a dry hole there, but have plans to drill another well in the future. There are two deferred consideration payments possible in a success case for PetroNor. If there is a discovery there, then there's a payout of $30 million on the approval of a field development plan, and then another $30 million on the establishment of production. So these are payments that, if they happen, would be some distance in the future, some time in the future. Nonetheless, there is... While the group has plans to drill another well, there's clearly a possibility that there could be a payout. We note that Apus Energy are also looking for partners in the acreage in Guinea-Bissau. But it's interesting that some majors have been moving into the area. Chevron have picked up acreage in that area. And so it could be that we're seeing, you know, more interest from the industry in that part of the Atlantic margin. Thank you. Was the company's legal situation the reason why you did not get a partner in The Gambia? I've been at, trying to do farm-outs around the African margin for a good deal of my career, and we can always speculate as to the reasons why the world doesn't see, you know, your prospects the same way you do and don't fall in love with them in the same way you love them. You know, it is something that you're always looking for, for reasons and excuses for that. I don't know is the answer to that question. You know, the Gambia has, and while I certainly believe in the prospectivity of it, it has had a checkered past in terms of exploration. There have been dry holes drilled elsewhere in the Gambian, the small Gambian footprint. And, you know, it's speculation as to what has driven the lack of partners in the area for PetroNor. I certainly hope that the Gambian government is successful in attracting others to the area for investment. We did try and extend our licence, but in the end, we were not prepared to take on a drilling commitment at 100%. These are not cheap wells. You know, I think the Atum-1 well in Guinea-Bissau cost over $60 million, and I didn't want that to be as a big liability on our balance sheet without a partner. So, I think it was the wise decision not to commit to that, and I wish them luck in finding an operator that will come and invest for them. Regarding the Hemla indictment, can you confirm that the indemnity agreement and the 13.88 million shares held in escrow from the 2021 Sycamore transaction are still fully available and sufficient to cover both the potential corporate fine and all ongoing legal defense costs? That's quite a complicated question, and it speaks to agreements that were made some time ago. I'm sure that any indemnities that were offered then have long since expired. So, you know, I can't address the issue of indemnities directly. What I can say is that we have sufficient funding to manage our legal costs. We're not making a provision for them, but they are... Nonetheless, we have been meeting all of our obligations in terms of legal expenses up to now, and so this is part of our planning going forward. I can't comment any more on the Sycamore acquisition. Are there any estimates on how much these court proceedings will cost the company financially and in legal fees? We do know them in. We have those estimates in some detail from our legal team. You know, we've been, as I've showed you in the cash bridge earlier on, you know, where the costs of running the company in the year, last year, was some $8 million. That includes all of our legal fees. They came down quite significantly when the Department of Justice decided to drop the case and the investigation in relation to their involvement. The U.S. is a more expensive legal environment to work in. We have estimates that are part of our budget going forward for the legal costs here in Norway, and they're within the numbers that you see in that bridge. Thank you. Are the indicted individuals still shareholders? Well, PetroNor is a public company. We don't choose our shareholders, but we do have some visibility on the share register, yes, and the indicted individuals are represented on that. Then a follow-up on the dividend. Are you communicating that there are a fair possibility that no dividend will be given in May? Like I said, we will wait on the board's consideration of the company's situation. And this will include, you know, our operational and financial outlook, as well as the legal outlook, and we'll be making a recommendation to the AGM based on that consideration, and it's too early for me to say. Can you say a little about industry consolidation and rightsizing the business to maximize access to capital? We have not, because of our situation, been looking at accessing capital for some time. I mean, this journey started for me with the launch of the investigation, and I think it was made pretty clear to me that the idea of going and raising a lot of debt or raising equity in the markets was not something that would be very easy for PetroNor with this overhanging us. So, I'm probably not the right person to talk about industry trends in accessing capital at the moment. It's not part of our plan. We've got strong cash flow from our assets and no debt, so we're in a strong position and don't need... We don't have plans to access the capital markets. Thank you, and moving on to the final question for, for now. Can you comment on the separate civil lawsuit in Norwegian courts where Hemla is a defendant? We do have other civil suit that is ongoing in Norway. We have, I believe, very strong defenses that are yet to be played out in that suit. We don't see... We've made no provision for this on the advice of our legal team, who don't think that this is going to be an issue that will be successful against us. And so, you know, all I can say in terms of the progress of this is that it hasn't got to any discussion of the merits of the case or anything like that. At this stage, we are... We're still in the very early stages of this, and we will wait to see how it plays out. Thank you. There are no further questions, so I will now hand it back to you, Jens, for your final remarks. Thank you. Thank you for your questions. Some tough ones there, as usual, so I appreciate that, though. Appreciate your interest. And really, by way of summary, you know, a strong operational situation with the production responding to the new wells that we drilled, a growing inventory of oil for sale, and entering the year with a strong balance sheet. So, you know, operationally, the company is doing well, and our focus now is on managing that, but also keeping an eye on the defense of Hemla in the hearing that starts in the fourth quarter. So thank you very much for your attention.