Good morning. My name's Jens Pace. I'm the CEO of PetroNor, and it's good to be back in Oslo to review our third quarter results with you today. We sent out a report earlier this morning, and I have a fairly standardized slide pack to discuss those results. The main point of being here is to answer your questions, so please do send them in, and we'll get to them as quickly as possible. Thanks for your patience with the slightly later time this morning. We normally do this at 9:00 A.M. It was pointed out to us by Teodor Sveen-Nilsen of SpareBank that we were clashing with another company, so we moved it to avoid that conflict. I hope that means that, Teodor, you can be watching us, and thanks for following us. It's a normal disclaimer, and this is the outline of the presentation that I have today. It's a brief operational update, some comments on financial performance and our commitment to shareholder value, an overview of the portfolio, touch on what I can say about the investigation, and a summary then before we get to your questions. Starting with an operational update here, it's quite an uneventful quarter in terms of production. Third quarter production was on trend with previous quarters. There's a slight decline associated with normal reservoir depletion. The main story is that we've completed during the quarter, we completed a five-well infill drilling program, which is starting to have a big impact on our production. We drilled five wells. Three of them have been put on production. Two are on full production now. One is still being ramped up, and another two will be brought online in the coming weeks. The three wells that are already flowing are adding about 5,000 bbl of oil per day to the gross production, and this has been increasing. Production this week is above 4,700 bbl a day net. In fact, yesterday, I think it got up to 4,950 bbl a day. We are banging on the door of 5,000 bbl a day, which is where we wanted to end the year. If we look at the year in total, we expect fourth quarter production will bring up the average for the year above 4,300 bbl a day. We are looking for an exit rate above 5,000 bbl a day. We have hopes that it will be significantly above that. We also have just completed in the fourth quarter in November, after the close of the third quarter results, a lifting of 540,000 bbl. This is the first lifting we've had this year. This is how that plays out in terms of the financial delivery. Because we've had no other oil sales during the year, it kind of makes a lot of the metrics here that we're required to report somewhat meaningless. Revenue, for instance, of $38.6 million is just evidence that we've paid our taxes and the royalty to the government that is paid in oil. It's not really cash that comes into the company. The cash in the bank at the end of the quarter was just under $46 million. The lifting that we completed in November, we expect will add about $33 million, depending on the oil price, which we will announce as soon as it's known. We, it puts us in a strong position in terms of our balance sheet with zero debt. I think you can see also from the oil sales chart there that 2024 was a year of record sales for us of just shy of 1,000, 1.8 million bbl. That involved a significant overlift, which we've had to pay back during the course of this year. That has obviously been paid back to allow us to lift in November. You know, it's just the luck of the draw that that overlift was achieved at $77.9 a barrel. You know, we're expecting a price of around just over $60 a barrel in terms of the fourth quarter lifting. Looking at the waterfall of the use of cash here throughout the year, starting the year at the 1st of January, we had about just shy of $80 million of cash in the bank. The first two columns there are really to be consistent with the reporting methodology in our interim report. The first is the assignment of tax oil and royalties in terms of the revenue we pay to the government, and then there's an overlift adjustment for the overlift that I just described. In terms of real cash, though, the OpEx costs so far this year of $17.8 million show that we've consistently got a high margin production from the Congo. Our administrative costs of $6.3 million have shown a significant decline over previous reports, in line with our strategy to have a very focused team. This also reflects the fact that we've been able to shut down a major work front in the U.S. for our legal issues with the DOJ investigation. We are grateful for that. CapEx investments is mainly our contribution to the infill drilling program this year at $13 million. Some working capital adjustments of $7.4 million. Dividends we've paid to minority shareholders of our Congo subsidiary, as we've moved money up through the company, in order to allow us to make a return of capital or two returns of capital to shareholders, during the course of the year of about $56 million. That leaves us with cash in the bank, at the end of the quarter of $46 million. We will be paid the $33 million or whatever it turns out to be, from our lifting in December. That will actually make us nearly flat with the beginning of the year. What does that mean in terms of shareholder value? You know, I think that the continued strong delivery, in terms of production and a focused strategy, has generated excess cash that we've been using to support shareholder distributions. In the course of the year, we made a distribution of NOK 2 per share as a repayment of capital in January, which was in consideration of 2023 profit. After the AGM in May, we were able to also make another distribution, again a return repayment of capital, of NOK 2.2 per share, and that was in consideration of 2024 profit. As we look at the 2025 profit and the balance sheet that I've just described, the board will be in a strong position to consider additional repayment of capital or dividends as we go into the beginning of next year. Looking at the last 12 months, you can see from the share price chart, it's largely flat. The main kind of increases that you see there are associated with the distributions that we've made to shareholders, but that has given a total shareholder return over the last 12 months of about 47%. Brief overview of the portfolio. There's a few things that are changing. This slide is something that needs updating on a daily basis. Now, our gross field production of 28,000 bbl of oil per day in the Congo is, hopefully, the next time you see it, it'll be over 30,000 bbl of oil per day. Our operator there is Parenco, and our share is 16.83% on a working interest basis. We have a redevelopment project in Nigeria in OML 113, the Aje field. We are focusing on consolidating the license partnership through the acquisition of New Age's interest. That's still not completed. I'll give you some more details on that in a minute. We see an attractive redevelopment there, which includes the gas that's reservoir above the previously developed oil leg. Gas is a valuable commodity in Africa, and it's considered a transition fuel. In terms of exploration, we obviously have exploration potential in both Congo and in Nigeria, but a pure play exploration in the Gambia, we have had the A4 license, and that has expired this week. We are in discussions or have been in discussions on the possibility of an extension there. Our objective is to avoid taking on a drilling commitment. We think that, without a partner, that would be an unwise thing for the company to do. We'd have to pay a penalty if we were unable to fulfill the drilling commitment. Our decision is either to conclude the discussions on extensions or to relinquish the acreage. We're hoping to get clarity on that in the next few days. Going back to the Congo here and a little bit of a deep dive into the infill drilling program, I mean, you can see that PNGF Sud is a complex of a number of fields, and in place, original bbl of over 2 billion, 2 billion bbl of oil, and up to now less than 500 million bbl recovered. You know, a potential for as much production in front of us as has already been produced from the field. A long, long-lived production from this complex. The infill drilling program has been focused on one of the smaller fields called Chibwela East. You can see it highlighted on the map here. It's a fairly simple structure that's described in the two maps you see underneath. It has two stacked reservoirs, one on top of the other. The overlying reservoir is in the Chironian age, is largely a carbonate. Underneath that is a Cenomanian sandstone. The wells that we've had to date have been producing largely from the Cenomanian. If we look at the original oil in place in both of these levels, it's about 120 million bbl in each level. Production to date has produced about 14 million bbl from the Cenomanian and only about 2.5 million bbl from the Chironian. A massive opportunity here to increase reserves and increase production, which is what this program of five wells has been targeted on. All the wells have been drilled now and were completed within the budgeted time. Each of the wells has encountered excellent reservoir qualities as expected. There are two wells targeting the Chironian reservoir, and we've drilled U-shaped wells there with sections of over 400 meters in each that have been perforated and then acidized because it's a carbonate reservoir. It responds to stimulation with acid. It increases the amount of pore space in the reservoir that's available to the well when we put it on production, and that will be happening in the next week. We're just in the process of connecting them up. The three wells in the underlying reservoir, the Cenomanian, have horizontal sections of between 400 and 950 meters, and these have all been put on production now, and two have been ramped up. The third is still being ramped up. Between the three of them, they are producing at over 5,000 bbl of oil per day and contributing to that growth. You know, the beginnings of a very successful program here, which we think will give us a fantastic end to the year in terms of production growth. As this program has completed, we're looking to the next targets. The rig will be moving off to another part of the Parenco portfolio in the Congo. We expect to bring it back for wells on the Chibwela field, the main field that we have in PNGF Sud, in the end of 2026-2027 period. With a view to an additional infill program there, that is still being defined. Plenty of opportunities to reinvest here and, on the face of it, a great start to the success of this program. Now moving to Nigeria and OML 113. This is a redevelopment project, some 500 BCF of gas and a significant quantity of valuable liquids in terms of condensate and oil and LPG and propane. We see a plan for redevelopment here involving an FPSO with a gas processing capacity, and a pipeline to the coast where there is a compression point for the West African gas pipeline, which gives us a number of commercial options for selling the gas. The development will involve four or five wells, some of which have the recompletion of wells that have already been drilled, for both gas and liquids production and a plant, an LPG plant onshore to recover LPG. The current activity is mainly focused on trying to complete the commercial arrangements we have within the partnership group to make sure that we have an aligned partnership group here. We have had an SPA signed with New Age for some time, and we're looking to complete that. We did have ministerial approval in Nigeria for this, but we slightly changed the deal, not in any commercial sense, but in terms of the entities involved. We are going through a process of completeness here in making sure that the permission that we got from the ministry to complete that deal is still supported. We do not see any material change from their point of view, but we nonetheless are making sure of that. We hope that the completion will follow fairly shortly from that confirmation. Technically, we are working on pre-development studies here. In the course of this year, we have purchased land onshore at the landing point for the pipeline and where we would put the LPG plant and completed an ESIA for the development as required. We've held public meetings regarding that. We've reprocessed the seismic to reimage the reservoir and added upside to the volumetrics of Aje and significantly in the oil leg, which we were quite pleased about. We are following on with that in developing a 3D static and dynamic reservoir model to help us plan the development. As we go into next year, we'll be doing studies on the optimum drilling concept here. We have a choice to make as to whether, because this field lies in an area of steeply dipping seabed, you have an option of using a floater to drill fairly straight wells or a jackup that's located in shallower water and drill deviated wells. There is obviously a complexity and cost trade-off there that we need to fully investigate. We need the reservoir model to help us have that value debate. We'll also be refreshing our views of the market for suitable FPSO to deploy here. That will be the next series of studies that we do as we progress this development. Moving on now to the exploration portfolio in the Gambia, Guinea-Bissau area. The A4 license, the first phase has expired. We did not want to take a drilling commitment here because we wanted to have a period of time where we could identify a partnership group to go into a drilling phase. We had agreed in our license that there would be a period, the first, what we call the first phase, where there was a technical work program but no well commitment. That was to be done in parallel with a partnering exercise. We have not been able to find a partner, and that phase has now expired. We and the Gambians have a decision to make. We have been having discussions about extending that first phase without a drilling commitment, and we have not had an official reply to our offer in that regard. The outcome here may result in us relinquishing the block. I do that with a heavy heart because I do believe in the prospectivity of our acreage in the Gambia. I think it would be a significant increase in risk to take on a well commitment here at 100%. We know from the Atom One well, which was the most recent well drilled in this area, that an exploration well of that nature, that depth, would cost us over $60 million. I'm trying to avoid doing that, having a commitment of that magnitude without a partner. That's the situation there. We will advise as soon as we have an official response to the discussions that are ongoing in the Gambia. In Guinea-Bissau, we understand that the Atom One well, which was unsuccessful, will be followed up in the 2027 time period. We don't have any more details than that. Our interest here is that there are contingent success payments in the event of a approval of a field development plan and initiation of continuous production. That is sometime in the future. You would have to take the potential for that revenue of $60 million with some sort of a discount. It is still on our books. Moving on to the investigation, this was initiated in 2021 in Norway by Økokrim and remains ongoing. We've in the past commented that we expected to learn something in the course of this year about what Økokrim's intentions are in respect to the company. We have really no new information about that. The timeline for the investigation is uncertain and clearly beyond our control. We, I would normally say we are cooperating fully with the authorities in respect to this investigation, but actually, you know, we've had no real demands on us in the last six months or so. It's, we're kind of in a wait and see situation. To wrap up here, stable production in Q3 in line with expectations. The infill drilling program has been completed and is already starting to increase our production. We expect a good finish to the year in terms of production rate. We've lifted and sold 540,000 bbl, and that will further strengthen the balance sheet. We're in a situation where, you know, based on the company strategy of maximizing the value of the existing portfolio and returning excess cash to shareholders, the board will have a strong balance sheet to consider their options early next year. That concludes my presentation and over to you now for any questions that I can answer. Thank you, Jens. The first question from the online audience is, are you concerned that you are liquidating the company with all these distributions to shareholders? That's a very great question. It's really probably one for my board. I would say that, actually, the distributions that have been made are in line with a strategy and a policy that we laid out a couple of years ago in the AGM that was approved by shareholders. You know, we are pragmatically focusing our efforts on the existing portfolio rather than trying to grow the business with new ventures or taking on a lot of risk. Having said that, though, we are reinvesting a lot of money into the Congo. Both these infill programs and new platforms that we have put in over the last two years have added reserves, added production, and increased the stability of our infrastructure. You know, that has been a way of adding production and growth that we think is very valuable here. We have opportunities to go beyond that with PNGF Bis, which is some discoveries and also exploration upside. We are continuing to move forward with the Aje development. I think the strength of our balance sheet shows that the board has actually been quite prudent, in that we have retained cash to ensure that we can meet all of our obligations. We are not going to hold onto excess cash. I think it has been something that has been well supported by shareholders, and I think, and welcomed by them. We will continue with that policy as we generate excess cash. Thank you. On the topic of dividends, how should we think about next dividend payments? Same level as the previous dividends? You know, we have seen the strength of the balance sheet and the board will be making a judgment on the basis of that. You know, we have seen a reduction in oil price and hence with revenues over the course of this year. We would need to reflect on that and also our obligations in respect to CapEx programs in the course of 2026. We've been looking at the reinvestment in the Congo and actually next year is be fairly light because we won't be in an infill drilling program and we're not doing any major investments in infrastructure in the course of 2026. This perhaps opens up more opportunity to the board, even though our revenue is slightly lower as a result of the falloff in oil prices in the course of this year. I don't want to make any prediction in terms of the quantum here, but you can perhaps make a judgment based on what I've shown you in terms of the balance sheet. I think the board is committed to the principle of not holding onto excess cash. We will look for an opportunity to return money to shareholders that is appropriate. Thank you. You mentioned CapEx. Are you able to indicate expected CapEx level for 2026? I think we'll see CapEx levels, again, reflecting, as I just mentioned, the fact that the drilling program has been completed and we're not starting another one in the course of 2026. We'll see CapEx levels below $10 million for our contribution to the investment program in Congo. You know, between that and our investment in Aje, we will have a CapEx of less than $10 million. Five well infill program with positive impact. Should we expect higher production for full year 2026 versus 2025? I would hope so. We expect to start the year with a production that is above 30,000 bbl a day, and while we will see natural decline through the year, that is normal. I expect the average will be, will be an increase in a net increase in production, overall. Yes, I think is the answer to your question. How much oil does PetroNor currently have in inventory after lifting? We had a slight overlift in that 540,000 bbl. We have zero inventory. We have a negative inventory as we speak of the order of 150,000 bbl. That is, we kind of add nearly 90 to 100,000 bbl a month. I think by the end of this year, as we go into next year, we'll be on balance and starting to build inventory again. That's just, it's just a timing issue in terms of when you can lift and the quantity you can lift against the buildup of inventory. We're looking into offtake options for next year that may have some additional, higher frequency of liftings, which obviously would give us a more predictable cash flow and spread our risk somewhat in terms of the volatility of the market. We will make those announcements as we conclude the discussions that we're having. Are you able to indicate how many liftings you expect for next year? Really, that's following on from my answer to the last question. It depends on our offtake options. You know, it's a small company problem that it takes a while to build up your inventory to what's considered a parcel size at the terminal, which is 940,000 bbl. We would expect on a normal basis about a lifting a year. It’s a bonus if we can pool with others to get more than one lifting a year. We’ve been successful in doing that in previous years. This year, we’ve had one lifting, which we have pooled with others to achieve. We’ll be looking to do something similar in the course of next year. What is the potential write-off associated with the Gambia? Yeah, that’s a good question. I think we flagged that in the interim report. On our balance sheet, we’re carrying nearly $7 million of investment in the Gambia over the past years. This is associated with licensing costs of seismic, our license fees, the training fees that we have under our license agreement that we pay to the government, as well as the technical work program that we have undertaken. We have normally carried things like this on our books in the hope that when we do a transaction, as we did with Guinea-Bissau, that there would be an ability to recoup costs from an incoming party. We were able to do that in Guinea-Bissau. If we relinquish the A4 block, then clearly we will need to write that $7 million off. That impairment will hit us on relinquishment and the decision to relinquish. It will be a fourth quarter item or not at all if we are able to agree an extension. Okay. What are the latest news on PNGF BIS? PNGF Bis is an opportunity that sits alongside PNGF Sud. It's an interesting block. We have a right to enter it, and as with Parenco as an operator, and with our net interest of about 25%, that right has been approved by the Council of Ministers. We don't see any competition in that, although we haven't signed the production sharing agreement on it yet. This is a timing issue as much as anything else in that, if we are planning to, to drill a well there, we want to sign the production sharing agreement in time to, to operationalize it, shortly after signing rather than have a long delay after signing, which starts to run against time limits that would be implicit in the production sharing agreement. It comes down to what would be a sensible rig schedule. The priority there is obviously on increasing production. An exploration well needs to be factored into that schedule in the right way. That is a discussion we're having with our operator, Parenco, and they're hoping that they can come forward with a proposal on that. It won't be in 2026. Once we have an operational plan, then we would need to conclude the signature of the production sharing agreement and then start ordering long lead items for an exploration well. It is really a process of an implementation of a strategy rather than waiting on any sort of negotiations to be concluded or anything like that. I think we can do this at the right time when it makes sense. In past presentations, you have stated that you expect more clarity about the way forward for the EcoCrim investigations during the second half of 2025. Has anything changed since you have now removed this passage? Yes. The eagle eyes amongst you have seen changes in what has become a rather standardized slide, I do admit. We were led to believe that there would be decisions made during the course of this year. All indications are that that might still happen, but we do not want to overpromise in that area because clearly it is outside of our control. It, you know, when all this started nearly four years ago now, I was thankful I do not have a lot of experience of past investigations to have as a data point, but I was advised by our legal team that this would go on for years and it has proved to be the case. I should not be surprised about where we are now. We obviously hope that there will be some conclusion, one way or another, in the near future. We were very pleased to be able to close the investigation with the DOJ earlier this year. And, you know, we hope, we can't comment on where EcoCrim are in their process, but if they are going to make a decision, we would be welcoming it. Thank you. The board has consisted of only three directors since March 2025. Will the board be expanded with more directors? There's no plans to expand the number of directors. This is, I think, we have a sufficient number of independent directors to comply with our requirements. We're a small and very lean company. I don't want to get into a situation where the board is bigger than the management team, and so three directors is the right number for us at the moment. With the very little CapEx anticipated for the Aje field in 2026, how much progression can we expect to see towards an FID over the next 12 months? I have listed the kind of things that we are going to be doing in the course of next year, and we have agreed that with the partnership. I think it is fair to say that we would like to move faster. This is a development that is going to need to be project financed and will need over $500 million. And so, you know, that, that's the kind of, of commitment that, that we need to be absolutely sure we can make, as, as a partnership. And so that, that's really, I think, one of the, the main constraints on, on how we, how we move, move forward as a group. You know, our job in the meantime is to ensure that, that we have a, a really solid basis for, making the decisions with a, a, a robust concept that, that, that is, that could value, value the, the underlying liquids as much as the, the, the, the overlying gas that we, we are looking to, to develop. So, we are, we are progressing this in a, in a, a prudent way, and, we will look to see how we can accelerate, in the course of next year. How do you see the company in three years? What kind of production and what kind of free cash flow can we expect over this period? We're fortunate in that regard that, you know, our Congo production is long lived and is, that there is continued development opportunities there. In terms of that part of our portfolio, I would expect it to remain consistent with the progress that has been made over the last few years. More of the same, essentially. The big thing that could change that one way or another is what we decide to do as a group with Aje. Looking at the Congo separately, I think more of the same. Thank you. At this moment, we have one question left before we round off. Do you see opportunities in the M&A market? Are you reviewing opportunities on a regular basis? We are not actively looking at opportunities as a company ourselves. We've had a number of unsolicited approaches to us about combining PetroNor with others or looking at specific assets. There are no conversations ongoing as we speak. You know, we keep an open mind about this, but we're not looking actively at doing any M&A activity on our own behalf. Thank you. There are no further questions. That concludes today's Q&A session. Thank you very much.