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Edited Transcript of BWO.OL earnings conference call or presentation 26-Nov-19 8:00am GMT

Q3 2019 BW Offshore Ltd Earnings Presentation

Oslo Jan 10, 2020 (Thomson StreetEvents) -- Edited Transcript of BW Offshore Ltd earnings conference call or presentation Tuesday, November 26, 2019 at 8:00:00am GMT

TEXT version of Transcript


Corporate Participants


* Marco Beenen

BW Offshore Limited - CEO

* Ståle Andreassen

BW Offshore Limited - CFO


Conference Call Participants


* Ivar Larsen

Arctic Securities AS - Analyst

* Terje Fatnes

SEB, Research Division - Analyst




Marco Beenen, BW Offshore Limited - CEO [1]


Okay. Good morning, welcome. Welcome at the third quarter presentation of BW Offshore. I will give you a general update and our CFO, Ståle Andreassen will bring you to more financial details. Please note our disclaimer, and then we can go to the third quarter highlights. All of these have already been communicated in the past weeks and months, actually. But I'll give you a short summary.

Anyhow, the biggest event was actually the significant oil discovery in Hibiscus. And that has -- or that allows us now to accelerate the production growth in Dussafu even faster, as we were already doing. And the other big event was the refinancing of the bonds. We have refinanced our complete bond portfolio, $300 million in convertible bonds and another NOK 100 million (sic) [NOK 900 million] in Nordic high-yield bonds. This is -- we've done it at very competitive terms and we're very pleased with it. It will give us a significant interest, cost reduction, it will also give us the financial flexibility going forward.

Our EBITDA was USD 162.1 million. This was about $30 million lower than previous quarter. But you may recall that in the previous quarter, we had a $50 million one-off upside, which we don't have this quarter.

In addition, we had to make a provision for outstanding payments from our client on -- for the Umuroa FPSO in New Zealand.

This client is in voluntary administration, and this is why we are concerned or actually, we find it quite unlikely that we will get further payments till the end of the year. And that's why we took the provision in quarter 3 of $10 million.

Then last, we had slightly lower oil price on our lifting in this quarter to BW Energy. So these factors combined created a delta of $30 million compared to last quarter. However, the operating cash flow was very good, $151.9 million. And this was mainly due to the solid operational performance we had in both the FPSO segment as well as the E&P segment.

Our highest priority is HSE. Our performance is good and I'm very pleased to see that we are now trending backwards to the level where we were on the LTIs in the past. We had a few more incidents -- a few more LTI incidents in 2018, but that is now reverting backwards in 2019.

Year-to-date, we have 4 LTIs in 2019 versus 9 in 2018. So that's going in the right direction. And you will see this 12-month statistics trending down in the next quarters.

Then over to fleet. I'm very pleased with the fleet performance. All 12 units have contributed to a very high uptime, 99.9%, so very close to 100%. And in particular, the units, Adolo and Catcher where the uptime is directly related to our revenues, this is very important. Catcher and Adolo, the 2 contributors, the 2 largest contributors, both in revenue and backlog. Catcher is still going strong, 66,000 barrels per day, [36,000] barrels above the nameplate capacity, and we capture through our excess production agreements, additional income from those barrels.

And you may have heard as well the good news from Premier that they're planning to tie in 2 more wells in 2021, the Catcher North and the Laverda. And then later on the Varadero infill well. What that means for Catcher is that the plateau production that we're operating from now will continue many more years to go. So -- and that will then add more revenue to the Catcher operation.

Adolo also a very good story. The production is stable. We're declining -- the field declines only slowly now downwards to 11,600 barrels per day. We still don't see water. So that is why we're staying on this high production.

The uptime of the FPSO is about 100% and we're currently executing modifications for the next phase in Tortue, but also after that, we will continue with modifications for Ruche Phase 1. And those modifications are investments that we capture through variation orders, and we will then roll them up in an increased day rate.

On top of that, because we increased the production on the Tortue field, and later with Ruche, we will capture more revenues through the production tariff that we have for that contract. So very good outlook for Adolo and Catcher.

Not much news for Berge Helene seas. In the yard in Keppel, we have a preservation program in place. Condition assessment is ongoing and nearly completed. And then we will wait with the modifications to start when we have an FID for Maromba.

For Umuroa, I already mentioned it. Our client is in voluntary administration, which is the New Zealand equivalent for Chapter 11. And that means that we have an exposure of about $23 million for 2019 for payments that are likely not going to happen. I already mentioned, $10 million of those $23 million, we have provided for. And then in quarter 4, we will probably miss the other $10 million to $30 million there.

In 2020, we will disconnect and demobilize. We've started preparations for this operation already. That's supposed to be covered under the contract as well. But again, quite unlikely at the moment that the client will cover that. We do -- we have discussions with the government of how to address this and see if they will take their responsibility, but these are all ongoing discussions. After we have demobilized Umuroa, we will start to prepare for a next redeployment. That brings me to the FPSO contract updates.

We had 6 units that we had to -- that we had a contract extension scheduled for. 4 of those were achieved. Then Umuroa, as just explained, was terminated or is not extended beyond the end of this year. And then we have still Pioneer to complete. Pioneer is progressing. We are discussing a 5-year agreement with possible options beyond that. Aim is to conclude this all before the end of the year. But that's going fast. So it may well that -- it may well be that this moves on to the next quarter. It's difficult for us to decide on the timelines of our client, but the discussions are progressing. And in any case, there is a hard deadline by April next year.

Production is going very well in -- on the Cascade Chinook field. So it's a quite unlikely scenario that that will suddenly stop. We have also agreed to 1-year extension terms. So in any case, we'll find a solution to continue next year.

Then Umuroa is now a candidate for redeployment, just like we've done with Adolo and as we are planning with Helene. Similar to those units, this is a very flexible unit. In addition, this one is [too remote], which makes her even more easy to redeploy as she is designed for more harsh environments as well. And she is in a good condition. So sufficient deck space, so it's quite a flexible unit that we can use for our next field development, together with a redeployment of our own asset.

Athena is a more difficult story because that's a particular kind of niche FPSO, and that's why that is more difficult, and just takes longer, but Umuroa is very different. It's much more like an Adolo and Helene. So it's -- it does create a clear opportunity for a new field divestment as well.

That brings me to the contract overview. A familiar picture, I think. You see on the top, Catcher and Adolo, the main contributors. And then further down the lower part of the page, you see all the units where they are sitting in the face of the contract where we have 1-year extensions. So there's a rolling extension typically year after year. And history has shown that because the field still performs, this is kind of a mechanical process. Exception, of course, Umuroa as just discussed and Pioneer, who -- where the contract will just end. But we will probably soon be able to announce a new dark green and light green period with firm and option periods for that unit.

Vicente is a unit that we do expect an extension for next year, but that may not continue too long after that probably.

Then E&P. A bit more about Hibiscus. This is the fifth consecutive discovery so we have 5 out of 5 in the Dussafu license, which is exceptionally good. The discovery was made in the Gamba formation and the Gamba formation is the same formation as were one of the 2 Tortue wells that we're producing currently from producers. So that's a very good formation, a very productive formation. And the total volume of this discovery is about the same as Tortue. To be more precise, it's about 45.4 million barrels.

So -- and that is constructed by a hydrocarbon column of about 33 meters and good porosity between 21% and 23%. So this is a very exciting field. And obviously, we want to produce as soon as possible from this discovery. So we've decided to change our Ruche development plan by including now our -- this Hibiscus discovery. So it will be a combined production from both Hibiscus and the Ruche field. And that is what you see in this picture.

So you see here Ruche, here Hibiscus, originally, we had the platform planned somewhere here. We moved it a bit northwest 4 kilometers further out such that we can produce from 4 Hibiscus wells and then 2 Ruche wells in Phase 1. And then we add another 6 wells later in Phase 2 of Ruche. We'll use a wellhead platform with 12-well slots, and we tie that back with a pipeline to FPSO Adolo.

We have just taken FID for this project. That will have a CapEx of about $45 million, and that is excluding the FPSO, the investment on the FPSOs will be covered to roll up in the day rate. This $445 million will be largely funded through the operating cash flow we generate from the Tortue field. We expect -- about quarter 4, 2021, we expect the first oil from this discovery. And that will then increase the production with 30,000 barrels per day. Previous plan was 15,000 barrels per day prior to Hibiscus discovery. So now we're able to double that and go a lot faster.

With that increase of the production, our OpEx per barrel will decrease to about $10 where today, it's around $20. So we're very excited about this development, of course. And you see here on the right side of this page, you see the growth of reserves we have been able to achieve since year-end 2017. So since 2 years ago, 375% growth by Tortue, Ruche and the Hibiscus discovery together. And this is confirmed by the third-party Netherland, Sewell.

Back to Tortue. Today, the 2 wells we have in Tortue Phase 1. We're producing about 11,600 barrels per day. And we've -- we have produced 1.1 million barrels of oil in this quarter, one lifting and still no water cut in this quarter.

OpEx have gone up slightly to $21 per barrel, and that's just because the production declines slightly. The full year forecast is now 4.2 million barrels gross. Then with the Tortue Phase 2 where we bring in 2 more wells first in next quarter and then 2 other wells the quarter after that, our full year forecast will be in the range of 6.3 million to 7.9 million barrels. So a significant increase compared to this year.

Further good news is that we have signed a new oil offtake agreement with BP Oil International. It's attractive agreement. It will be effective from December 1. And instead of the discounted brand we have today, we will then capture a premium.

And then on the bottom, you see the planned lifting schedule. So this quarter, we will have 2 more liftings, which will result in an increase compared to this quarter. And then quarter 1, we will go down to one lifting. That's also related to a short shutdown we need to tie-in for risers in -- tie-in the risers in the first quarter to bring Phase 2 online. And then after that, we continue with 2 liftings per quarter and then finishing the year with 3 liftings.

Phase 2 is on schedule. I already said we will have first oil next quarter. We're on schedule to achieve that even though our drilling campaign has been slightly delayed because of the success of Hibiscus. We decided to do an additional sidetrack well because of the success of the first well. That was obviously well-spent time and money given the success we achieved with that. We're now pressing on full ahead with the production drilling campaign of the 4 wells, which is progressing well, and we will still make the first oil in the quarter. And then the second quarter, we'll bring in the other 2 wells.

FPSO modifications are going well and were also within the budget that we have for this project, which is $240 million, which excludes the $30 million of the modifications on the FPSO, again, rolled up in the day rate of Adolo. And it also excludes the exploration drilling.

You see the summary then of the Dussafu developments. So 2019, here this is what we're doing today, then Phase 2 comes online in 2020 -- first half of 2020. And then we're working towards Ruche Phase 1, adding another 30,000 barrels per day after that. And then in Phase 1, and then we move on with Phase 2. And as you see, we're reaching the maximum capacity of the Adolo FPSO, which is actually a good news obviously. And we have already made studies that we think we can -- it's not a big problem to debottleneck the capacity of the FPSO. So if needed, we can bring in even beyond the capacity of the FPSO.

Then Maromba, there's not so much news from Maromba. We -- most of it has been communicated already. We are on track with the Field Development Plan to submit the plan to ANP before year-end. And then we will work through a couple of iterations as that is normal with them to a final concept selection, probably midyear. And then realistically, it probably takes towards the end of the year before we have the approval. And then the project will kick off in full, preparing for first oil 2 years later, end of 2020. So this is a slight shift of what we said earlier, but it is mainly driven by the reality of how these approval processes work in Brazil.

In the meantime, we're pressing full ahead with Dussafu and increasing our production faster as planned there. So overall, we're growing as planned. The structure, the group structure of BW Energy is now completed. So we brought in all E&P assets under one entity, meaning Dussafu, Maromba and Kudu. We're also progressing on the RBL. Commitments are expected now in December and that will allow us to get the facility available in the next quarter. And then in the meantime, we're still working on the listing. We have to update, of course, all the good news we had in the past quarter.

In the meantime, it's fair to say that we didn't feel the market was there in 2019 to do an attractive listing. So we will move this now to next quarter in 2020. And hopefully, we'll see a market then that makes it attractive to list. Then finance over to Ståle.


Ståle Andreassen, BW Offshore Limited - CFO [2]


Thank you, Marco. Good morning, everyone. I'll start with some overall consolidated income statement highlights. As you can see from the screen, operating revenues for the combined business was $267 million last -- or this quarter. Somewhat down if you compare it to what was a very good first quarter.

EBITDA was $162 million this quarter, also somewhat down compared to second quarter. And EBIT for the combined business was $66 million in Q3. And let me just state sort of before I continue on to segment is mentioned that we did release a preliminary trading update for Q3 like on 5th of November. And there is no changes to the figures being released today as compared to what was released in that update.

Taking a look at the income statement for the FPSO segment. We delivered $238 million in operating revenue for the quarter and we delivered an EBITDA of $133 million. The -- as Marco mentioned earlier, the results were affected by the provision we had to make due to the uncertainty when it comes to the situation with the client Tamarind for the lease of the FPSO Umuroa. So we took $10 million as a provision for third quarter.

And as you also could see in some of the -- on one of the previous slides, we do expect that there's a risk of nonrecoverability also in Q4 for -- on any payments from the client. The way we will basically do it and the reason we haven't made the full provision for this in 3Q is that effectively we'll just recognize any revenues in Q4 under that contract. Although we will, of course, continue to invoice the client as per the contract.

EBIT was $46 million for the quarter. Depreciations were kind of more or less in line with second quarter. So given what I've said, that came out sort of within our expectations.

Moving on to the E&P segment. Operating revenues were $50 million for third quarter. We had one lifting, 591,000 barrels, with an achieved price of $61.3 per barrel. So of course, if you compare that was lower than we achieved for the one lifting we had in the second, second quarter. And also worth to highlight here because we do see that someone finds it little bit difficult to follow us in terms of revenues when you look at lifting and oil price achieved.

Bear in mind that the taxes that we pay under -- to the government, they are basically being listed in kind. And as such, our revenues will be grossed up every quarter with the taxes we pay to the government. And at the same time, expense -- as a tax expense -- on the tax expenses in our income statement. So for third quarter, there is a roughly $10 million add on to operating revenues that basically reflects the taxes we pay to the government there. So hopefully, that makes it a little bit easier to reconcile overall revenues when we mention lifting and oil price.

EBITDA for the third quarter was $35 million. As Marco mentioned, a slight uptick on the OpEx per barrel, but more or less as expected. EBIT was $21 million for the quarter. As you can see, if you compare to second quarter, more or less in line. So depreciations from 3Q onwards was lower. The reason for that is that we got a midyear update on reserves related to Tortue. And this confirms more reserves than we had in our previous estimates, which basically allow us to reduce the depreciation per barrel going forward, based on more reserves for the same amount of CapEx.

Back to the overall income statement, and I'll only mention those items that I haven't covered already. Interest expenses, $19.6 million, slightly lower than second quarter, but more or less as expected. And again, we had losses on our interest rate hedges. We had overall net losses of $12.8 million for the quarter, predominantly, all of this coming from the fact that you have negative mark-to-market adjustment on hedges due to the continuing kind of decline on U.S. dollar stock rates. So it is a non-cash event. But despite that, affecting our results quite heavily, again, as in previous quarter.

Profit before tax was $33.3 million. Income tax was $23.8 million, more or less in line with the previous quarter, and net profit was $9.5 million for the quarter overall. Again, we're pleased to see that our debt and the leverage ratio is kind of trending in the right direction. Net debt was standing at just below $1 billion end of Q3. And the leverage ratio has been dropping further to 1.4.

Worth noting that we use last 12 months reported EBITDA for this, it's a lagging indicator, showing that increasing our EBITDA has also been a factor in increasing our debt servicing capacity quite significantly. Our equity ratio stood at 40.8% at end of the quarter.

Looking at the cash flow. We started the quarter with $265 million. We delivered $152 million in operating cash flow from the fleet and the E&P segment, so very pleased with the contribution there. We spent $73 million on our E&P segment, $30 million is linked to the first milestone payment for the Brazil acquisition of our field. The remaining is spend linked to drilling of the Hibiscus update main well and sidetrack as well as getting the field ready for Tortue Phase 2. We spent $21 million on our FPSO fleet. A large part of this is linked to Adolo and the modifications being undertaken to get ready for tie-in on Tortue and the rest is ongoing LAT.

We paid $34 million in scheduled debt installments. We didn't draw any new debt. As you can see, we paid $21 million on interest and $9 million to noncontrolling interest, leaving us with $260 million in cash end of the quarter. Then -- but of course, you can see at the bottom here with $272 million undrawn on our corporate facility. We have $532 million in total liquidity at the end of Q3. And post Q3, we've been rather busy with a number of financing initiatives, as you can see.

We -- in November, we completed a 5-year convertible bond. It's the company's first. We raised $297.4 million through this bond issue. All-in coupon was 2.5%. And the conversion premium on the bond is USD 10.24, which is equivalent to 37.5% above volume-weighted average price on the share on the day of the launch.

We're quite pleased with the transaction as such. It was a transaction that enabled the company to address a large part of the existing bond portfolio in one transaction. And that was key to us. As we saw, that's quite a challenging task to be able to address $400 million in existing Nordic high-yield bonds and roll those over. It will -- it would either take us quite a long time or we have to look at alternatives.

And overall, looking at the outcome, where we're quite pleased with the outcome. Of course, we also recognize that doing convertible is a different instrument, it's not straight debt. It comes to the price in terms of conversion. But we think, as a company, it does provide us with good downside protection, a very cheap debt in a long-term bearish scenario, which is not to be taken too lightly on. And in an upside case, we do understand that there will be a dilution on the share, but altogether, that will remove $300 million from your debt if so.

Later in November, we did another straight bond. We raised NOK 900 million in the Nordic high-yield market. Terms on this one was NIBOR plus 450 basis points. And the bond has a 4-year tenure, as you can see on the slide. We have later decided that we want to hedge this. So we have hedged this to U.S. dollar, and we have fixed the interest rate at approximately 6.3% all-in. I'll come back to this on the next slide. I have another slide to show you, but -- so come back to the bond refinancing.

On the RBL and the financing for the ANP segment, we have had pretty good progress in the quarter. It's been a long process. It's been a complicated facility to put in place, but we're now seeing that we are getting towards getting a commitment. We expect to have this by end of the year for the facility. And we do expect to have the facility ready for drawing on from first quarter 2020. That is pretty good in terms of timing. It allows us to have availability on the facility in place, kind of with a good fit in terms of cash needs for further development activities on Dussafu.

And in due course, we will also be addressing financing for Berge Helene and the modifications we need to do for our Brazil development. We haven't kick-started this project in full yet. We will do that only as we get close to FID on the project, and we have a contract in place between us and BW Energy in this case. And we do intend to use the uncommitted accordion, which we have mentioned before for this financing.

Taking a look at the debt profile, and referring back to what I said about the bonds. We have tried to illustrate here on the right-hand side, how we see our debt portfolio looks like post refinancing. As you can see, the 2 bonds we have done have effectively allowed us to replace all existing high-yield bonds, BWO01 to 04 and replace them with 2 new bonds with longer tenure, maturing in '23 and '24.

Overall, it's an exercise that allowed us and given the company more financial flexibility. And obviously, the same people are -- want to hear this, and that is it is driven by the fact that we want to put the company in a position where we are enabled to restart dividends from 2020. Although, again, I want to point out, we really want to focus on the 2 other key things, and that's a closer RBL and also to successfully launch BW Energy as a separate company before that kicks in.

And finally, the backlog, as you can see, the FPSO backlog continues to be steady and provide good visibility on our future revenues. It's reduced slightly to 5.8%, which is kind of natural depletion from revenues being earned in Q3.

And on the E&P side, we continue to add reserves and resources to our portfolio. We have -- with the successful discovery on Hibiscus, we've been able to increase our overall reserve estimate to $248 million by end of Q3.

And with that, I'll hand it back to Marco for outlook and sum it up.


Marco Beenen, BW Offshore Limited - CEO [3]


Okay. Thank you, Ståle. Yes, concluding with outlook. We remain focused on our strategic priority and we are on track to deliver those. The FPSO backlog remains the foundation of our strategy. It provides the long-term cash flow visibility. And with the current oil price and the fluctuations we see, there is no concerns about extensions we have seen in the past that even with much lower oil prices, we are able with the fields where we're operating, it makes economic sense to continue to extend these units.

We remain also selective on bidding new FPSO projects. But the market is tightening. There's -- many competitors have signed up contracts in the past year while there is still a growing demand for new FPSO. So that obviously creates opportunities, and we're looking at a couple of those. It's a bit too far from FID to really be specific, but it is a more interesting market developing there for us.

Focus stays on redeployments with field developments. And the first priority is really to grow the production on Dussafu, bringing on Ruche online Ruche and including the Hibiscus in the 2 phases as shown. The refinancing of the bonds, as very well explained by Ståle, obviously, creates -- or increases our financial flexibility. And that will also help probably with finding the right way to list BW Energy.

Then on the event guidance, most of these things we have discussed. Hibiscus, Ruche, FID, the Tortue production drilling, Maromba submittal to ANP. Kudu license is ongoing. This is a project where we have governmental partners and that makes it a bit complex to go in a fast pace of development. We have to make many iterations, but we will continue to work those issues.

And we expect to also conclude the agreement with Tullow on their back into the gateway for Dussafu. On the FPSO side, I haven't mentioned yet the -- we did talk about Umuroa and Pioneer and the upgrades on Adolo. Cidade de São Mateus, unfortunately, no real news. Other than that Petrobras is progressing in their approval process. However, they have not been able to conclude it in the time frame they indicated earlier, which was November.

I think this will probably move into next quarter as well. But what I can say is that I think what we see is that this is progressing and is going into a conclusion at one point. It's just very difficult to say what the exact timing is.

Then for next year, 3 extensions planned in the first half and one more extension in the second half. So Abo, Polvo more or less mechanical. Vicente, is we do expect at least one more extension during next year. And then in the second half, Petróleo Nautipa. It's also considered more a mechanical extension where the production is such that it is very unlikely that that contract would not be extended. So it will be a rollover. And then starting the project on Berge Helene with a redeployment contract with BW Energy.

On E&P, then next year, 2020. So the RBL we talked about, the IPO, we have talked about, the Tortue production drilling campaign is ongoing until first oil in the first quarter. And then we will spud a second exploration well. We haven't decided yet exactly where that decision will be taken in January, but we will do one more exploration well after we've completed the production drilling on Tortue.

And then in the second half of 2020 towards the end, we will start the Maromba projects, and we will do some exploration wells in Dussafu. We have an option for 2 more exploration wells and that will take place somewhere in the second half. We'll take those decisions in the first half of 2020.

That concludes this presentation, but I would be very happy to take any questions.


Questions and Answers


Unidentified Analyst [1]


Can you give us a little bit of an idea about the likely decommissioning costs for [your] next year?


Marco Beenen, BW Offshore Limited - CEO [2]


Yes. The -- so there's a couple of aspects in the decommissioning cost. The key contributor is the installation vessels and we haven't locked them in yet. And a lot depends on because it's New Zealand on whether you contract vessels in the area or you have to demobilize. So that gives quite a spread on the cost. The other uncertainty is to what extent the government will take responsibility as well for compensating these costs. But roughly, it will be somewhere between $15 million and $20 million by the time we're in Singapore.

Okay. Other questions? All clear? One more.


Terje Fatnes, SEB, Research Division - Analyst [3]


Terje Fatnes from SEB. So question on Maromba. Can you explain a little bit why the production start is later? And then what are the key issues that you are discussing and considering there?


Marco Beenen, BW Offshore Limited - CEO [4]


Yes. Well, there's nothing really, in particular, it's just that we realize that the approval processes with governmental bodies will take a bit longer than we originally anticipated. So we're on track developing or submitting our plan. We just think it will probably take a year to work through everything. So I'll get more towards the end of next year rather than being ready in mid next year.


Terje Fatnes, SEB, Research Division - Analyst [5]


And second question, will you, at some point, the time disclose emission from that field, since it is quite a big topic in the investor market?


Marco Beenen, BW Offshore Limited - CEO [6]


Yes, we are reporting emissions already of our fleet and operations.


Terje Fatnes, SEB, Research Division - Analyst [7]


I was talking more about the Maromba field. Since it is heavy oil, there is obviously a higher emission from that field than light oil field.


Marco Beenen, BW Offshore Limited - CEO [8]


Yes. No, I expect we will just include reporting as we do -- as we currently do with all our operations. There's no reason to exclude Maromba from that. Okay. Thank you very much. One more, I'm sorry. I'm sorry.


Ivar Larsen, Arctic Securities AS - Analyst [9]


Ivar Larsen from Arctic. Could you shed some light on the timing of the listing of BW Energy? You have a clear peer, Panoro, listed at the Oslo Stock Exchange, which is trading at or close to all-time high. What's keeping you from listing now? There hasn't been any better periods previously?


Marco Beenen, BW Offshore Limited - CEO [10]


Do you want to answer?


Ståle Andreassen, BW Offshore Limited - CFO [11]


Well, it's -- it is a good question, though. It's nothing kind of technical that prevents us from the listing. We just don't see the market being there, being able to pay the price that we need for a transaction. It is as simple as that. When we see the right market window, we want to pass on to go for a listing there. And yes, we do observe exactly the fact that you're raising there, and that is that peers star trading at a higher multiple than what we are seeing as implicit pricing when you look at BW Energy as part of BWO.


Marco Beenen, BW Offshore Limited - CEO [12]


We added a lot of value, again, in BW Energy through the discovery of Hibiscus, and I think it's important that this value gets recognized. So we need to have the right market to get this recognition.

Okay, then. Thank you very much.