PetroNor E&P ASA (PNOR) Q4 FY2025 Earnings Call Transcript & Summary

Good morning. My name is Jens Pace. I'm the CEO of PetroNor, and it's good to be back here somewhat wintery Oslo to follow up the fourth quarter results report that we put out at 6:30 this morning. I have a brief presentation which we'll go through. But my main purpose here is to answer your questions. So please send them in, and we'll deal with them after a few slides. So first, the disclaimer, and I can't imagine there's many of you that look at these things. But there is a change from the last time we've had this up on the screen. With the relinquishment of our position in the Gambia, the A4 license in the Gambia, we've removed references to Dr. Adam Law of ERCE, who did our independent assessment of prospective resources. So he no longer appears on the disclaimer. So those eagle-eyed of you might have noticed that. So first of all, an outline of the presentation. And while the fourth quarter results show very strong operational story. I can't avoid dealing with the announcement that we made a couple of weeks ago regarding Okokrim's decision to indict a subsidiary of the company. So we're going to deal with that upfront and then get into the operational update, financial performance and a brief overview of the portfolio and then a summary. So look forward to your questions at the end of that. So first up, then an update on the Okokrim investigation. So as you know, Okokrim has decided to indict Hemla Africa Holding AS, which is a subsidiary of PetroNor. It's an indirect subsidiary that holds our shares in the Congolese company that has our share of the PNGF Sud license in Congo. So it's been indicted in relation to suspected corruption committed on behalf of the company. And the company categorically contests this indictment and welcomes the opportunity to have this case thoroughly reviewed in court. And we understand that hearing will commence on the 23rd of November this year. So we're looking to that date as the beginning of the process. Probably worth also noting that the Okokrim decided not to press charges against [TopCo, ] against PetroNor for suspected market manipulation as lack of evidence. So I'm personally pleased about that. Our messages to the market is something that we all take very seriously. So I'm pleased that that's not been put in question here. This is the beginning of a process, which I understand could take quite a long time. The trial itself initially will last for about 10 weeks, I'm told. So we won't hear a result or ruling on that until probably March or April in 2027. Whatever happens, that there'll likely be appeals on either side. So with this going to another court and then maybe ultimately to Supreme Court, we are looking actually at the result of this only being known at the back end of 2028 or early 2029. So we clearly have a long process here of uncertainty that's kind of in some ways it's welcome at least that we know -- perversely, we know the process going forward. It's been 4 years that this investigation has been hanging over the company. So while we're deeply disappointed in this situation, we at least know that there is a process now to resolve it. In the meantime, PetroNor needs to continue to operate in normal course of business. And so that's the job of me and my team to try and make sure that, that is done as much as possible. So moving on to what that means and looking at the last quarter, we've seen the production that has resulted from the infill wells that were drilled in Tchibouela East in PNGF Sud. They came online at the end of the year and added a wedge of production I'll show you a chart later on, but added up to 7,000 barrels of oil per day gross from these new wells at year-end. And that raised the overall growth rate of the field to 32,000 barrels a day. If you look at the chart underlying this, you can see that this is -- it reverses a decline that we have noticed over the last 3 quarters. And it brings the average production for the year up to 4,600 barrels a day net and the new capacity of these wells is shown perhaps most markedly on the exit rate of the year, which was at above 5,000 barrels a day, 5,400 barrels a day and that's how we are starting 2026. This production is adding to our oil inventory. It's currently -- we had a lifting in November, you may recall, last year. So it was down to 0 then, but it's now up to 250,000 barrels of oil, and we're adding to that at approximately 100,000 barrels a month. So we anticipate being in a situation to have another lifting and sale of oil in the second quarter. What that means in terms of the financial delivery for 2025, the cash that we have in the bank as of the end of the year was just shy of $60 million. And this -- with no debt, gross assets have somewhat reduced because of an impairment of our position in the Gambia with that relinquishment. And the revenue for the year was some $83 million, EBITDA of $63 million and cash flows from operations of $61 million. So very healthy numbers there. And you can see from the pattern of oil sales from -- that's shown in the chart that we had only one lifting in 2025. And the reason for that was because of the record liftings we'd had in 2024, which included a significant overlift that we effectively had to pay back during the course of last year. And the realized average price of those liftings for each year is shown. So if I'm going to have an overlift and have to pay it back, I'd rather do it where we are able to sell oil at a higher price than we have to pay it back, but that's sometimes the way it goes and sometimes not. So looking at the bridge for cash, based on the report that we've just sent out over the course of 2025, we started the year with about $80 million, oil sales of $33 million. And then the overlift that I mentioned, we account for that in the course of 2025. So that's another $36 million. Some working capital movements that this year were in our favor. So an additional $23 million on the positive side of the ledger there. And then in terms of costs, $20 million in OpEx costs works out at around $12 million a barrel, which is I think -- sorry, $12 a barrel, which is, I think, a high margin representative of the high-margin production that we enjoy at PNGF Sud. $20 million on gross investments and that's on CapEx. That's largely the infill drilling program that we're enjoying the benefits of now. $8 million on admin costs for running the company, and this includes our legal costs, all our professional services costs as well as people and the cost of our listing and board and so forth. And that's come down over the years as we've kind of run the company as lean as possible. Then the big flying brick there that's in orange is the return of capital to shareholders, nearly $56 million that we made over the course of 2025 and some leakage of dividends to our minority shareholders of $8 million, which leaves us with this cash position of just shy of $60 million as we enter 2026. So a 30,000-foot fly over the portfolio, and it's really focused on 2 areas now. Production is from the Congo Brazzaville PNGF Sud license. Gross field production of over 30,000 barrels a day. It's operated by Perenco, specialist operator for mature fields, been doing a good job there. PetroNor's working interest is 16.83%. And as I've mentioned, high-margin production. Moving to Nigeria. This is a redevelopment project that we have in the OML 113, which is the Aje field. We have a redevelopment plan there that would yield some 25,000 barrels of oil equivalent per day. 70% of that is gas. Gas is consider a transition fuel in Nigeria because it displaces the use of heavy fuel oil and diesel for power generation. So it's an environmental alternative to the current situation. And our working interest now with the acquisition -- the completion of the acquisition of New Age's interest in Nigeria is now at 52% effective in the Aje field development. So this increases our 2C resources to 78.2 million barrels. So 70 million of that is associated with the Aje field. 2P reserves in the Congo of 17 million barrels and with our current production that -- at current rates, that would be 10 years of production, so a pretty healthy resource base to be operating from. Diving into the PNGF Sud asset a little bit more now. It's a field complex of a number of different fields with different reservoirs in each field. Some 2.3 billion barrels of oil originally in place, and only 500 million barrels extracted to date. So we think that there's an opportunity for recovery of as much, again, has already been recovered. So a long tail of production with -- as we've demonstrated a production rate that responds well to investment in new well capacity. And so the 5-well infill program that was drilled in Tchibouela East was completed in December. All the wells found good reservoir as expected. And were -- the rig has now moved on to a different assets that Perenco operates in the Congo. And the plan is to bring it back in 2027 for more infill drilling programs, and we're looking at candidates now either in the Tchendo field, Tchibouela or retuning to Tchibouela East for the -- one of the upper reservoirs that has proven to have worked out very well in this last campaign. And you can see the wedge in the production that ramped up at the end of 2025 there from Tchibouela East. So that's the sort of thing we want to replicate from future programs. So going to look at Aje now. And I think it's worth stepping back a little bit and looking at what Petro has set out to achieve with the Aje redevelopment. I think that we recognized that this was a field that would benefit from a fresh look. And we wanted to do a few things upfront. First is to align the partnership and consolidate our position there. This was -- there was a history of misalignment between the partnership. It have been partly a result of -- that have partly resulted in holding the field progress back. So we have formed a joint venture with the operator, YFP. And with the New Age transaction completed now, we have a leading position in the partnership. And I think we have a great opportunity to have an aligned partnership going forward. Second area that we've been focused on is defining a project with attractive economics. And this is something that we've done quite a bit of work on with vendor cost estimates and a view of what would work here. So the idea is for an FPSO with gas processing capacity that would flow gas condensate to shore with the gas pipeline, and where we have bought land near the compression plant of the West African gas pipeline. So a clear export route for the gas and extraction of LPGs onshore. We would be able to use some of the existing well stock and drill a few more wells to produce both liquids and gas. And so there'll be offshore export for the liquids and gas going to shore. So we've defined that project and in our estimate has some very attractive economics. And that's the basis in which we think the project should move forward. The other thing that we set out to do is to improve the subsurface description. Aje field does lie in a kind of area of complex geology and overlying geology with a steeply dipping canyonized seabed. So there is technical issues to be overcome in really refining the subsurface description so that it's fit for purpose for a redevelopment. And there have been surprises in wells that have been drilled in the past. So we knew this was an area that needed to be addressed. We've had 2 rounds of 3D depth migration of the seismic. And I think we're satisfied now that we have a stable product that we've taken into rebuilding a static and dynamic reservoir model. So a solid basis in which to plan the location of future wells. So I think we've ticked the box in a lot of those areas that we set out to come into this project with I think what's now in front of the partnership is really the project financing that's needed to move forward powerfully with this. And I think it's fair to say that with the company's situation in Norway, we recognize that PetroNor is probably not the right company to lead the project financing of Aje. So we're in discussion with advisers as to what the commercial solution would be to realize the value of Aje and secure project finance. So I expect that we'll be able to make more information available to the market in the future, but that's the focus right now of looking for the commercial solution with our partners. So in summary then, good fourth quarter production with the production capacity increased by new wells, giving us a net production of over 5,000 barrels of oil per day. Building inventory of oil for sale at that rate of 100,000 barrels per month and so we're planning for the next lifting and sale of oil in Q2 and entering 2026 with a strong balance sheet. And our focus is, apart from running that business is to prepare ourselves for the legal defense of the Hemla indictment in the hearing that starts in the fourth quarter. So thank you very much. I look forward to trying to address your questions. Do we have any?

Yes, we do. We will start with a couple on the dividend outlook. Is there any dividend policy in mind for 2026?

The company has a dividend policy that was proposed a few years ago to an AGM that remains in place. We would see the concept of dividend or further shareholder distributions as part of the normal course of business. Probably too early for me to say what the situation is. The Board will be looking at the company's situation, legal, operational and financial in order to make the recommendation to our AGM in May on that. So there'll be more news on the possibility of shareholder distributions at that point.

Moving on to a couple of questions on Aje. What is the current tentative high-level time line to reach a final investment decision?

Our budget is poured on the basis of FID early in 2027. So we're looking at more project definition and commercial work through the course of this year, and that's been reviewed with our partners and agreed. So that's the work we're doing at the moment is on completing the subsurface definition and drilling planning with a view to having a good cost basis for moving into an FID in the following year.

What about the CapEx associated with the Aje plants?

In terms of the development, we're looking at CapEx within a range and the main determining factor of where it ends up in the range is the cost of an FPSO with gas handling capability. There are options here of refurbishing an existing FPSO, extending its life and adding the kit that's needed to it or converting a tanker. So the range of CapEx is determined largely by that. But an average would be of the order of $0.5 billion needed for the development based on our estimates.

Also with respect to the Aje field, can you say a little about the nearby discoveries at [ Ogo and Seme ] Have the same project difficulties any bearing on the RJ development? And what is the forward plan on at [Ogo]

So let's deal with the development in [ Benin. ] And yes, I have been reading the articles about the drilling issues that they've had on that project. And I think some of the previous wells in Aje have also experienced some of the same problems. I think the issue is an unstable shale layer in the overburden of the main reservoirs that needs to be handled with great care in drilling and it's particularly difficult for deviated drilling and that's something that we're taking account of in the drilling plan assessment that we are currently embarking on Aje. So we recognize the issue. There are technical solutions, but it does need to be handled with great care. And I think in terms of the neighboring developments and they're producing or planning to start producing oil in Benin to the to the west of us and the Ogo field to the East needs further appraisal, right? And I can't really comment on what that group's plans are for doing that. But there's clearly significant advantage here in being the first mover for gas evacuation from this area. That infrastructure -- there isn't room for multiple gas pipelines from this area to the West African gas pipeline route. So I think there are economies of scale and synergies in doing something with those neighboring developments in the future. It's not part of the base case economics that we've been looking at for Aje, but clearly, it would be a source of value for all parties going forward.

Do you still see the possibility for a payout in Guinea-Bissau?

Guinea-Bissau, as you may recall, was farmed out 100% to Apus Energy. They drilled a dry hole there. But I have plans to drill another well in the future. There are to deferred consideration payments possible in a success case for PetroNor. If there is a discovery there, then there's a payout of $30 million on the approval of a field development plan and then another $30 million on the establishment of production. So these are payments that if they happen would be some distance in the future, sometime in the future. Nonetheless, there is -- while the group has plans to drill another well, there's clearly a possibility that there could be a payout. We note that Apus Energy are also looking for partners in the acreage in Guinea-Bissau. But it's interesting that some majors have been moving into the area. Chevron have picked up acreage in that area. And so it could be that we're seeing more interest from the industry in that part of the Atlantic margin.

What's the company's legal situation? The reason why you did not get a partner in the Gambia?

I've been trying to do farm-outs around the African margin for a good deal of my career. And we can always speculate as to the reasons why the world doesn't see your prospects the same way you do and don't fall in love with them in the same way you love them. It is something that you're always looking for reasons and excuses for that. So I don't know is the answer to that question. The Gambia has, while I certainly believe in the prospectivity of it, it is -- it has had a checkered past in terms of exploration. There have been dry holes drilled elsewhere in the Gambian, the small Gambian footprint. And so it's speculation as to what has driven the lack of partners in the area for PetroNor. I certainly hope the Gambian government is successful in attracting others to the area for investment. We did try and extend our license. But in the end, we were not prepared to take on a drilling commitment at 100%. These are not cheap wells. I think the Atom 1 well in Guinea-Bissau cost over $60 million, and I didn't want that to be as a big liability on our balance sheet without a partner. So I think it was the wise decision not to commit to that, and I wish them luck in finding an operator that will come and invest for them.

Regarding the Hemla indictments, can you confirm that the indemnity agreement and the 13.88 million shares held in escrow from the 2021 Symero transaction are still fully available and sufficient to cover both the potential corporate fine and all ongoing legal defense costs?

That's quite a complicated question, and it speaks to agreements that were made some time ago. And I'm sure that any indemnities that were offered then have long since expired. So I can't address the issue of indemnities directly. What I can say is that we have sufficient funding to manage our legal costs. We're not making a provision for them, but they are, nonetheless, we have been meeting all of our obligations in terms of of legal expenses up to now. And so this is part of our planning going forward. And I can't comment any more on the Symero acquisition.

Are there any estimates on how much these court proceedings will cost the company financially and in legal fees?

We do know them in -- we have those estimates in some detail from our legal team. And we've been as I've showed you in the cash bridge earlier on, with the cost of running the company in the year last year was some $8 million. That includes all of our legal fees. It came down quite significantly when the Department of Justice decided to drop the case and the investigation in relation to their involvement. The U.S. is a more expensive legal environments to work in. We have estimates that are part of our budget going forward for the legal costs here in Norway, and they're within the numbers that you see in that bridge.

Are the indicted individuals still shareholders?

PetroNor is a public company. We don't choose our shareholders. And -- but we do have some visibility on the share register, yes, and the indicted individuals are represented on that.

Then a follow-up on the dividend. Are you communicating that there are a fair possibility that no dividend will be given in May?

Like I said, we will wait on the Board's consideration of the company's situation. And this will include our operational and financial outlook as well as the legal outlook, and we'll be making a recommendation to the AGM based on that consideration. And it's too early for me to say.

Can you say a little about industry consolidation and rightsizing the business to maximize access to capital?

We have not because of our situation, been looking at accessing capital for some time. I mean this journey started for me 4 years ago with the launch of the investigation. And I think it was made pretty clear to me that the idea of going and raising a lot of debt or raising equity in the markets was not something that would be very easy for PetroNor with this overhanging us. So I'm probably not the right person to talk about industry trends in accessing capital at the moment. It's not part of our plan. We've got a strong cash flow from our assets and no debt. So we're in a strong position and don't need -- we don't have the capital markets.

Thank you. Moving on to the final question for now. Can you comment on the separate civil lawsuit in Norwegian courts where Hemla is a defendant?

We do have other civil suit that is ongoing in Norway. We have I believe, very strong defenses that are yet to be played out in that suit. We don't see -- we've made no provision for this on the advice of our legal team who don't think that this is going to be an issue that will be successful against us. And so all I can say in terms of the progress of this is that it hasn't got to any discussion of the merits of the case or anything like that. At this stage, we are -- we're still in the very early stages of this, and we will wait to see how it plays out.

Thank you. There are no further questions. So I will now hand it back to you, Jens, for your final remarks.

Thank you. Thank you for your questions. Tough ones there as usual. So I appreciate that, though I appreciate your interest. And really, by way of summary, strong operational situation with production responding to the new wells that we drilled, growing inventory of oil for sale and entering the year with a strong balance sheet. So operationally, the company is doing well. And our focus now is on managing that, but also keeping an eye on the defense of Hemla in the hearing that starts in the fourth quarter. So thank you very much for your attention.