BW Offshore Limited (BWO) Earnings Call Transcript & Summary

Ladies and gentlemen, thank you for standing by. I am Emma, your Chorus Call operator. Welcome and thank you for joining the BW Offshore conference call. [Operator Instructions] I would now like to turn the conference over to Marco Beenen, CEO. Please go ahead.

Good morning and welcome to the third quarter 2020 presentation of BW Offshore. In this call, I will give a general update, and our CFO, Ståle Andreassen, will cover the financial results. Moving to the next slide, our disclaimer. Please take note. And then moving on to highlights on Slide 3. The third quarter was a challenging quarter from an operational perspective, with both the Yùum K’ak’ Náab and the Sendje Berge FPSO experiencing shutdowns, and that impacted our commercial uptime and financial results somewhat. Our EBITDA of USD 98 million and our operating cash flow of USD 82 million were, therefore, a bit lower than previous quarter. But this is also further explained by a one-off settlement of $8 million that we had in Q2 and [ no sets one-off ] revenues occurred in quarter 3. As expected, we received confirmation of a contract extension of Petróleo Nautipa until September '22. And furthermore, we reached an agreement with the New Zealand government for a fully funded stay and demobilization out of New Zealand, and this will reverse our voluntary liquidation. During the quarter, we were able to progress various tenders to -- for new projects. And last but not least, the Board of BW Offshore has approved a quarterly dividend as part of the annual $25 million cash dividend program. Moving to Slide 4 with an update on COVID. As you are all well aware, the COVID-19 situation globally is not improving, and it requires proactive risk management, planning and procedures to manage the operational impact. However, we are pleased that there were no new FPSO outbreak since our quarter 2 reporting. However, the situation remains challenging, in particular, in relation to crude logistics. It doesn't come without cost. The managing COVID costs has cost us about $4 million per month in this quarter. However, with full implementation of PCR testing protocols as well as improvement in the flight availability in several countries, this is now reducing to about $2 million per month towards the year-end and going forward. Then operational update on Slide 6. On the right side, you see the HSE statistics, with average ratios per million man-hours over the last 12 months. This is in accordance with the IOGP definitions. We're striving for zero harm. And the most important metric to achieve this is the orange line, which represents the high potential incidents, and that's trending downwards in a satisfactory rate. The left side of the chart shows the fleet uptime, commercial uptime, and displays the dip that is caused by the instruments on Sendje Berge and Yùum K’ak’ Náab, okay, as I just explained. Then moving to Slide 8 (sic) [ Slide 7 ] with further updates on some of the units. First of all, Catcher, our operation in the U.K. While the production was impacted by the need to remove calcium naphthenate from the produced water systems, our commercial uptime was not impacted as [ discount has company underproduction ]. It does, however, prevent us to capture benefits from excess production. We're working closely with our client Premier Oil to optimize the management of this issue and to avoid or at least reduce downtimes in connection to this. Furthermore, it's worthwhile to refer to earlier announcements made by Premier about their merger with Chrysaor. And this merger creates the largest London-listed independent oil and gas company, and that obviously strengthens the Catcher-field operator's financial position. Already mentioned Petróleo Nautipa with the contract extension. And Sendje Berge is now backing production again since mid-October. Also mentioned Umuroa. So we're very pleased with the recent agreement we made with the Ministry of Business, Innovation and Employment in New Zealand. That will now cover all our costs until departure from New Zealand. And then Vicente, the contract was ended in quarter 3, and we consider it now for redeployment or recycling in 2021. Moving on to Slide 8, BW Energy. Our associated company doing the field developments in Gabon and Brazil. We're looking forward to restart Dussafu development activities as soon as the -- COVID's restrictions are lifted. In the meantime, the opportunities in the downturn caused by COVID has been captured to acquisition of jack-up platforms rather than using newbuild hull platforms for the Hibiscus and Ruche developments. And this is expected to reduce development costs with about $100 million, and it will also reduce time to first oil as well as the environmental impact of construction. The strategy of joint value creation to FPSO redeployments allowing for short cycle and phased developments remains unchanged. We just have some delays in -- due to COVID in executing those plans. The operations in Dussafu are still strong. Current production levels are around 14,000 barrels per day, with an average operating cost of USD 19 per barrel. And to our 39% ownership, current value in BW Offshore is about NOK 11 per BWO share. That brings me to the fleet contract overview on Slide 9. What is worth noting is Petróleo Nautipa beyond 2022, we're having discussions with our client, VAALCO, to enter into a new contract beyond that. Although expected to come off contract mid-'21 and we consider her as a very good candidate for the Maromba field development by BW Energy. And then Abo, further down, discussions are ongoing for further extension. This is a situation we are facing every year, and I find it quite likely that this contract will further extend beyond the end of this year. Moving to the next slide, Slide 10. Our solid backlog provides long-term financial visibility. We have a total backlog of about USD 4.2 billion by the end of Q3. Firm backlog is about USD 2.6 billion, and 80% of that backlog is delivered to the 3 main units we have in the fleet, and that is Catcher, Pioneer and Adolo. And again, the Catcher partnership operated by Premier Oil is the largest customer. And I mentioned the merger with Chrysaor would significantly strengthen the balance sheet of that counterparty. And with that, I give over to Ståle Andreassen to run us through the financial results.

Yes. And thank you, Marco. Then we move to Slide 12. And as usual, we started with an overview of the key financial figures as well for the quarter. As you can see, and as also earlier mentioned, we achieved an EBITDA contribution from our operations of $98 million in Q3. It is a reduction of about 15% from what was achieved in the second quarter. Firstly, we did expect Q3 to come in somewhat lower than the second quarter as a result of the $1 million positive one-off settlement we received in the second quarter for the outstanding claims related to the former project for FPSO P-63. We have -- as Marco mentioned earlier, we had some downtime on Yùum K’ak’ Náab. The units operating for Pemex was hit by a tanker during offloading, and this led to approximately 1 month shutdown of the unit. We have not been paid by Pemex for this period. And although we are disputing this, we have not recognized any revenues for the quarter, and this has impacted our EBITDA negatively. On top of this, we continue to battle with COVID. We are investing quite highly to manage COVID costs related to crude [ and related ], which has an impact on our results for the quarter. When you look at the revenues, it's mainly reduced due to the 2 items I mentioned before, the settlement we had in Q2 and then the downtime we had for YKN Q3. Moving on to Slide 13. As you can see, depreciations were pretty much similar to previous quarter at USD 63 million. This overall gave us an EBIT or operating result of USD 35.1 million for the quarter. Net interest expenses came in at USD 13.2 million, which is down from USD 15.2 million in Q2. This was as expected as we continue to amortize on our debt. And also, as we have done an additional repayment on the corporate facility in Q3, reducing our gross debt and, consequently, also some debt interest expense. We have a gain on financial instruments of USD 8.3 million in the quarter. This came as a result of positive mark-to-market adjustment on our FX hedges as well as our interest rate swaps as both U.S. dollar as currency has strengthened against the NOK, and also as we see U.S. dollar swap rates have increased quarter-on-quarter. Other financial items were negative by USD 3.3 million, and this is predominantly due to revaluation of our Nordic high-yield bond, which is denominated in NOK. But -- and as we see, the Norwegian krone has strengthened against U.S. dollar in the quarter, we'll have to take a mark-to-market loss on that. And note, any negative effect from valuation or revaluation of the Nordic high-yield bond will have a positive effect on their -- on financial instruments as the loan's -- it's fully hedged. But for presentation purposes, we have to show this on 2 separate lines. We recorded a loss from equity accounted investments of USD 4.7 million during Q3. This is coming from BWO's 38.8% net share of the results from our investment in BW Energy. Income tax expense was USD 7.6 million for the quarter, more or less in line with our expectations and within ordinary fluctuations quarter-on-quarter. And overall, we had a net profit at USD 14.6 million for quarter 3. Moving on to Slide 14 and the cash flow overview. As you can see, we started the quarter with a total cash position of USD 206 million. Operating cash flow was USD 82 million for the quarter. This was slightly behind our target. And although we had a reasonably steady quarter, our cash flow was affected by the incident on YKN, and we also see that we had a higher cash outflow as we've been building some working capital, buying additional spares and building on our inventory due to higher maintenance activity on the FPSO fleet. And just worth mentioning, if you compare operating cash flow this quarter to second quarter, which was roughly USD 120 million, it's important to remember we did receive a one-off settlement from Petrobas in Q2. And another thing in Q2 was that we received back -- sorry, USD 17.5 million related to cash collateral, which we had put up in Q1 due to extreme FX movements we saw where the U.S. dollar strengthened significantly against NOK, and this required us to put up some cash collateral on our hedging instruments. But due to the reversal of the U.S. dollar versus NOK in the second quarter, this was all received back. So it's just important to note that there was a one-off movement in Q2 that gives an artificially high variance quarter-on-quarter. We did spend USD 10 million on maintenance CapEx on fleet and some other investments related to some pre-FID activities we're performing, which overall gave a total free cash flow of USD 72 million for the quarter. We reduced our debt position quite significantly in Q3, USD 35 million of a total of 109 was scheduled installments on the Catcher and PNA facilities. The remaining USD 75 million was a one-off repayment we did on the corporate facility. We have a quite large cash position at the beginning of the quarter, and we used this to trim our balance sheet by repaying on the revolver, which will reduce our interest cost going forward, but which retains our liquidity as the revolver -- the down payment just decreases our available draw on the revolver. We paid USD 12 million in interest on our facilities. We continue to pay dividends with USD 6 million paid also in Q3. And we paid $8 million in relation to the preference share agreement we have for Catcher. So total, we ended the quarter with USD 142 million in cash. Moving on to Slide #15. And as you can see, there's no surprises when it comes to the financial position of the company and shouldn't be as key units in the feed are on long-term contracts and results are relatively steady. We did continue to reduce our net debt, which stood at USD 976 million by end of Q3. The leverage ratio continued to trend more or less flat. It stood at 2.1x the last 12 months reported EBITDA for the quarter. And I want to say, although this has trended flat, we expect it to continue to trend in a downwards trajection as we continue to deleverage and amortize off our debt as we go. The equity ratio increased by 1.7% in the quarter to 37.5%. And although there is a positive effect from the net result this quarter, the main impact is coming from the reduction in our cash position as we repaid on corporate loan facility and effectively reducing gross debt and the balance sheet, [ therefore ]. Moving to Slide #16. It's a well-known slide. We have shown this before. And again, we want to emphasize that with this, we -- as you can see, we have no major debt maturities before late 2023. We have refinanced all our capital market debt late 2019, and that gives us flexibility from a balance sheet point of view. We continue to amortize on our debt, as I mentioned on the previous slide. We are amortizing approximately USD 120 million per annum for the next couple of years, while this will gradually increase as we get into 2023. Overall, it does give us ample time to plan our financing needs and also flexibility for any opportunities that comes around. Going to Slide 17. We have basically 2 priorities: one being to maintain financial flexibility towards any growth opportunities, while the second one being providing flexibility -- sorry, providing predictability when it comes to returning value to our shareholders. As you've seen on the previous slide, we continue to deleverage as long as we have no new projects. We have a strong liquidity. We have almost USD 390 million in available liquidity when you're adding together available credit lines and cash. As mentioned earlier, we continue to incur costs related to COVID. However, as Marco mentioned earlier, we do expect that we will be able to drive down the cost of this going forward, reduce it by approximately 50% as we can do our own PCR testing and as we see borders opening, which allows us to more effectively move personnel. On fleet, we see limited CapEx on the -- sorry, on the existing fleet. That we think will continue both for the remaining part of 2020 and also throughout 2021. Overall, we are predicting CapEx to be in the range of USD 25 million, and that includes any investment in BW opportunity. We now come to the point where we have been able to conclude on termination for the contract for Cidade de São Mateus, which was this unit operating for Petrobas. The settlement for this has been more or less final for quite some time, and we have fully provided for any payments here. As we expect now, all formalities to be closed relatively shorter -- shortly. We want to highlight this settlement and our planned payment of USD 40 million, which we have estimated to be paid in early 2021. As I said, it will not have an impact on our P&L, but it will have a liquidity impact of USD 40 million. And when it comes to shareholder returns, again, as mentioned before, we will continue to pay a quarterly dividend, as I've said. But we want to emphasize again, when you look at year-to-date, when you add up the BW Energy shares that we did in kind in the first quarter this year, the share buyback program that we executed in Q2 and dividends paid so far this year, plus plant paid now in Q4, we will have returned almost USD 130 million back to our shareholders in 2020. And we believe this stand a strong commitment to returning value to shareholders. So with that, I'll hand it back to Marco for strategy and outlook.

Yes. Thank you, Ståle. I will now provide an update on strategy and outlook. Moving to Slide 19. We continue to capture the value from the existing fleets to the extensions on the fields where we operate and also through redeployment of units, which are available, ideally with BW Energy. This segment, the redeployment is, however, a bit slow given the low oil price environment we're currently in. We expect this will rebound when the oil price recovers. But in addition to that, we are selectively pursuing new projects with leading E&P companies. And we're currently focusing on Australia and Americas, and we're progressing well to be able to take an FID during 2021. Moving to the next slide, which will explain a bit more about these investments. We're aimed to build new and different type of backlog, which is based on firm contracts of 15 years plus options, which excludes residual value risks. And it means we're targeting infrastructure-like projects with investment-grade counterparties, and that enables us to secure equity partners preconstruction. So for the benefit of the doubt, there's no need and no intention to raise equity in the markets to be able to undertake such investments. The type of new project backlog will need strict investment criteria, which is a 15% return on equity, which needs to be met during the firm period of the contract. That ensures access to competitive financing. We have received positive feedback so far from extensive sounding with banks and equity partners for the prospects that we are currently looking at. And we minimize project execution risk to basically replicating the success factors of the Catcher Chrysaor delivery using the same team, leveraging our experienced project execution organization and also working with known suppliers and yards using our existing relationships and experiences. We also want to use the RapidFramework newbuild hull concepts, which we have developed during peaks in the past years. With that, I'll move to summary, last slide, Slide 20 -- sorry, Slide 21. We continue to manage the COVID-19 pandemic proactively as the situation lingers, but we also expect that this will improve during 2021. Protecting our people and operations remains the priority. We continue to deliver stable EBITDA performance, and that provides strong operational cash flow as well as requires financial flexibility. We target a new FID in 2021, and we're also looking at energy transition opportunities where we can apply our offshore engineering and operations competence. With that, I would like to conclude this third quarter update, and we would be happy to take any questions.

[Operator Instructions] The first question comes from the line of Frederik Lunde from Carnegie.

I was curious on -- when you mentioned talking -- taking in partners. Do they come in as the sort of equal partners [ publishing equity risk open ] upside and downside in any projects?

Yes. Thank you, Frederik. I can answer this question. No. Typically, those partners will not take EPC risk but will provide equity during the EPC phase.

So then it's sort of cost [ ordering ] or delays which would be at your risk that they would provide liquidity? Is that the way to think about it during the construction?

Yes. So we are responsible for the EPCI delivery of the project. But as I said, we're -- you can say we're kind of derisking that because there is, of course, a profit element in the EPCI phase.

Okay. Great. And then I just did some calculations here, looking at the company since listing in 2006. And on my numbers, return on equity has averaged negative 3%. And I think accumulated EBITDA is about negative $500 million. So investors are obviously spooked by the prospects of new conversions that has typically increased risk historically. But then obviously, the market is not difficult. There's probably no pressure on the supply chain. Both suppliers and shipyards at ample capacity. So we could say risk reward looks better. But then again, if you look at investing in your own shares, I calculated that cost of capital 19%, which will have, obviously, much less risk as well than taking on new conversion. So just curious to what extent actually hold up investing or evaluate and investing in more buybacks versus any projects? Do you see the totally different investment decisions? Or do you see them as sort of equal opportunities?

Well, I think as Ståle explained, where need -- we need to strike a balance here. And we do see a very good window of opportunity for -- in the coming years, a couple of projects, but hopefully, at least one in 2021, where we can make new investments with better returns than what you explained we have had in the past. And the main reasons for that is that we are now at a time where also strong counterparties, major oil companies are finding [ the lease-op results ] for long-term contracts, 15 years and beyond, interesting. And that was typically not the case in the past where the lease and operate model, we were kind of forced to take residual value and residual risk. So -- and that window is now. So both on the demand side, there's a window of opportunity. And also, in a way, on the supply side, there is, one can say, constraint because most of the active competition is pretty occupied already. So we think we're in the right window to deliver the returns on investments on those new projects in this window. And then we need to be a bit careful with how much money of our -- or how much of our capital we allocate to share buyback or cash dividend. We are, however, committed to sustain the dividend level that we have today in any case. And we also feel that in 2020, we actually have, as Ståle also showed, delivered to the promise to return to shareholders. But it is a balance, and I think that your topics are absolutely valid. And we will continuously monitor and strike that balance. But as we think there will be some investments coming, I think we have to be a bit careful with how much we [ protend ] and how much capital we allocate to immediate returns.

[Operator Instructions] At this time, it appears there are no further telephone questions. I hand over to the speakers for any questions from the webcast.

Okay. Thank you. Yes, we have some questions that come in via the web. First question here is from Magnus Olsvik from Kepler Cheuvreux. "On COVID cost, are you able to pass some of that over to the client? Or do we cover all the costs ourselves?" Marco, that's probably a question for you to...

Yes. And it's relatively simple. We can only recover when we have reimbursable contracts. On the contracts where we have fixed operating and maintenance costs, we're, of course, trying to push this back on our clients considering COVID has quite an exceptional circumstance. But you -- I'm sure you realize that the clients are also putting a lot of pressure on us to kind of reduce our rates in view of the low oil price they're facing and putting their revenues under pressure. So this is a bit of a -- yes, arm-twisting both ways. So we cannot -- of course, we cannot reduce our rates in view of low oil price. But equally, that reduces the willingness of our clients to contribute to COVID costs. It is important that we protect our revenues as we have been doing, as you can -- have seen. And at least now, we're seeing that with -- to a large extent, the costs were driven by the quarantine periods and not being able to move people out of country. So basically having 2 crews in a country. That improves now, and that's why we're also guiding towards a lower level of cost, kind of 50% of what we have had so far by year-end and going forward.

Okay. Thank you, Marco. Next question is from [ Nick Lemme from Sutton Place ]. The question is, "Will you recover any of your year-to-date cost on the Umuroa prior to November agreement date? Or this agreement only cover costs going forward?" Do you want me to take it or...

Yes, you can take this one.

Yes, yes. I think it's fairly straightforward. The contract is mainly a contract -- a forward-looking contract. So there is limited cost that will be covered for prior periods. There is an element of a small success fee when you meet the criteria for demobilization, if everything goes according to plan in -- that we're able to get the unit of field by mid-2021. But primarily, it's a looking-forward agreement. Next question is from [ Heston Aaron ]. "In regards to the low price book, pricing in stock market, okay, why invest in new projects versus bigger share buyback programs?" I think, Marco, you have already responded to this one. The answer would be the same as you gave to Carnegie on this one, unless you want to add anything on this.

No, no. I think it's the same question. It's a valid question, and I think I've answered that.

Yes. Next question from the same person. This was, "Why did we not inform the market regarding the incident for Sendje Berge and Yùum K’ak’ Náab?" Well, maybe you can fill in. But in short, we did inform the market about the incident on Sendje Berge, that should be a well-known event. We also informed the market that there will be downtime as a result of it. And also the instance for YKN was highlighted in previous quarter's presentation. I think you can say with regards to the magnitude of this, we did not see this as incidents which would require us to send out separate press releases. And in particular, as we consider this to be one-offs and not incidents, which will have a lasting impact on our results. Okay. Next question from Magnus Olsvik again, Kepler Cheuvreux. "Offshore energy opportunities was mentioned in the presentation, could you elaborate on what you mean by this? Will you enter new business areas outside FPSO business?" I think that question is for you, Marco.

Yes, I can elaborate a bit. I think the offshore energy transition is a fact. That means -- and we see particular opportunities arising in -- on the back of the growth in electrification. So it's -- I think it's logical to consider what our opportunities are in that space. And that could, of course, be from gas FPSOs contributing to power generation. That could also be renewable power generation, for instance. On the long run, I see also opportunities in -- with cleaning fuels for offshore hydrogen productions, but that's further out. But -- so we're considering where we can capture those opportunities. And logically, you will do that with partners. And then that means with the right partners, you can also enter other business segments. A bit similar as we've done with BW Energy where we basically used our global platform that we have as BW Offshore with operations in 10 different countries, more -- well, 30 to 40 years project execution experience, offshore construction experience, operation and maintenance experience. If you put all that competence together, you can reapply that into new business models and new business segments, like we did with BW Energy, where we partnered with -- on the small oil company entity and integrated that in a -- with BW Offshore, and then you create a new business opportunity, new business model. I think we -- I see opportunities to do similar things in the future in the energy transition space.

Thank you, Marco. Next question that comes from Herman Lia in SEB. "Can you please provide some insights into potential financial impact of the incident on Catcher in Q4? And should we think about the operational performance on Catcher in light of the issues in recent quarters?" Do you want to elaborate on that? I see there's a couple of questions which are similar, but we'll get to that.

Yes. So I think there's a couple of questions right around Catcher, I can see, referring to a fire incident. [Technical Difficulty]