Jens Pace. I'm the CEO of PetroNor E&P ASA, and it's a great pleasure to be back here in Oslo, which is starting to look very Christmassy and feel that way. We're here to discuss the third quarter report, which we sent out earlier on this morning, and I have a few slides to help me discuss that, and then I'd like to give you an opportunity to answer, to ask me any questions, and I'll do my best to answer. So please send them in as I'm talking. We'll deal with that at the end. I'm going to leave you from this view, take you from this view of Brazzaville across the Congo River through our disclaimer slide to the outline of the presentation. So I'm going to provide a very quick operational update of some of the highlights and then dig into the financial performance, really covering the first three quarters of the year. An overview of the portfolio and then discuss our plans for shareholder distribution that we have announced to the market. And there'll be a quick summary and over to you for any questions that you have. So looking at Q3, I think we're seeing improving production efficiency after some difficulties that we've experienced earlier in the year, and that's supporting what will be record sales for the company in terms of oil liftings and oil sales this year. To date, we haven't had any liftings this quarter, but to date we've lifted about 914,000 barrels of entitlement oil over the first two quarters of the year, and we achieved an average price of just under $83 a barrel. We have an additional lifting now scheduled in December. In fact, it'll be over the 24th and 25th of December while you're all with your families for Christmas. You can think of us having a lifting operation in the Djeno Terminal. We'll be lifting 920,000 barrels, which is a full parcel size, and we'll be looking to have that operation completed before Boxing Day. So the price over the Christmas week that is achieved in the market will determine the value of that, and it will be paid in January. So there's always a kind of a month delay. But a strong end to the year operationally and obviously a big positive start to the year in terms of the finances for 2025. So looking at the underlying production, we have a small increase since the second quarter. We're producing 4,763 barrels of oil per day on a working interest basis, and that's just a marginal uptick on Q2, and that actually disguises an improving trend that I'll tell you more about, which is associated with the commissioning of new power generation and focusing of the well workover capacity that has been happening in the Congo. I'll tell you more about that in just a bit, so in terms of financial delivery, building up a cash position, we started the year at about $46 million, and as of the end of the third quarter, we have $101 million in the bank. We've cleared our debt, so this is debt free, and our gross assets largely reflect the increase in the cash position of increased to $262 million. Looking at the highlights for the first three quarters, revenue has been about $126 million, and that yields an EBITDA of about $73 million, so cash flows from operations of just under $70 million. You can see the lifting schedule for the past three years, and you can see the impact of this fourth quarter lifting in December will give us a total sales of oil this year of just under 1.8 million barrels, which is a record for us and clearly a very successful year from the point of view of generating income. Look at the use of cash over the nine months, and to reiterate, our cash position started at $46 million. We've added $76 million in terms of oil sales, and then on the negative side of the balance sheet, we've spent $17.5 million in OpEx, which equates to about $11 a barrel. I think this is still world-class OpEx, and our share of CapEx of $10 million, which is paying largely for the installation of the new generating capacity and the drilling of a well to the Vandji Reservoir, which I'll talk about in just a minute here. $11.3 million in administration costs, and then a working capital adjustment, which is a result of us having a lifting in the fourth quarter last year and then receiving the cash for that in January. It means we carried a working capital balance over the year end, and we will have to do that again, as I've explained, in the year end for 2024-2025. It's just part of the way of accounting for the disparity between being paid and when we actually do the sales of our crude. The debt repayments are just under $5 million, which includes some of the interest payments we made. So we're debt free now as a company and our end cash position of $101 million. So just a brief overview of the portfolio, and those of you who follow PetroNor will perhaps be a bit tired about this slide, but it still does reveal a lot of information about what the company is focused on. Our production base is in Congo- Brazzaville, with our production coming from PNGF Sud, gross field production of about 28,000 barrels of oil per day, and as I've mentioned, with high margin production with OpEx of $11 a barrel. It's operated by Perenco, and our working interest in this is 16.83%. Looking further along the coast, we have a redevelopment project in Nigeria in OML 113. Our efforts there have been around consolidating our license position via acquisition of a partner, and we are moving forward with our development plan. The Aje field, it was originally developed as an oil field. We have plans to develop it as a combined gas and liquids production stream, which would yield about 25,000 barrels of oil equivalent per day. The gas content is something that is valuable in the region and is considered transition fuel for Africa, and then to round out the portfolio, we have an exploration block in The Gambia, which we've had for a while. We've extended the license. It's in a proven basin with discoveries in field and fields on trend with the prospects that we map in that block, so some headline numbers: 17.2 million barrels of oil equivalent in net 2P reserves, producing 4,800 barrels of oil per day. The legs in the portfolio are shown in the 2C resources of about 36.7 million barrels of oil equivalent. About 20 of that is in Nigeria, and the balance is in Congo- Brazzaville. Focusing on Congo, we have a field complex with multiple fields and multiple reservoirs within those fields, which gives us a total barrels of oil originally in place of over 2 billion barrels, and that has only given up about a quarter of those barrels to date with the production since it was started in the late 1980s. We think there's as much to come yet as has been produced to date, and obviously, this is a complex series of reservoirs that need careful management. We rely very much on power generation because a lot of the oil is lifted with electrical pumps, and the water injection is also electrically controlled. We've had a history of using power from a neighboring field, the Nkossa field, that had become unstable. If you look at the chart there, this is a chart of production efficiency. What we're measuring here is we're comparing what the field production should be if everything is working exactly as intended versus what it actually is, given that we have well outages and infrastructure outages. You can see that through 2023, which are the blue columns, we had very good production efficiency of over 90%, about 92% on average throughout the year. This started to change at the end of the year. We had some production outages because of a shortage of power generation at Nkossa giving us some unscheduled shutdowns, and this has kind of led to an instability that has continued until quite recently. We've installed a new platform over the Tchendo field, which includes 27 MW of power generation capacity using gas from the reservoirs in the PNGF Sud area, and that is starting to show dividends, and you can see the rise in the production efficiency as that has become more stable, and indeed, in November, we're expecting to have efficiency back to the kind of levels that we were achieving in 2023. One of the aspects of power outages is that it gives you a problem with all your electrical pumps. They don't like being shut down. They want to be run steadily, and so it increases the maintenance and the workover schedule for the whole field, and with offshore operations focused on installation of the new platform and that sort of thing, we've had a backlog of workovers developed because of those two effects. So the operator is starting to get on top of that now, and we're seeing some of the high-value wells being brought back onto production, and so we expect production to continue to rise, and we're hoping for a strong fourth quarter. One of those wells that was drilled last year is in the Tchibeli Northeast field, and that was to a deeper reservoir called the Vandji. And we've been monitoring the production from that well. It's performing as expected, but the relevance of it is that this reservoir is also hosting the discoveries in PNGF Bis, which is a license that we haven't completed the award of yet. And we're watching this production with interest so that it can inform our development plans for PNGF Bis. Discussions are going on with the government, between our operator and the government, about the production sharing agreement for that, but that has not been signed yet. We've also acquired 3D seismic data over the whole area, and that is being looked at to develop an understanding of what the opportunity set in PNGF Bis will look like. We have had great success in past years of infill drilling, and we've been reaping the benefits of that over the course of this year, but we haven't had much infill drilling program. We plan to restart that in 2025 with a focus of five wells on Tchibouela East, and I'm just going to give you a little bit of a summary of that on the next slide here. Tchibouela East is a fairly small field, actually, in relation to the others in the area. Of about 140 million barrels of oil in place, it's in two stacked reservoirs, one on top of the other, the underlying Cenomanian and the overlying Turonian reservoirs, high-quality sandstone reservoirs, and to date, we've only produced about 11% of the volumes in terms of recovery factor, so we see this as a good opportunity to convert 2C resources to 2P reserves, and we're targeting three wells into the deeper Cenomanian reservoir and two wells into the overlying Turonian, the undrained areas of the overlying Turonian, so that will generate between 4.6-11.5 million barrels of oil in reserves on a gross basis with a CapEx of less than $10 a barrel, so an efficient way to add reserves here, and we'll look forward to the outcome of that. The rig to start this program is scheduled to arrive on location in April. It's currently operating for Perenco in Gabon. So it'll be moving and starting in March and will be arriving in Congo in April. And you have to continue to pedal hard in mature fields to maintain production or to grow it, and these wells will have a significantly positive effect on the 2025 production rates and obviously also in 2026. So that will offset the natural decline in other fields within the complex. You may recall that actually previously we were planning to have the infill drilling programs centered at Tchendo in 2025. That has been deferred for this Tchibouela East program because we see this has a higher rate opportunity. Tchendo will follow, and we're not quite sure when at this stage. Moving on to Nigeria and the Aje redevelopment. Aje is about half a TCF of gas with associated liquids that's underlain by at least 5 million barrels of oil. We think there's some significant upside in the oil reservoir, and there's also exploration upside in the block and nearby discoveries that are looking for infrastructure to help develop the area, so I think there's an opportunity for a regional hub here, which would start with our plans for redevelopment of an FPSO with gas processing capacity and a pipeline to the coast where we have a compression point on the West African Gas Pipeline, so very well positioned to access that for the regional export. And so we're working on that plan and focusing on a few things in the immediate future. We have reached agreement to acquire New Age's interests in the license, which would increase our working interest from the current levels of 20% to just over 50%, and that also gives us more significant influence in the partnership group working alongside the operator, YFP. The ministerial process for approving that transaction is going well. We've completed the due diligence workshop during September, and we're hoping that that will be approved in the near future. We're also focusing on doing some depth reprocessing of the 3D seismic. We did some work on this earlier last year, which pointed to a significant upside in the underlying oil reservoirs sitting underneath the gas condensate of the Aje field. Oil is a big driver for the economics here, so we want to understand that better, and so we're doing some more work on the depth imaging underneath this field. We're looking at an area that's quite complicated technically because it has a steep ramp of slope from water depths of about 100 meters to the north to 1,500 meters to the south with a typical kind of canyonized near-surface geology and seabed, so we think we've cracked the code of that problem, and I've got high hopes that this current work we're doing will give us the best possible image of the structural controls on the underlying reservoirs, and so we think it's very sensible to get that story right before we move forward with positioning of development wells. We are also doing a baseline environmental and social impact assessment. This is obviously a mandatory part of the field development plan process. We've acquired land onshore in Lagos where we'll be putting an LPG plant, and so we'll be doing sampling there and also offshore so that the project can be informed by the up-to-date environmental information. To round out the portfolio now, we're looking at West Africa's high-impact exploration in our license in the Gambia. We've extended that license by 18 months from June 24, so we have it till the end of 2025 on the current agreements with the government. We're progressing some technical work there with our partner, GNPC, to integrate all of the wells that have been drilled in the Gambia, as well as some wells from Senegal to the north into our seismic interpretation. And this is actually yielding some quite interesting results, which I hope will encourage us to reassess the chances of success in the A4 license and the prospects that we've mapped here. We have a data room open because we have a partnering exercise on this block, and we have discussions ongoing with interested parties. Looking to the south in Guinea-Bissau, you'll recall we did a deal last year in which we farmed out 100%. We're no longer involved in that license, but we do have an enduring interest in it because of contingent payments on a success case on the block. We're awaiting information on the Atum-1x exploration well. We are in touch with Apus Energy, the new operator. Obviously, any announcements from that outcome will be up to them and the government of Guinea-Bissau to agree. We understand from them that we will get a full breakdown of all the studies and the conclusions in the early part of next year. So moving on to our plan for shareholder distribution, we clearly announced a dividend policy in the AGM in May last year and signaled an initial distribution of $25 million. In the last quarterly report, I explained that to support that distribution, we needed to ensure that we had liquidity across the PetroNor Group, which involved moving funds from our subsidiary in the Congo. Because of sensitivities of the ongoing investigation regarding the Congo, we have taken time to have conversations with the investigating authorities about this plan. And based on the outcome of those, we are moving forward with the implementation of the proposed strategy to distribute to shareholders. We want that to take place as soon as possible, but there are a number of steps that we have to go through, including moving funds into PetroNor in PSA before the end of this month, and then having an audit on an interim basis of our balance sheet that can inform an extraordinary general meeting, which will most likely happen in mid-January for us to be able to approve the distribution at that level. So we will provide further details on the timing of the AGM as soon as we know specifically what the dates will be. Our first step is to prepare for the audit of the end-November numbers, and we have a team ready in place to do that and hoping that that can happen very efficiently. So that kind of brings me to conclude my comments here, really. And I guess the summary is that we're seeing increasing production in the quarter and that is supported by the improvement in the production efficiencies from the Congo assets. And this is largely down to the power generation and workovers that I've mentioned. We look to build on the success of our previous infill drilling program to resume in 2025, and we're looking to add additional reserves and production capacity in that asset. We have valuable options in Nigeria and The Gambia, and we'll be able to progress them in the near term at a pretty modest cost in terms of the technical work and the sensible steps we're taking to move forward in both of those areas. So building a significant cash position with NOK 101 million at the end of Q3, rather, and significant oil sales for us scheduled at the end of 2024 with that 920,000 barrels that will be lifted at Christmas. So our strategy as a company is to focus on that existing portfolio. We're not looking at expanding from those three areas and generating cash that we can return to shareholders. So that initial distribution has been signaled, and we'll follow an extraordinary general meeting in January 2025. And the way I calculate it, $25 million works out to be about $0.18 a share or just under two NOK per share in terms of the value of that distribution. So it will be a significant initial distribution from the company that we hope to continue into the future. So that concludes my presentation. I'd be happy to answer any questions that you have. Thank you. And we do have a few questions coming in on the web. First one is, why is administration cost so high? Okay, tough one straight off the bat there. So administration costs cover a number of things, and that's $11.5 million in our cash waterfall that I showed earlier on. Half of that is down to people costs, salaries, and consultant costs. So we are actually taking steps to reduce that. Included in that half is some restructuring costs. With the focus strategy that we've adopted, focusing on the current portfolio and just maximizing the value of that and the cash flow from that, we have reduced the size of the employee base. We have agreed terms with four people in the U.K., one person in Norway, and two others internationally to leave the company. So that administration cost includes the cost of that restructuring this year, but going forward, there'll be lower costs on our salary base. I think the next tranche is really the amount we're paying on professional services. A listing in Oslo doesn't come cheap, and we have compliance costs and audit costs to take care of. But we also have a significant legal bill, and while some of that is associated with acquisitions that we're doing, like in Nigeria, a good deal of it is associated with the advice that we're seeking in relation to ongoing investigations in Norway and the U.S. So that's costing us about $1 million a quarter and is a significant part of the spend. And clearly, we are hoping that there will be a conclusion to that at some point in the future. I don't have a crystal ball to tell you when, but that is a cost that we have to spend at the moment as a cooperating company, and that's the responsible thing to do. And then the remainder is just office costs and IT and that sort of thing. We're looking at other measures that we can do to save money in those areas. So the focus is to maintain those sorts of administrative charges at a minimum and focus on cash generation for shareholders. And I think we have a plan to do that. Thank you. Next one is on operations. What is the daily production today? Well, as I came into the meeting, I did look at the daily production report, and from memory, I think it's at 2,975,000 barrels a day for the day on a gross basis. So our net from that will be 16.83% on a working interest basis of that. And I don't do the math in my head, but it'll be about 4,900 barrels a day. Any timeline for PNGF Bis? Well, we have had the Council of Ministers approval, which was announced at the end of last year. The remaining steps are a presidential decree and negotiation of a production sharing agreement. And so I think that the negotiation of a production sharing agreement is down to the operator, and that's something that they are working on. I wouldn't want to venture a timeline. I was in the Congo last week. We did discuss it, and I think it will be something that will be concluded, but probably not this year. It may happen in the course of 2025. Next one on Aje. In terms of the proposed Aje development, will the proposed redevelopment of the adjacent Sèmè field in Benin impact your analysis of scope in any way? We're following the regional activity, and I'm aware of plans in Benin, so all of these discoveries and the fields need infrastructure to be developed, and it clearly is something that is an opportunity to share costs if that makes sense to do so, and so we'll be evaluating that as plans mature. The kind of development that we've been talking about up to now is a standalone development as the first one out of the gate, so to speak, but if there's an opportunity to move forward with our neighbors, then that's something that would be maybe of mutual benefit. Thank you. The result of the drilling of Atum could generate $60 million. The result should be known, but no news has been communicated to the market. What is the reason for this? Well, like I explained in the presentation, any announcement from there is down to the new operator and the government of Guinea-Bissau. We don't have any control over that. The well was completed in September, but as always, there's a lot of studies that need to be done to complete a well analysis, particularly in an exploration well. This involves kind of moving samples around the world to have analysis done and things like that, which isn't always a quick thing to achieve. So we've heard from Apus Energy that they will expect to have more information available in the first half of next quarter, sorry, the first quarter of 2025. So we're being patient there. I would say that clearly the contingent payments were always some distance in the future. They rely on a field development plan approval, which takes some years and may even take an appraisal of the area before you can get to that position. And then the second tranche would be on an establishment of continuous production. So the cycle time for these things, if you look at analogous fields in the area, is measured in decades rather than immediate. So as a consequence, we're still carrying a provision for those contingent payments in our balance sheet. I think it's of the order of $2.6 million, but it's clearly significantly discounted versus the potential for the $60 million total that is mentioned in the slide and it's in the deal that we did with Apus Energy. So we'll be patient and we'll see what happens. I think in terms of our interests in the area, The Gambia position will be perhaps informed somewhat by the Apus Energy well. But more significantly, we look to the north and the Sangamar field, which went on production in June this year. And I think as of the end of September, has reached plateau production of 100,000 barrels a day and has already produced 8 million barrels. So clearly, the reservoir system in that part of the margin is a productive one. And we are looking at The Gambia very carefully to make sure we understand what that means for our economic evaluation of that area and our discussions with third parties. Thank you. Now over to the dividend. You have communicated to the market that dividend would be paid after the EGM in January. Will this be a 100% cash distribution? Can we also assume in the general meeting in May that a new dividend would be paid as 30% of the result for 2024? I'll take the second part of that first. The dividend policy is something that we will stand by. With continued cash generation in the company, we'll be looking to do that as part of a normal course business going forward. I'm not sure what the levels will be, but that will be based on the policy and the excess cash that's available to the company. You can see that we've positioned the company to maximize the cash generation and minimize the costs that we have going forward. In terms of the mechanism by which we distribute value to shareholders after the January EGM, we're still discussing that with our advisors. It will perhaps need to wait until then, but most likely it will be a cash distribution and most likely it will be what's called a return of paid-in capital. We raised money quite recently, which means that the $25 million we've signaled would be a return of that paid-in capital to shareholders. So that's the mechanism we're looking at at the moment. It might change, but we will get to that answer before the EGM. Thank you. Could you inform of the status of the Økokrim charges? Is there any signs that this will be concluded or closed in the near future? We don't know the status. I think my impression is that we're probably closer to the end than we are to the beginning, but this has been running for three years, so I don't know exactly what the time frame is going forward. Certainly, I don't think there's anything going to happen this year, but I'm hopeful that we will see a conclusion in the course of 2025. But I don't have a crystal ball on that, and it relies very much on the judgment of the authorities that are involved. Our position is to maintain our role as a cooperating company in both jurisdictions and to participate as required in the process. But that's all I can really say at this stage. What is the maximum potential fine that the company could be given due to the Økokrim charges? We've had no discussion with the authorities on fines. Clearly, it's a potential outcome if the company is charged and found to have done something wrong, but there's been no discussion on the quantum of what that would look like, and so I really can't comment. Thank you. There are no further questions, so I will now give the floor back to you, Jens, for your final remarks. Well, thank you for that. Some good questions there and very relevant, but I think I'll just come back to the overall summary, which is strong underlying production and a return to infill drilling signaled for Easter next year. Building a strong cash position and a commitment to bring that value to our shareholders with distributions that will start as soon as possible. So looking forward to getting that bit of business done in the early part of next year and then sustaining it moving forward. So thank you very much for your attention and have a great day. Bye now.