Good morning. My name's Jens Pace, I'm the CEO of PetroNor, and it's a great pleasure to be back here in a delightfully sunny Oslo to give an update on the company. We put out a report this morning for the 1Q results of this year, and I have a few slides to take some highlights from that report. The main point of me being here is to answer your questions, so please start sending them in, and we'll get back to them after a short presentation. We start with the disclaimer slide. I have been using this slide for years, and it's never changed, but there are some changes in this one, so the eagle-eyed amongst you might want to have a look at that.
The outline of the presentation, I'll give a brief update on production mainly, and then go into the financial performance and make some comments about shareholder value. There are a few slides describing the portfolio, which is a somewhat standardized pack, but it gives us an opportunity to get into a little bit more detail on each of the assets. And then an update on the Oracle Crime Investigation before a summary of the highlights of the first quarter and some comments about going forward. We will get to questions and answers, so please send those in. Starting with production, we've seen some natural reservoir decline over the quarter. Our production was 4,321 barrels of oil per day, and that is a few hundred barrels shy of where it has been in the previous quarter.
The reason for that is, apart from some normal anticipated decline in reservoir, we've had a couple of high-rate wells that needed to be taken out for maintenance of their electrical pumps. These are now back online, and we will see production coming up. I think in the past year, we've had some difficulties with infrastructure stability. Thankfully, that problem is behind us now, and we're actually seeing reasonably good production efficiencies. It was 90% on average over the quarter, and as I stand here in May, it's well above that for the last month or so. We're addressing the reservoir capacity issue with an infill program. We have five wells scheduled to be drilled. The program is a few weeks late.
The rig, the AXIMA rig, is still in Port- Gentile of Gabon, but it is shortly destined to arrive in Congo and start operations, and certainly they are getting ready in the field for that. We will start drilling five wells. The production impact of that will start, we anticipate, in August, and we will work up to an exit rate at the end of the year of over 5,000 barrels a day, we hope, given success of that program. That will bring the full year average up to something closer to where it has been of 4,800 barrels a day on a working interest basis. That is based on operator estimates of the impact of the infill program. Looking forward to seeing that and a recovery of the production. What does that mean in terms of some of the financial metrics?
We're sitting on a pretty good cash position. At the end of the quarter, we had $107.5 million in the bank and no debt. When we look at revenue for the quarter, it's a little misleading in that the accounting standards that we use count the money that we give in oil to the government is counted as revenue. That was $13.9 million. We don't actually see that, but it goes through our books on our balance sheet. The time that we get revenue is obviously when we lift and sell our oil. The chart at the bottom here tells the story of the back track record of liftings and sales versus the inventory that we build up at the Jenner terminal as a result of our production.
You can see that if we look back on the last year, the first half of the chart there, we lifted about 1.8 million barrels of oil, and that is the large blue columns. The last lifting was just in December. That was nearly 880,000 barrels in one lifting at the end of the year. What that did was it produced what we call an overlift situation. We overlifted about 470,000 barrels. The production through the first half of this year is, to some extent, paying that back. We anticipate that we will reach a balance point around the middle of the year in June and then start building inventory again. As you build inventory, you start advancing up the queue at the Jenner terminal to have another lifting.
We anticipate that in the fourth quarter, we will be close to the front of the queue, and we anticipate a fourth quarter lifting. It'll probably be of the similar scale that we saw last year with a full cargo of around 800,000-900,000 barrels at the end of the year. Certainly, we'll have the opportunity to do that, and that's what we're hoping to be able to arrange. An alternative might be if we get into a pooling agreement with another lifter in the Jenner terminal, and we may be able to advance that. If it's just us lifting by ourselves, it'll be a late year program.
Somewhat confusing picture on the cash side because of the difficulties in the IFRS accounting system of dealing with not only the overlift, but also the fact that we have the sale of crude in December and the payment for that lifting in January, which kind of distorts the way that the numbers hit our balance sheet and gives us a large working capital movement, which you see as the large blue brick in the middle of this column here. The first area is starting from the cash position of $80 million at the 1st of January. We have the assignment of tax oil and royalties, which I mentioned earlier, which is counted as a revenue. OPEX costs, which looks a bit larger than it normally is.
The actual OPEX side from the field point of view is about $4.5 million, which is $11 a barrel, which is kind of a world-class operating cost number. The other elements of that are the kind of cost of sales, including the royalty that we've paid to the government, which makes it up to $9.9 million. Admin costs, which is the bit that effectively I control, is people costs and legal costs and professional services. The people and travel bill is around $1 million, and the bulk of the rest of it is in legal costs. That's something that we think will be addressed going forward with the changes in the investigation that I'll come to later on. The big working capital movement to account for the year-end and overlift situation. The CapEx investment so far, particularly in the Congo, quite modest, $2.8 million.
We expect that will go up in the second quarter as we start the drilling program in the Congo. The big flying brick at the end there is the repayment of capital that was achieved in January. That was $25.2 million, which leaves us the cash position that I mentioned before of $107.5 million and a strong position. I hesitate to stand in front of a chart of our share price, and maybe I won't do it if it's ever really bad news, but this is good news here, so you have to give me some allowance. We've been focused on a strategy here of looking at the existing portfolio, investing in the existing portfolio, but not looking at growth beyond that, which is a change in the strategy that was announced about a year and a half ago.
With that, we've made a commitment to give excess cash back to shareholders. We were able to achieve the NOK 2 per share distribution in January this year. It was somewhat delayed, you may recall, by conversations with the investigating authorities, but we were able to make that in January. We're looking at a recommendation for the AGM, which will be tomorrow, for an additional NOK 2.2 per share, about $30 million, and that will be proposed to the AGM, and if approved, will be paid before the end of the month. That gives us a total shareholder return over the last 12 months of about 78% following that, assuming that second payment is approved by the AGM. That's not too shabby, and I hope that we can continue with those sorts of contributions to shareholder value.
Let's go through the portfolio briefly. You can see we're focused in West and Central Africa. Our production comes from Congo-Brazzaville, the PNGF-SUD license. Gross field production is around 26,000-27,000 barrels of oil per day. With our working interest of 16.83%, that gives us our current production levels of about 4,300-4,500 barrels a day at the moment, which we obviously hope will be increased by the infill program later this year. As I mentioned, this is high-margin production with lifting costs of around $11 a barrel, and depending on the production performance of the drilling program, could be below 10 by the end of the year. The second area is a redevelopment project we have offshore Lagos in Nigeria, the Aje field.
Our current efforts there remain fixed on consolidating our license position with the acquisition of New Age's interests, which, when completed, will give us a working interest of about 52% in that redevelopment. We're interested in that redevelopment. It's a gas condensate and oil development, and it's well positioned just offshore Lagos for a big gas market, and it's right on the West African gas pipeline. We see that as a valuable asset. Finally, in the Gambia, we have a pure exploration play in deep water. It is targeting analogous prospects to the ones that have been successful in the north, in Senegal, in the Sangomar field. It is a proven basin, and we've been working on the technical description of prospects there while undertaking an exercise in trying to attract partners to join us for the next license phase.
I think the main issue to bring out of the metrics there is 2P reserves of 17 million barrels and 2C resources of twice that. Some legs at the current production level to continue with high levels of production. That is all from the Congo at the moment. It is the field complex in PNGF-SUD of about 2.3 billion barrels of oil originally in place, with only about 500 million barrels recovered to date, which is a low recovery factor for reservoirs of this nature. We see as much to come again as has already been produced. Our reserves position that I mentioned earlier on represents a 93% production replacement this year, which we have just completed our audit on. That supports more than a decade at current producing levels without doing too much more.
If we continue to invest as we have been doing, then there's an opportunity to double that lifespan in terms of production. The production efficiency, which is shown in the graph here, as you can see over the performance in 2024, which is the blue columns, dropped down to just over 85% of production efficiency. We're seeing that increase now as the investment in new infrastructure, particularly power generation, has stabilized the operating environment. We're seeing operating efficiency is getting above 90%, and we hope will stay at that level where they have been historically. The infill program will start shortly on the Chubwela East field. That is focused on some high-rate opportunities that we think will add significantly to our production levels. Just a little bit more on Aje.
As I said, we've been focused on getting the ministerial approval for the New Age acquisition. We anticipate that that will be any week now. We've fulfilled all of the meetings and workshops with the regulatory authorities that we're required to. From our perspective, they've gone very well. We are expecting that approval to come shortly. While we've been waiting for that, we've also been focused on the subsurface description of the asset, in particular on the depth image of the deeper oil reservoir that underlies the gas condensate reservoir. This is significant because it obviously affects the way we look at the project economics. I'm pleased to say that this has given us increased confidence in an oil upside. The previous versions of this slide had black oil at around 5 million barrels in terms of reserve potential.
We've seen that has at least doubled, if not more. We are excited about the potential that is being uncovered with this new work. Other things that we are doing are around the regulatory, environmental, and social impact assessment. To facilitate this, we have purchased land at the landing point of where we anticipate the pipeline from the development will come onshore. We are in the process of doing mandatory sampling and monitoring of the environment there so that we can make informed decisions about how that development is implemented. I think that is it for Aje for the time being. Just a few words on the exploration potential in West Africa here in the Gambia. As I said, we have been working on a seismic conversion of the 3D seismic that we have across the license.
This has provided some good support for the prospectivity that we see in these reservoirs that are analogous to the Sangomar field to the north in Senegal. Sangomar has been performing very well. It is still on plateau. These are proven reservoirs now. I am excited by what we are seeing in the seismic conversion. It does seem to show that we have support for these being oil-bearing in our license area. We are continuing to work to finalize that and working with our partners in GNPC, the national oil company, to look for partners to help us go through into the next phase of the license, which carries a well commitment. In Guinea-Bissau, you will recall this is a license we farmed down 100% in the course of 2023. It was drilled in 2024. The well was not commercially successful.
There have not been any formal announcements about that, but I think it is generally well known across the industry. The operator has been conducting studies to decide what to do next. We have not, although I have been in touch with them, received any reports as to whether they are going to move forward to another second well in 2026 or not. We wait on news for that. There is the potential for PetroNor to get contingent payments in the future in a success case. I would have to say that to start that with a disappointing well at the beginning puts that at some risk, but nevertheless, it is not discounted if they still have plans to move forward and drill. We will wait and see and obviously inform the market if we have any more information about that. A brief update on the investigation.
We announced earlier in the quarter that the Department of Justice in the U.S. had closed their investigations. Although the company was never a target of those investigations, we were nonetheless a subject and participating fully in that process. It is something we're pleased about that that work front on the legal side is at an end now. The investigation by Økokrim in Norway, which started some years ago, remains ongoing. We are continuing to cooperate with them on that. There is not much we can say about the forward timeline. It is outside the company's control. We do expect, based on signals from Økokrim, that we will learn more before the end of the year. We are waiting on that, their decisions. We will obviously update the market as soon as we have anything meaningful we can say about it.
That brings me to a pretty simple summary here. It is stable production with an infill program to bring us back up to levels we have seen in the past. I anticipate a strong exit from this year on the basis of that being successful. Oil inventory is building, as we would expect, and that has the potential to support a large lifting in the fourth quarter. With a company strategy that is focused on maximizing the value of the existing portfolio and returning excess cash to shareholders, we have a second return of capital of NOK 2.2 per share, which is about $30 million being proposed to the AGM tomorrow. If you want to support me on that, you will come out and vote for it. Thank you very much.
Thank you. We will now move on to the Q and A. What are the news on PNGF-BIS?
Yeah, thank you. In the end of 2023, we announced that the Council of Ministers in the Congo had approved the award of the PNGF-BIS license to a Parenko group, in which we would have, I believe, 25% of. We acquired 3D over that license in addition to the rest of the PNGF complex. Even though we haven't formalized the production sharing agreement yet, we thought it was wise to extend the survey over the whole area. That data arrived earlier this year, and we've been in the process of interpreting it and working with the operator to understand what it's saying about the license. We've actually found some things that are of interest, which we're in discussion with them. We anticipate that once we are able to inform the process of finalizing the PSC with our technical understanding of the license, that we will move forward on it.
We have, as I've demonstrated, quite a lot of opportunities to reinvest in the Congo as it is in the existing portfolio of assets in PNGF-SUD. We are not in a hurry to add to that list of opportunities, but we have the option to do that, and we will take it when we're ready and have reached agreement with the government on the PSC.
Thank you. What can you say about expected CapEx for 2025 and 2026?
We had some big years for CapEx when we've been installing new platforms, and as we did on the Chendo field, which was kind of largely a big spend through 2023 and into 2024. The kind of CapEx we've seen since then is really just focused on the drilling programs. Relatively modest CapEx we've seen in the last quarter of $2.8 million will see that increased in the next quarter with the drilling program. I think on a gross basis, there's been a shift of about $10 million. Our net of that will mean that we're seeing costs of around $4-$5 million in the next couple of quarters. I think in general, we're not seeing any big spend because we don't have any large infrastructure decisions to make. It will be focused on just increasing the well capacity of the field.
These have been very economic investments that we've seen payout of these within months as a result of some of the rate that we've been able to add. It is a very sensible program to be engaged in.
Good. What is the best guess when it comes to the timeline of seeing revenue from the Aje field?
Aje is things do take time. I think we've learned this. Waiting for government approvals is something that we've learned to be patient with. There is an element of things moving forward at a rate that the government wants. It's a bit of a dilemma because we would like to see the New Age transaction completed quickly. At the same time, there is an impatience on other parts of the regulatory authorities to see action in licenses and to see activity. I think we're trying to manage that dilemma and see that project move forward. If we could get to a point where we see a final investment decision in the course of next year, then first production would be two years after that on the basis of the plan that we've developed. It's not soon, but it's in that sort of foreseeable future.
Thank you. Positive to see another dividend. What will determine when the next dividend will be announced?
We have had the unusual situation this year of having essentially two returns of capital employed, one in January, and now we are contemplating a second for the AGM this month. That is unusual. You may recall that we actually delayed the January payment from 2024. That was a result of conversations we were having with the investigating authorities. What we would like to see is getting this back into a normal annual cycle that is focused on our AGM, which is always around May, and will be based on prior year performance and excess cash that we can identify that exceeds the needs of the company in terms of its investment plan. I anticipate that the board will monitor this situation.
If we get a lifting in at the end of the year, then we'll be in a similarly strong cash position for the next AGM in May 2026. I think we'll be looking at an annual cycle for this judgment to be made going forward.
For the year 2025, do you estimate the dividend in the same range as 2023 and 2024, payout of around NOK 2 per share?
I don't really want to be drawn too much on this because it depends on a lot of factors, oil price being one of them. We've seen some softening in the oil price in the course of this year, which, I mean, as an aside here, that makes you feel better about having overlifted last year at higher oil prices because we get the benefit of that. We will have to see how the cash situation and the company's needs work out when this judgment is made. If oil price recovers and we see a good lifting at the end of the quarter, the fourth quarter, then I could anticipate that we would see similar levels of return of capital. It will come down. The board will have to make that judgment when we have the finalized accounts for the year.
Thank you. There are no further questions. I'll now hand over to Jens for your final remarks.
Thank you for the questions. My final comments are really a return to the points I made on close here. We have got solid performance with stable production and a plan that is being implemented to bring that back up to levels we have seen in the past. An asset that has demonstrated it is responsive to infill drilling program. We are excited about that for the next year. Oil inventory building with a view to a big lifting at the end of the year. We look forward to that opportunity. Company strategy, which is very much focused on near-term shareholder returns. It is focused on maximizing the value of the existing portfolio and returning excess cash to shareholders. An opportunity to vote on that in the AGM tomorrow with a return of NOK 2.2 per share for investors.
Looking forward to see the outcome of that vote. Thank you very much.