Earnings Transcript for AKRBP.OL - Q3 Fiscal Year 2020

Kjetil Bakken: Good morning, and welcome to Aker BP's Third Quarter 2020 Results. My name is Kjetil Bakken, and I'm heading the company's Investor Relations department. Today's presenters are CEO, Karl Hersvik; and CFO, David Tønne. The presentation will be followed by a questions and answers session. Before we start, I would like to refer you to the disclaimer on Page 2 in the presentation. And with that, I leave the floor to Karl Johnny.

Karl Hersvik: Thank you, Kjetil, and a warm welcome to all of you who are listening to this call. I sincerely hope you are all safe and healthy. Third quarter of 2020 was a very good quarter for Aker BP. I would, of course, like to have seen high oil prices, but we delivered strong performance within most of the areas we control. We are well on the track to the level of our production guidance for the year. Our development projects are progressing as planned and we are keeping costs under control as well as, that's the message.

David Tønne: Thank you, Karl, and good morning, everyone. Aker BP's net production in the third quarter was 202,000 barrels per day. The change from the second quarter was mainly driven by planned maintenance and drilling activities. With an underlift in the quarter of 14,000, sold volumes ended up 188,000 barrels per day. Both liquids and gas prices increased quarter-on-quarter, and the realized average hydrocarbon price was up approximately 41% and ended at $38.8 per barrel of oil equivalent.

Karl Hersvik: Thank you, David. I'll walk through as always. Before we open up for questions, let me just summarize our main priorities for the coming quarters and reiterate a few key points. First of all, Aker BP has a very strong operational track record. And we will continue our relentless focus on operational excellence, which is basically about maintaining safe and efficient operations with good cost control. And we will continue to focus on strong project management and to deliver our development projects on time, on budget and with the right quality. Second, we are already one of the leading global operators when it comes to low cost and low emissions. To further improve our position, our main priority is the implementation of a new operating model, which I touched on earlier. Thirdly, Aker BP is uniquely positioned for profitable growth due to the combination of a larger resource base and Norway being probably the most attractive place in the world right now for E&P investments. With our project portfolio, we can mature more than 500 million barrels for FID by the end of 2022, potentially doubling our production a few years down the road. These projects will all have breakevens below $30 per barrel. And helped by the temporary tax regime, we can do this without stretching our balance sheet. In my mind, this is a unique value proposition. This concludes our presentation, and we are now ready to take your questions.

Operator: . We'll now take our first question from Alwyn Thomas from Exane BNP Paribas.

Alwyn Thomas: I guess, if we could just start off at a reasonably high level. You've got a bit of a war chest now after the recent bond raises. I wanted to ask how you think about using that? And whether M&A comes into it or particularly as you've got 500 million barrels of resource that you can put into action relatively quickly over the next couple of years. Is that really the priority for that, that money at the moment? And then perhaps, Karl, maybe get your thoughts, maybe we're a bit too early here to ask this, but can I get your thoughts on when you think about the dividend level at the moment. And like I said, if things are slightly improving, and obviously, the tax regime is starting to help as well on a cash flow basis, whether we can see an increase in dividend early next year?

Karl Hersvik: Yes. Thanks, Alwyn. Excellent questions, as always. So let me start with the so-called war chest. We really don't think about it as a war chest. We think about this as a robust balance sheet. And we have, for a long time now, we've been communicating a message that we want to be ahead of the game when it comes to maintaining a robust balance sheet and liquidity. We actually see that as probably one of the cheapest ways of -- as a hedging volatile oil price environment. And if anything in 2020, it has proven that this volatility is, one, significant and, two, probably here to stay. I think in the E&P space, the CEOs have always been talking about the better world, and now we're actually living one. So it's good to see that Aker BP is in a position where our main strategies on hedging those risks are actually working and we're able to secure additional financing in the middle of this huge turmoil. So that, of course, also means that, as you probably realize from our presentation, our primary focus now is to realize the early phase projects that are ongoing, roughly 500 million barrels. And with the $30 breakeven, it's really difficult to see how M&A should compete. And as always, we will be disciplined when it comes to M&A. We are a company that's all about value creation. So while M&A is not entirely off the table, it, of course, will need to be more profitable than the alternative investment into our organic hopper. And if you start running the numbers, you'll realize that, that has to be quite a spectacular good deal. When it comes to dividends, I think I'll come back to that when we come to our capital market updates, probably in February. There are, of course, discussions ongoing, both internally, and we also hear that there are a lot of advice and a lot of opinions from different parts of the ownership groups. So we'll come back to that in more detail in February, Alwyn.

Operator: The next question comes from Teodor Nilsen from SB1 Markets.

Teodor Nilsen: Karl, you highlighted that in your investment proposition low OpEx is very important. And just looking forward on next decade, are you doing any specific steps right now to avoid cost inflation in the next part of the cycle? Or do you never see that we will have actually a tight supplier market? Second question, just a follow-up on the dividend level. Of course, I understand that you can't guide specifically on 2021 dividend today. But can you just provide some high-level thoughts around how you consider cash dividend versus buyback?

Karl Hersvik: Teodor. Well, I must have missed that. I actually expect some cost escalation as we increase our investment portfolio in the Norwegian E&P space. And to some extent, this is actually desirable. Because if you remember back, the idea among this temporary tax change was to ensure that the vendor industry, one, has a sufficient influx of, I would say, activities; and two, that these activities generated a positive result for this company. But it's not necessarily just about surviving. It's also about actually being able to run through that transition. So I think that's my point of departure on that discussion. And then I think the primary strategy from an Aker BP perspective is along two main lines. So when it comes to how we deal with the vendor market, we've been for a long time now working within these alliance partners. And I think around 95% maybe of our CapEx is currently passing through different alliances and the OpEx is similar or trending similarly. And then, of course, we talked today about the new operating model, which is the first stage about standardization. We've been now focusing, as you've probably seen, on operational issues like uptime, throughput, maximizing production, et cetera, et cetera. And now we're starting to kind of back to stable. We're starting to run down standardization, which will also enable us to acquire these services and goods in a much more predictable manner and thereby also providing better influx and better planning and lower waste in our processes. So at least there's a solid plan in place. And then, of course, we are always eager to stay ahead of that game and see if we can actually do further improvements. Now when it comes to dividends, and of course, instruments, I don't think I'll speculate too much in this call. And we'll come back to this in detail when we come to the Capital Market update in February.

Operator: The next question from Anders Holte from Kepler Cheuvreux.

Anders Holte: Sorry, if there are some sound effects in the background. But just a couple of questions, if I may. First of all, related to your operational cost guidance for next year. I'm just curious to see how much of that increase in '21 that you gave in your slide is due to FX rate and how much of it is due to underlying costs coming up? And also in relation to your spending level that you're now indicating for next year, how much, if any, is related to NOAKA? And what are the key drivers for that continued high level of CapEx for next year?

David Tønne: Anders, I can do the question around guiding on cost level. So the slight increase indicated for 2021 on OpEx per barrel is primarily driven by FX. So if you refer to the footnotes on the slide, we are basically assuming NOK 9 per $1 as average for 2021 compared to the average, what we've seen this year is more close to NOK 9.5. So that's the reason why there is a slight uptick. When it comes to NOAKA total spend, I don't think we will go into details on sort of CapEx for project as of now. But I assume you will provide some more details on the NOAKA project probably when we get back to the capital markets update.

Karl Hersvik: Absolutely, Anders. But also remember that before DG2 this is field evaluation cost, meaning expects. And DG2 is planned for Q3 2021, right? So there will be a limited CapEx spend for NOAKA, and most of this field evaluation of steady cost is now being projected as expects. And then maybe an additional comment to the 2021 OpEx per barrel. In his remarks, David also talked about the underlying cost performance. So while the change in dollar per barrel is primarily driven by FX, the activity level is somewhat increased. So the underlying cost performance, if you view it from a resource utilization point of view or an activity point of view, is declining.

Operator: The next question comes from Yoann Charenton from Societe Generale.

Yoann Charenton: Three questions, if I may. Turning back to Slide 21, which shows tax payments and refunds. The projections for the first half of 2021 in terms of payments or refund has changed dramatically on the $50 scenario. Would you please shed some light on the drivers behind this? Second set of question, would it be possible to hear a bit more from you about further likeliness of further deployment of power from shale solutions across your existing hubs? And secondly, about the opportunity set for powering some facilities with Offshore Wind? Finally, would you mind providing some color on how environmental considerations may have played a role in forming a decision regarding the barrel fee in recent licensing rounds?

David Tønne: So Yoann, I could do the tax question, and then I'll leave the word over to Karl. So on Page 21, we illustrate the fact for the fiscal year 2020, meaning based on the results in 2020, we paid 6 installments, 3 of them are paid in second half of 2020 and three of them are paid in the first half of 2021. And what we are indicating here on the slide is basically what installment to be basically here at the tax refund, depending on what the oil price will be in the fourth quarter this year. So we have, of course, now 3 quarters of actuals. And then spending of oil price in the fourth quarter that indicates the cost results for the year. We have already picked the three first installments and then the variable is 3 installments first half of 2021. So that's what the $50 scenario here indicates. And Kjetil will add the additional comments here.

Kjetil Bakken: Yes. Yoann, one additional commentary is that in the previous version of this chart, the sensitivity was made based on full year oil prices versus now it's only Q4 oil prices that vary. So that's why the bars have narrowed in.

Karl Hersvik: Thanks, Yoann. And then for the other two questions, and if you start asking these difficult questions, David and I may have to change roles, so I can answer back questions and he can do the more environmental discussions. So power from shore, we are assessing power from shore, concretely, of course, related to NOAKA, which will be powered using an onshore grid action. That it's already decided. There is, of course, questions whether or not this can form some sort of system where Offshore Wind production is finding an offtake in the NOAKA area. Maybe in addition to power from shore solution, where the volatility in the -- or I'd say, flexibility in the offshore wind production will be countered by power from shore. So the discussions such that these are, of course, ongoing and also ongoing at other assets, both operated by Aker BP and other companies. Then there are discussions related to existing operational assets. Both of those who are now, I mean, ramping up to be powered from electricity is of course we've already in 2022 and for Aker BP clear our electrification that is ongoing at the moment. And also this already powered and does really have a power production going on and give an alternative power using gas turbines at advanced tank, which one this cost line side decommissioned and replaced by power from shore. It will be entirely electrified. And then there are assessments ongoing, both on Alvheim and Skarv at the moment. Currently, I would say that these projects are challenging. Retrofit of power from shore solutions to FPSO. So it's technology novelty, but we are addressing it. So when it comes then to, let's say, other possibilities in terms of Offshore Wind, Norway has really 2 areas for application of Offshore Wind. And also in Southern North Sea, very close to Valhall in fact. And it's these two areas, which is just in from the NOAKA field development. Of course, brings up discussions around how offshore operations can be utilized, current infrastructure offshore in oil & gas can be utilized to improve Offshore Wind installations. There is 100-megawatt or HVDC line out to Valhall, the longest HVDC aligned on the industry in powering and offshore installation that's 295 kilometers. So we are in the middle of all of these discussions. And as soon as we have more clarity, Yoann, we'll come back with more details. So when it comes to the Barents Sea. So, first of all, we, as a company, entirely believe that it's fully technologically and technically possible to develop an oil and gas installation in the Barents Sea. So let me not leave any doubt about that on the table. It is entirely possible and has been proven already to do this in the Barents Sea. It's not a particularly different -- difficult regime to operate in. Yes, it's dock and somewhat full, but it's not more difficult than the Norwegian. Second, when we think about our priorities in terms of capital allocation, I think, first and foremost, we've been disappointed about the exploration success, primarily linked to the number of exploration models that have now been drilled out with limited success. So to us, this is mostly about a commercial decision, where we believe that our exploration cost is better than elsewhere. Two, that we have a really large organic that would like to mature. I don't necessarily see the need to go looking for long in the two assets in the Barents Sea. And thirdly, this is also about the geological assessment of the opportunities we've seen in the Barents Sea. So let me go back and say that we entirely believe that it's durable and viable to develop operations in the Barents Sea, but we have chosen to allocate upon elsewhere.

Operator: We'll now take the next question from Karl Fredrik Schjøtt from ABG.

Karl Fredrik Schjøtt: A question regarding dividends. Do you feel that there's large political pressure for you not to raise dividends at the Capital Markets Day next year? That would be the first question. The second question relates to the new project and in terms of news flow on the full hopper that you present today. What should we look for in terms of news flow on these projects?

Karl Hersvik: Thanks, Karl Fredrik. So on dividends, I think I just reiterate what I've already said. It's, of course, helpful when we're now financing. But the Board has made the changes to the dividend policy that we had in place previously. But when it comes to new dividend policy, we'll refer those discussions back to the Capital Markets Update in February. When it comes to news flow, I think, first and foremost, we, of course, plan to run through all these assets, projects and early base prices in somewhat detail, a significant more detail than, of course, today, of course, at the Capital Markets Update. So I think that would be your first touch base in terms of news flow. And then I stated in my presentation that we'll continually operate the markets along 3 main lines. The first one, of course, is the quarterly presentations. Then of course, as we keep on passing decision gates, we will, of course, inform the market as the activities and performance of those decision gate passengers. And then thirdly, there will, of course, be a contract and other, I would say, market communication related to activities carried out by the project themselves. So I think the best advice Karl Fredrik is to stay tuned.

Operator: The next question comes from James Hosie from Barclays.

James Hosie: I was just wondering if you could expand a little about what the new operating model actually entails. I mean you mentioned standardization, in answering an earlier question, but is that -- I'm just wondering, is it investing in technology to increase automation or remote operations, both headcount reductions? Really just if you can give a bit more detail on what's actually going to be done differently?

Karl Hersvik: Thanks, James. Just to be clear, I haven't paid James anything to ask that question. So it's actually all of the above. I think the way of thinking about this is that since 2016 we have been focusing on improvement quite significantly at Aker BP. And we've done that, I would say, along 3 main lines. The first one is to reshape the, I would say, the way we procure services and goods. We've talked about that as an alliance model. We, of course, spent significant time, money, experience in the digitalization, as you might have seen. In fact, we have now got the pricing on Cognite with the entrance of excellence into that company which also proved that this activity from an Aker BP perspective was actually value-accretive as well as an awful lot. We've been focusing on process optimization using the lean program, and we talked a lot about flexible models. And it's quite clear that this has been quite a bit of experimentation. That means that different assets have different books in the portfolio. And in the same time, we've been really focusing hard on production optimization, getting the uptime to where we like it to be, getting the operations to a stable environment, getting execution right, getting the basics in place. And what we're doing now with the operation model is we're taking all of these pieces, and we're putting that into a systematic framework and implementing them in a consistent way across the portfolio. So we're using all these experiments, and we're basically running that into a structured process. We couldn't have done that two years ago, to be honest, because we didn't really know how digitalization we're working with business processes, our alliances and in-sourcing and outsourcing would impact our data flow, et cetera. So we are relying on those experiments and those, I would say, development programs that we've done. So the 3 -- to me the 3 key figures are as follows

Operator: We'll now take the next question from James Carmichael from Berenberg.

James Carmichael: Just a couple of quick ones on the assets for me. I was just wondering if you could provide a bit of color on the choke influx that you mentioned at the new wells at Valhall, just how significant is that? And are there any set basis you can take to mitigate that in future drilling programs? And then also just quickly on Johan Sverdrup. Just wondering if you could provide any sort of indications of the potential upside you're targeting in the Phase 1 facilities?

Karl Hersvik: Okay. Good. Let me start on Valhall. So currently, we have choke influx in -- and some reasons to drill some wells at Valhall, this is -- talking to Valhall is really nothing new. It's been a problem since the field was put on stream. And usually, we clean out these wells using coil tubing pretty much immediately. The reason this now becomes a bottleneck is that we're also stimulating wells using the same possible units that we should use cleaning out these wells. We are experimenting with a machine learning algorithm to predict chalk influx as we have been unsuccessful as of the industry of predicting chalk influx using empirical mathematical models. There are some positive results coming out of that work. So we are believing that over time we'll be better faced to pull those and predict, which is the key to avoiding the chalk influx. We are investigating other lower completion technologies that is different track problems, different binders, different mixed frames when pumping the frac frames, et cetera, but also different solids screen out, yes. It's not really screening, but it's more about solid controlled on Valhall. And thirdly, we are assessing different chemical properties to resolidify the chalk after you've seen a chalk influx. So there's quite a lot of activity going on. And to us this is really important because stepping up the system on a control will reduce cost because all this contributed work is, of course impact. But it will also allow us to drill other wells, simple wells, to realize 1 billion barrel at Valhall. Now when it comes to -- when it comes to you onsite, I'll leave it to the operator to disclose details on that in testing program but it, of course, means that we are stress testing and looking for new bottlenecks. And as I've talked about in previous presentations, we are now at a level where we assume that we will meet several of these bottlenecks at the same time or very close to each other in time. So it's a more complicated testing machine that we've seen in the box.

Operator: The next question comes from James Thompson from JPMorgan.

James Thompson: Great. I've got all the James in a row just then. Karl, I just wanted to ask you a little bit about, obviously, the development projects that you've outlined there. You've got 11 projects to sanction by the end of 2022, which in the first instance, feels to me like quite a lot of projects to get done in the organization. And your commentary sounded a bit more like an aim rather than a commitment. The questions really were, is there a plan here that you effectively get these sanctioned and then you sort of stage the investments? It's very clear that your focus on NOAKA and getting that done first, but you just really want to just take the other bits off before you pursue sort of significant development CapEx on them. And also just thinking about the investments there if 3 going into Skarv, another 3 going into Alvheim. Are there any sort of capacity issues in terms of total liquids that might cause you to sort of spread those out over the next 5 or 6 years?

Karl Hersvik: If I said James, that sounded like an ambition, then let me clarify that immediately. So while there certainly as an ambition, we're staffing all of this project for execution. So we're not playing a game here we throw up a lot of projects. And then some way down the road, discover that they will end up different. They were really running very hard now to execute the project in accordance with what we set out to do in the summer with the temporary tax changes. We're not kind of playing a game here at all. So that means that we're also working really hard to staff these projects. And you're right. It's a stretch, to staff all of this. In Garantiana, of course, is Equinor operated project. And Alvheim is also an Equinor operated project, but we are collaborating with Equinor in the -- this area to do a field development of four tiebacks in Alvheim and Skarv in the area. So I don't know if it is part of that. These other projects. If you think about this from an Alvheim perspective. It's a pretty almost right on the milk, so that it's easy. None of these projects are easy, but we know how to do it. There's not a lot of, let's say, new concept development that needs to be done. And we're kind of putting them into an already, I would say, robust execution machine. Valhall is a little bit of a new one chalk depending on solution. But again, the alliance is already on it, worked really hard and that we end up with a solution that's more, I would say, industrial in nature, we can also rely on hopping effects. So each of these projects have their own dedicated team, their own dedicated project leads. We follow them up every month in my effective management team. For us, this is actually fundamental to the valuation potential of Aker BP. So let me be very clear, this is something that we're spending a lot of effort on. We truly believe, as a consequence that it is doable to execute these projects and be FID by 2022. And then to us, execution is a part of getting these projects phased in through our rig lines, our production lines with the alliances and on yards, particularly in Norway and other. So execution in terms of detailed time lines will be a part of the total activity level on the Norwegian contract itself. But right now, I feel that we have very good control over these projects, particularly with the alliances now working on them. And that also gives us a huge muscle for us. So as a company, if we were to execute all of this using a conventional model, I will be doubtful to our ability to execute with quite a few years of experience within the alliance model now I'm actually without a doubt we will be able to execute this project. And that also perhaps volumes -- speaks volumes to the strength of the alliance volumes in addition to currently being costs under control, keeping quality under control, just gives us a huge muscle in terms of execution of this project.

James Carmichael: All right. Okay or to the FID. And I just wanted to follow-up on the question of the operating model. Are you able to sort of quantify what the sort of formalization of all the improvement work you've done over the last 3 or 4 years, means in terms of that kind of operating cost per barrel? Is it kind of worth of sort of $1 to $2 a barrel to you over the long term? Is that the ambition?

Karl Hersvik: It's a good question, and it's something we're asking ourselves all the time. That's a question of how the actual value of cost and value and an income on each of these activity programs and improvement programs. So the way I think about this, it's more in terms of development. We are basically now seeing activity levels up or higher than we saw two years ago. But we are seeing decreasing underlying costs. Against the same, I would say, outflow in terms of cost per hour, to vendors, et cetera. We're seeing production efficiency trend consistently upwards, meaning that we're driving production up as well. And there's a certain amount of activity that is behind that production efficiency increase. So while there is no doubt that these improvement programs have provided meaningful reduction in cost per barrel, allocating, I would say, $1 per barrel to each of these activities is more difficult. So what we try to do now, and we're set ourselves a quite ambitious target internally, and we'll communicate those to the market at the Capital Market Update and give you a lot of transparency in terms of program and agile ambitions, but they're quite significant in nature. So they're not incremental in nature when you think about the improvement program. And it's basically a continuation of a trend that we'll see or at least the last 3 or 4 quarters.

Operator: The next question comes from Sasikanth Chilukuru from Morgan Stanley.

Sasikanth Chilukuru: I had two, please. The first was regarding the expected oil breakeven price. And apologies, if I -- if you've already mentioned that and I missed it. I was just wondering given that you now have indicative guidance for production, CapEx and production cost for 2021, where do you think the crude breakeven price for 2021 is before the dividends, I suppose, if you can give an indication, that would be helpful. And the other one, was also related to the breakeven oil price but for the projects. You mentioned less than $30 breakeven prices. I was just wondering, the field evaluation cost that you mentioned in 2021, particularly for NOAKA, is that included in that breakeven oil price that you highlight or is it post FID?

Karl Hersvik: So, David, you can answer the first question.

David Tønne: Yes. Thank you for that. So probably a bit too early to go into too much detail on this. But I think what we have presented today, we are talking about free cash flow breakeven at or below $30.

Karl Hersvik: And when it comes to breakeven. On MPE breakeven. So the way that is calculated is simply all costs into the project and we don't really differentiate between CapEx and OpEx and all these other cost elements. So of course, field evaluation leading up to which is a part of the breakeven. It is a cost that is incurred because of the budget. So of course, it's included in the break. And this is also why we talk about full life cycle breakeven and not pre -- post FID breakeven, which is a very different number. Of course, all of these projects as you trend towards production staff, that will be lower than $30 per barrel. So that becomes a little bit of a meaningless game. Just this is about capital allocation, and therefore, we need to see the entire COGS picture on this project.

Operator: The next question comes from Michael Alsford from Citi.

Michael Alsford: I just got 1 left, please. So Karl, you made a clear rationale of why you're prioritizing organic growth rather than chasing M&A. But on the flip side, you're targeting around 60% of your contingent resource base with the next pipeline of development projects. Are there any non-core resources in the portfolio that we might see you dispose off in the short-term where others maybe haven't got the resource base that you have blessed with?

Karl Hersvik: That's an excellent question, Michael. Yes. We have around 915 million barrels in 2C resources. And of course, we are receiving a lot of incoming, I would say, requests for 2C resources. I also stated that this is probably the most interesting investment environment in the E&P right now, which also has an effect on pricing and willingness to pay for these 2C resources. Most of these 2C resources that are now, is having in the hopper were either, I would say, doing from an exploration portfolio and probably around $1.1, $1.2, maybe on average per barrel or through M&A activities at basically the same level. So yes, there is a discussion whether or not some of these resources could be divested, but I won't be -- I won't dive into details on these discussions. I think we've given a lot of clarity on which project we are now prioritizing in terms of credit -- or capital allocation. And then there's question also allocated to M&A. Yes, you're quite clear that the -- however we are quite clear that organic growth is a priority at this point in time. And while M&A is not entirely off the table, it will be rather disciplined to see that kind of activity, at least when it's portraying CapEx for the time being.

Kjetil Bakken: I think we have time for only 1 more question now before we have to close the discussion.

Operator: There is no further questions in the queue at this time.

Kjetil Bakken: Okay. That is good. I hope that you have got all your questions answered. And if not, then the IR team at Aker BP is at your disposal. We wish you all a great day, and please stay healthy.

Karl Hersvik: Thank you.