Good morning. My name is Jens Pace. I'm the CEO of PetroNor E&P, and it's good to be back to discuss the company's quarterly report, which was put out this morning. I'm going to be using a few slides to review the first half of the year and to give some guidance as to what we expect to happen in the second half. Those of you who are familiar with the data will see that this is a fairly standardized format that we've been using. My main objective here is to allow you to ask questions, and I'll do my best to answer those at the end. Please do send them through in the normal way, and we'll get to them. My first slide here is a disclaimer, which I will leave you to read at your leisure. This is an outline of what I plan to go through today. There'll be a brief operational update to look at the first half of the year. We'll dig into financial performance and our focus on shareholder value in the next section. There'll be a brief portfolio overview to remind you of the geography and the activity sets we have across the portfolio. I'll give a brief update on the investigation that has been effective for the companies for a number of years now and then summarize the highest half of the year. Please do send in your questions, and we'll get to them as soon as we can. First up is the production over the first half of the year. As you can see, it's been stable at about 4,300 barrels for the last two quarters. This is accommodating a slight and normal reservoir decline that we see with a greater efficiency of the infrastructure and well-up time that has kind of worked against that. We've seen flat production for the first half of the year. I think the main thing I want to emphasize here is in June, the Axima rig arrived in country from Gabon and has started a drilling program of five wells on the Choboila East field. We expect production from those wells to start to have an impact from September through to the fourth quarter. If we look at the full year for 2025, we expect it'll be somewhere between 4,400 barrels- 4,700 barrels a day on average, and an exit rate of over 5,000 barrels, which gets us back to the kind of production that we were seeing over a year ago. We're looking forward to seeing the benefit of that program. During the first half of the year, we've distributed NOK 4.2 per share to shareholders as a capital repayment. This creates a total shareholder return over the last 12 months of over 50%. We're quite pleased with that, and we're committed to keeping focused on that metric as we go forward. Looking at the financial metrics, cash in the bank as of the 30th of June is just over $60 million. We've got revenue of $27.6 million, which is really only the grossed-up tax and royalties that we pay in oil to the Congolese state. We haven't had any sales of oil and any cash input for the first half of the year. To explain that a little bit more, the bottom graph shows the state of our oil inventory in green and our liftings and sales in blue. You can see that oil inventories can be negative as well as positive. We had record liftings and sales of oil in 2024. As a result, we had an overlift situation in December, and we started the year with about 500,000 barrels of overlift to pay back through the first half of this year, which we've done. We're now starting to build inventory again at a rate of about 90,000 barrels-1 00,000 barrels a month. By the end of the year, we'll be at over 600,000 barrels, and we expect this will support a lifting in the fourth quarter as it did last year. We're focused on getting that cash injection late in the year, pretty much like we did last December. If I look at the cash waterfall, you can see we started the year with just under $80 million of cash in the bank. Looking at the various flying bricks here, I've discussed the assignment of tax oil and royalties as a revenue, but we back that out in some of the other columns here. It's not really a real revenue to the company, but for accounting purposes, it's treated as revenue. Our operating expenses are $20.8 million. This is the field operating cost, which is about half that. This is a high-margin field. Our operating costs are about $11 a barrel. The other part of operating expenses is the royalty payment. It might look a little high, but this is a high-margin field. Admin costs are $5.4 million. Working capital movements as a result of the cash input in January that was related to production and sale of oil from the previous year means we've had a working capital balance that we've had to work through over the last couple of quarters. This is the residual of that. Capital expenditures investments in the infill drilling program are $5.4 million. The big flying brick there is the $55.8 million that was repaid to shareholders in two tranches early in the year and then in May through the annual cycle. We also have paid a dividend to our minority shareholders in the Congo. This leaves us with cash in the bank of just over $60 million at the end of June. We look at shareholder value. We have this discussion every time whether I should be showing a chart of the share price. There'll be a day that perhaps I won't want to, but perhaps that hasn't arrived yet. If you look over the last 12 months, we've had a growth in the share price of about 10%. You can also see the effects of the two capital distributions that we made to shareholders in the beginning of the year and then again in May, as reflected in those big spikes in the share price. It's a continued operational delivery that has allowed us to do this, but we have a very focused strategy of running the company very lean so that we can produce excess cash that will support these shareholder distributions. The total shareholder return over the last 12 months has been over 50% if you take into account the growth in the share price and the distributions. Quick overview of the portfolio. Production comes from Congo (Brazzaville) in the PNGF Sud license, which is operated by Parenco. Current field production on a gross basis is just over 25,000 barrels of oil per day. Our working interest of 16.83% means that we have a net production of 4,300 barrels a day at the moment. We have a redevelopment project in Nigeria, offshore Lagos in the Aje field. Our focus there has been in consolidating the licensed partnership. I'll give you a little bit of an update on that. The redevelopment plan would be mainly focused on gas as well as liquids. There's a big market for gas in the region. Gas is considered a transitional fuel for Africa. We have an exploration portfolio with a license in The Gambia, the A4 license, which is in a proven basin with some attractive prospects that are analogous to nearby production. At our current production level, we have 2P reserves of 17 million barrels and 10 years or over 10 years of production at the current levels. We also have 2C resources that would allow us to double that in the Congo as well as the 2C associated with the Aje field. Dive into the Congo a little bit. We've got a number of fields with 2.3 billion barrels of oil originally in place and only 500 million barrels recovered to date. An opportunity to improve that recovery factor to something closer to 50% from the 25% that is currently being produced. We are doing this by keeping the existing stock up and running with a work program, but also drilling infill wells on targeted fields where we see an opportunity to add production and reserves with additional wells. The current focus is on the Chubbula East field, and we have a five-well program that started in June there. The approach that's being taken is to do what we call batch drilling, which means that we drill each section of the well in sequence rather than a complete well at once. We have done all the top holes of these five wells, and we are currently working through sequentially into the next casing point. This means that the production will come on quite quickly once we start completing these wells. The first of these will be expected online in September. As well as the workover program, we have acquired new 3D seismic over this area, which is giving us some insights as to the remaining exploration potential in the area and particularly the potential for follow-on in PNGF BIS, which is a license that we have had awarded to us, but we have yet to sign the production sharing agreement. Going to Nigeria now and the Ajay field. It has been produced as an oil field in the past, but we see the potential for it to be a gas-condensate field with about half a TCF of gas and 17 million barrel condensate. An underlying oil leg, which has been focused on in the past, would also contribute to future production. It is a license that has an exploration upside in the license area and also nearby discoveries that are awaiting infrastructure. Our plan for development is to renew the FPSO with one that has gas processing capacity, drill four or five wells, and bring gas to shore via a 30-kilometer pipeline where New Age is interest, which would give us a working interest of over 51% in the licensed partnership. We are following through with the formalities to complete that acquisition and hope to do that in the next month or so. Our focus in the partnership is to continue our pre-development studies on the subsurface. We have completed reprocessing of the seismic into depth, and we are currently revising the reservoir model so that we can best position development wells. We have also acquired land on the landing points for the pipeline, which would also be the host for an LPG plant. This sits right next to the compressor station for the West Africa gas pipeline. Things are moving forward on Ajay. The final part of the portfolio is in The Gambia. We are chasing reservoirs that are analogous to the Sangamar field immediately to the north of us in Senegal. We've had a technical work program over the last 18 months, which has highlighted seismic attribute support for hydrocarbons in the prospects that we have mapped. We continue to be excited about the prospectivity, but we are also continuing to look for a partner for going into the drilling phase of this license, which on the current license timing will need to start in November this year. I'm not sure that we would go into a drilling phase at 100%, but we are hopeful that there will be continued interest in coming into that phase with us from others that we're in discussion with. You may recall that we had a position in Guinea-Bissau, which we farmed down 100%. The well that was drilled was not commercially successful, but encouraging enough that we understand the operator is planning to follow on with a well in 2027. This is important because there are deferred payments on success case milestones of a field development plan being approved and the establishment of production, which could yield up to $60 million of consideration to PetroNor E&P in the future. Moving on to the investigation, the big news in the first half was that the U.S. Department of Justice had closed their investigation into the company, which obviously was great news. We are still under investigation in Norway by Økokrim. This has been ongoing since 2021, and we're cooperating fully with them on this process. I don't really have any updates on the timeline for this. It's uncertain and obviously beyond our control. Based on the conversations that we've had with Økokrim earlier in the year, we are expecting some more clarity on the way forward sometime this year. We will update the market if there's any change in that. This is my wrap here before addressing your questions. It says stable production from the Congo (Brazzaville) assets. The offset of improved efficiency and production decline has given us flat production through the first half of the year. We are expecting this to rise significantly with the infill drilling program that is underway with new production that's anticipated to come online in September. The overlift position coming in from 2004 coming into the beginning of the year has been paid back, and we are building inventory now to support a fourth quarter sale of oil and working hard to make sure that happens. With our cash position and the confidence that we have in a lifting before the end of the year, I think we're in a strong position now for the board to be considering additional repayment of capital. Our focus is to maximize the value of the portfolio and returning excess cash to shareholders, as we've demonstrated in the first half of the year. I expect that the next cycle will be the normal cycle, which would be announced at the May AGM next year for an additional distribution. We will see how the cash position works out as we go into the end of this year. That's really all I have to say in a prepared sense, but I'm happy to answer your questions now. Please send them in. Thank you, Jens. First question on the Q&A is, why are the admin costs so high? That's a tough question to start with. The admin costs in the first half of the year were $5.4 million. They've actually come down quite a lot, and there's a couple of reasons for that. I think the equivalent admin costs for last year, a similar time period, was about $7.9 million. The reason that they've come down is that we've reduced the size of the company in terms of people. The people bill has come down from about, it's been halved from about $2.4 million to $1.2 million. That will come down further once we get out of some of the restructuring costs associated with that. In addition, our legal bill, which is a substantial part of the admin costs, has come down as a result of the U.S. closing their investigation. The U.S. legal bill was substantial. We did have some invoices early in the year associated with meetings we were having in Washington, but that activity has now stopped. I expect that to drop further from the current numbers. $5.4 million is an improvement over previous years, significant improvement over previous years, and we expect it to come down further. It's our current strategy to run the company as lean as we possibly can. Perfect. Thank you. Moving on to the next question. Are you able to provide any outlook for further dividends? Any plans for establishing a predictable dividend policy? We have a predictable dividend policy that was announced in an AGM a few years ago when we announced the change from being a growth company, a company focused on growth, to one that's focused on shareholder value. In the following AGM, we put out a dividend policy, and we've been following that since then. The predictability of the dividend is really around the predictability of our lifting cycle, which is always a problem for small companies when we have to build up to a certain parcel size to fill a tanker. This means that our cash inflow is quite lumpy. There are some ways we might be able to address this that we are in discussion about. Nonetheless, we have been successful in producing cash from our asset on a reasonably predictable basis of selling about 1 million barrels a year. I anticipate we'll be able to do that again in the fourth quarter this year. This will put the board in a very strong position to make an additional dividend or shareholder distribution of some form in the May AGM. Thank you. What is the status on the restrictions on taking cash out from the Congo (Brazzaville) subsidiary? There's no restrictions as such. There's obviously a legal process that we have to follow that's kind of part of the corporate governance of companies in the Congo, which means that dividends have to be declared on the basis of fully audited accounts. There's an annual cycle for auditing accounts, and this means there's an annual dividend cycle. There's been no restrictions on us accessing the cash that is in excess to what we need for reinvestment in the Congo. Obviously, we are following the law in doing this on audited accounts that is part of a normal corporate process. It means that timing is not always, timing is constrained by the audit cycle. It doesn't happen when you want it. It happens when we have fully audited accounts. We do what we can to ensure this is done efficiently and regularly. We have a good relationship with our auditors who close the books on a very efficient basis. I don't anticipate any problems at all. Okay. What is the next steps on Ajay development? We have been focusing on pre-development studies. This is largely in the subsurface area and making sure that our reservoir model is fit for purpose. We changed the subsurface interpretation significantly as a result of the new seismic work we did, and this has required an adjustment there. We're continuing to complete the environmental sensitivities assessment. This is associated with the landfall where we've purchased land for the pipeline that will come from the FPSO. Our main focus right now has been on consolidating the partnership because it has been an issue that has, I think, delayed the development in the past. We are hopeful that we'll be able to do that going forward now with the ministerial approval that we've received on the acquisition of New Age's interests. That's been the focus of our activity. The next step is really to complete the pre-development studies so we get to a position where we can come to the market with a field development plan update and a concept select that we will be able to get to a final investment decision on. The timing for that is obviously still under discussion with the partnership group as it is today. We hope that we'll simplify that discussion in the coming months. Very good. Thank you. Should we expect 2026 production to be above 2025 production? I fully anticipate that we'll come out of 2025 with production over 5,000 barrels a day on a net basis. I would expect 2026 production will be commensurately higher than we've seen through 2025. You have to keep pedaling hard on these old fields to keep production going. We've been doing that very effectively. The operator, Perenco, has done a good job of maintaining the existing well stock with an active workover program. We have two workover crews working on the field complex at the moment. That's reducing the waiting list for wells that have fallen over and need to be brought back to production. The infill program adds new well capacity. That's what I'm hoping will significantly increase the production through the second half of this year and going into 2026. The answer to the question is yes, we should see higher production in 2026. Thank you. Any updates on PNGF Sud and Chubbula East? I'll take Tchendo first. Tchendo was a field that we put a new platform on in the last year. There were two objectives to that new platform. One was to add generating capacity to the field to allow us to be self-sufficient for power. We've been seeing quite a lot of power outages and instability in the previous year, which had been a problem for the uptime of the whole field, in fact. By being self-sufficient in power, the field has been running much more stably, which is why we're seeing the increase in production efficiency that has allowed us to keep production flat. The second objective of the Tchendo platform was it has 14 new well slots. We're planning to do infill drilling on the Tchendo field from those slots. I think we had planned originally to do six initial wells. That program got deferred in favor of the program we're currently doing on Chubulla East, really for reasons of higher priority because of rate. We think we'll get a higher rate from Chubulla East than the Tchendo wells. They're still in the program, but we're not sure when we'll get to them, whether it'll be next year or early the year after. We're still working on that. We have the capacity now with the wellhead platform to implement that quite quickly. Thank you. On the second part of the question of PNGF BIS, the license has been awarded to a Perenco-led group. Our PetroNor's working interest in that would, I believe, be 25%. We're in discussion with the operator as to the final award of the production sharing agreement that is necessary to start work on the license. We have acquired 3D seismic survey over it, which we've been interpreting, which will inform that discussion with the government on the final production sharing agreement. It is very much in Perenco's hands. I'll be traveling to the Congo to meet with Perenco in the normal cycle for the technical committee meeting in November. I expect that this will be a subject of an update then. It is a license that we see good potential in, but obviously, the detail of which needs to be informed by the work that we're doing on the new seismic. Okay. Okay. Thank you. You report CapEx of $5.4 million for the year-to-date period. What do you expect CapEx to be for the full year? The full year CapEx for the infill drilling program for us on a net basis will be closer to $18 million. The $5.4 million for the first half reflects that we were perhaps a little delayed getting started, a month delay in the rig arriving from Gabon. I expect the second half of CapEx will be a little bit higher as we fully execute that drilling program, which is the main investment that we're making. Yeah, around $18 million for the year in total. We've paid about $5.4 million in the first half of the year. Looking at next year, I would expect it to be something similar. We won't know that until Perenco issues the license budget, which will be in November. I'll be able to update the market in the next cycle. Perfect. Moving on to what seems to be the final question for now. Does PetroNor E&P have the correct capital structure to support a 51% share of the CapEx on the Ajay development, or is the current plan to bring in a partner? We've looked hard at how that project would be financed. We do see a good debt capacity for project financing the Ajay project. We would still need to put in some equity capital. We don't have any debt at the moment as a company, and the Congo production is entirely unleveraged. We do have options around that. I think behind the question is, would we welcome a well-funded partner? I think the answer to that is yes. We're looking at what that might look like for the partnership group. Our current focus is on trying to clean up the existing partnership and allow the project to be presented to either a debt financer or another equity partner in a robust way. It's a bit of an inconclusive answer, I realize that, but we do see the Ajay project as a very attractive project, one that can attract both debt and equity finance. Thank you. There are no further questions. I will hand it back to you, Jens, for your final remarks. Very good. Thank you for your questions and some good ones there. Just to reiterate the key messages, really, for the first half of the year and then looking forward to the rest of the year. You know, solid production, which gives us a platform now to see that increase with the infill drilling campaign that is underway and running well. We expect to see a good production increase in the second half of the year. A lifting as well would be supported by the growth in inventory now that we've paid back the overlift from 2024. All of this to a strength and an already strong cash position, which we think will put the board in a great shape to consider additional shareholder distributions as we look towards the end of the year. Thank you very much for your attention and look forward to seeing you again in the next quarter cycle.