Ladies and gentlemen, welcome to Equinor's 3Q18 analyst call. I'm Peter Hutton, Head of Investor Relations at Equinor. I'm delighted to welcome Lars Christian Bacher as CFO. He's also joined by Svein Skeie, Head of Performance Management, and Morten Haukaas, Chief Accountant. Lars Christian will run through the presentation for around 12 - 15 minutes. We will open up for questions. We'll expect the call to finish within the hour. With that, let me pass the word over to Lars Christian. Thank you.
Thank you, Peter, and good morning, everybody. I've been looking forward to talking to you in my new capacity as CFO. It's good to start by presenting Equinor's strong third quarter result. Three things to highlight. One, our adjusted earnings before tax this quarter more than doubled compared to the same period last year to $4.8 billion. The after-tax adjusted earnings were strong, $2 billion, which is up more than 140%. You have to go all the way back to the first quarter of 2014 to find a stronger result. Remember, the oil prices were well above $100. Our third-quarter IFRS net operating income was $4.6 billion. Two, we have the best ever after-tax adjusted earnings for our international segment of $774 million. Three, we are lowering our CapEx guidance from around $11 billion to around $10 billion. This is strong deliveries.
Higher oil and gas prices have, of course, contributed to the good result. It is not the only explanation. We create material value because we use the downturn to reduce costs and to transform Equinor into a more competitive company, being more agile and resilient. With the E&P industry seeing higher oil and gas prices, now is the time we must show discipline and protect the structural improvements we have achieved over the last four years. Together with our suppliers and partners, we have a joint responsibility to continue to improve and further strengthen our competitive position. This is how we can create the basis for a stable activity level, new projects, and value creation for all. We are continuing to progress our next-generation portfolio. In the third quarter, we delivered field development plans for Johan Sverdrup Phase 2 and Troll Phase 3.
These two projects, both with very low breakevens, are excellent examples of our ability to deliver on our always safe, high-value, and low-carbon strategy. Phase 1 of Johan Sverdrup is more than 80% complete and expected to start producing in November next year. It's not only the largest projects that generate value. On October 14th, we started producing oil from Oseberg Vestflanken II, the first unmanned wellhead platform on the Norwegian Continental Shelf. We delivered this field with a CapEx of NOK 6.5 billion, around 20% below forecast at the investment decision. The breakeven for the field has been reduced from $34 at FID to less than $20 per barrel now, further improving an already robust field development. The Mariner field in the U.K. is progressing with hookup and commissioning ongoing offshore.
Due to challenging weather conditions, very challenging weather conditions, and other factors, the estimated first oil date is delayed to the first half of 2019, with CapEx unchanged. I repeat, CapEx unchanged. Meanwhile, the Mariner reserves have been increased by around 50 million barrels, a 20% increase. This comes as a result of improved reservoir understanding and more optimized drainage strategy. We also continue to strengthen and sharpen our asset portfolio to create value. The acquisition of Rosebank operatorship in the U.K. gives us the opportunity to leverage our experience gained from Johan Castberg to realize a new exciting deepwater project with a considerable value creation potential. At the same time, we have recently divested the undeveloped and, for us, low-priority discoveries, King Lear and Tommeliten Alpha, on the Norwegian Continental Shelf. With these transactions, we deliver on our strategy to create value through the cycle.
In the quarter, we also continued to strengthen our industrial position in renewables. We are on track with the Apodi solar project in Brazil, and we have started the delivery of power from Arkona offshore wind project in Germany. Equinor is now in projects with the capacity to supply around 1 million European households with power from offshore wind. The third quarter is characterized by strong cash flow generation, strong earnings across all business segments, and high production capturing higher realized prices. We reduced our net debt ratio from 27.2% in the second quarter to 25.7%. Combined with strict capital discipline and continued strong project execution, we are able to reduce our CapEx guiding for 2018 from around $11 billion to around $10 billion. We maintain our commitment to capital distribution, and the board of directors have decided to maintain the dividend for the third quarter at $0.23 per share.
The safety of our employees and the integrity of our facilities and installations is and will always be our top priority. Our serious incident frequency the last 12 months was 0.5 per million hours worked. This is the same level we achieved in the 2 previous quarters, and it is the lowest level ever achieved by Equinor. In the same quarter last year, our score was 0.7. Now let's have a look at the key financial takeaways for this quarter. Adjusted earnings before tax were strong at $4.8 billion, an increase of $2.5 billion. This is more than a doubling when compared to the same period last year. The IFRS net operating income was $4.6 billion. There are three key drivers behind the strong quarterly results. High realized oil and gas prices, high production due to new fields and new wells, and continued strong cost focus.
I'm very pleased to see that all segments delivered strong results this quarter. We realized on average liquid price of $67.6 per barrel, an increase of 44% compared to the third quarter last year. Realized European gas prices were up 33%, while North American gas prices were up 15% year-on-year. Adjusted earnings after tax came in at $2 billion, up from $0.8 billion in the same period last year, an increase of 143%. The tax rate in the quarter was a low 59%. At higher oil prices, we are seeing sustained profits being generated internationally in areas with low effective tax rate. Let's now have a look at each of the segments. E&P Norway. E&P Norway delivered adjusted earnings before tax of $3.4 billion. This is an increase of 68% year-on-year. The main adjusted earnings driver were high realized prices combined with lower DD&A.
Production was down 6% due to an increased number of turnarounds and expected field declines, partially offset by contributions from new wells and ramp-up of new fields. Underlying OpEx and SG&A costs per barrel increased somewhat, mainly due to plant turnarounds, new fields, and preparation for operations. E&P International. E&P International delivered strong adjusted earnings of $1 billion before tax, up from negative $27 million in the same quarter last year. After-tax-adjusted earnings in the quarter from E&P International is the strongest ever. We recorded the highest quarterly production of 831,000 barrels per day, a 14% growth year-on-year. I must say, it's kind of a bit annoying that the record was achieved just after I left EPI. Torgrim and Anders and their organization have done a great job, and as CFO, of course, I'm obviously very pleased with these results.
The underlying OpEx and SG&A cost per barrel were stable international, adjusted for royalty and asset retirement obligations. The net cash margin per barrel after tax in E&P International is a strong $30 per barrel, which is higher than the contribution per barrel from the NCS. Our MMP segment delivered strong pre-tax-adjusted earnings of $481 million compared to $423 million in the same period last year. A good delivery is mainly due to strong products trading and strong results from European gas. During the quarter, Equinor's total average equity liquids and gas production was 2,066,000 barrels of oil equivalents per day. This is an increase of 21,000 barrels per day, corresponding to a 1% increase compared to the same period last year. The production growth is due to start-up and ramp-up on new fields.
Portfolio changes, among them the acquisition of the Roncador field in Brazil and new wells put on production, especially onshore U.S. This is partly offset by high planned turnaround activity on the Norwegian Continental Shelf. Year to date, we report strong cash flow from operations of more than $20 billion before tax. After investments, dividends, proceeds, and transactions, the net free cash flow year to date is $2.5 billion. Without the value-enhancing transactions on Roncador and new prospective acreage in Brazil, North Platte in U.S. Gulf of Mexico, and Wisting on the NCS, we would have more than doubled the year-to-date free cash flow. Our net debt ratio was further reduced by 1.5 percentage points during the quarter to 25.7. In the first nine months of the year, our organic CapEx is $7.2 billion. Proceeds from portfolio transactions add up to $1.2 billion year to date.
Let me close with a few comments about our guiding. We have been able to lower our 2018 CapEx guiding from around $11 billion to around $10 billion. We maintain our 2018 exploration spend at $1.5 billion. This is due to good project execution, efficiency improvements, and cost reductions on several projects, like Johan Sverdrup and strict capital discipline. Expected 2017 to 2018 production growth is unchanged at 1%-2% and 3%-4% per year for the period 2017 to 2020. We are on track to deliver on our ambitions communicated at the Capital Markets Day last February. As Peter said, I'm here with Morten and Svein. We are looking forward to your questions, Peter will guide us through the Q&A session. Thank you for your attention.
Thank you, Lars Christian. In fact, what I'll do is I'll pass the word straight over to the operator so that she can remind you of the process to poll for questions. Thank you.
Thank you. If you would like to ask a question, please signal by pressing star one on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Again, press star one to ask a question. We'll pause just a moment to allow everyone an opportunity to signal for questions. We will take our first question from Oswald Clint from Bernstein. Please go ahead.
Good morning. Thank you. Yeah. I'd like to ask just on the CapEx reduction that you've released this morning, the NOK 1 billion, maybe could you just break it down a little bit more in terms of, is this pricing reductions? Is this kind of redesigned and cost savings, or is it some rephasing of spend into 2019, please? That would be my first question. Secondly, obviously some very strong cash flow, some decent improvement in the balance sheet position here again. We didn't really hear any language around the increased shareholder returns that I think you spoke about earlier in the year, the scope for buybacks emerging back in February. I just wonder if you could update us on that comment that you made at the beginning of the year, given how good the cash flow has been through 2018, please. Thank you.
Well, thank you. Let me start with the first question on CapEx guiding for this year. We have taken the guiding down from around $11 billion to around $10 billion for the full year. I must say that I'm impressed. Perhaps I should stop being impressed, because they deliver year on year. I'm still impressed by the quality of execution of our project portfolio, that the projects deliver. The ability for us to take down the guiding is based on twofold. One is capital discipline, because we have a lot of sort of small capital projects, too. This is about capital discipline and making the right priorities. Then combined with all the field developments and the projects, the majority of the contribution is related to project execution. This is not sort of a redesign at this stage.
It's more about project execution. That's why we take down the guidance. On the element of share buybacks, you refer to the beginning of the year, let me then remind you of what we said at our Capital Markets Day. We concluded the Scrip program as planned. We increased the dividend and said an emerging scope for share buybacks dependent on macro outlook and portfolio developments. We also said that short-term priority was to strengthen our balance sheet, meaning reducing the net debt ratio. Since then, in my view, we have delivered on these guiding, we have reduced our net debt ratio from 27.2 to 25.7 percentage points. We have delivered strong cash flow, as I say, of the tax at $2.5 billion, which would have been more than double if we hadn't done any inorganic investments during the year so far.
We have taken positions like North Platte in Gulf of Mexico, Martin Linge on the Norwegian Continental Shelf, and Roncador in Brazil, to mention a few. All these good value propositions for the company and thereby also the shareholders. You will see us going forward reducing our net debt ratio is a priority and catering for our flexibility and strong balance sheet given the different market outlooks going forward and the opportunity space we see for making good deals.
Okay. Very good. Thank you.
We will now move to Thomas Adolff from Credit Suisse. Please go ahead.
Morning. My first question is also on CapEx and capital efficiency. I wonder if you've done an amazing job over the past four years, whether there's actually more you can do from here on or whether it's getting pretty difficult. Given the update on capital efficiency with this result, I also wondered what it meant for CapEx for the period beyond 2018. Secondly, on capital allocation, I'm just wondering if you are more actively engaged in buying more assets or companies than selling assets at this stage. Thank you.
I'm just writing down the question so I remember it correctly. On CapEx, if there are more to do from now on going forward on project deliveries. The better you get, it's harder to improve even further. That's obvious. What we look at currently within the area of digitalization, we believe that there might be opportunities to improve even further. That is something that we're working on and too early to conclude as to how that will influence our different projects going forward. On the CapEx guiding for the period towards 2020, there is no change in the guidance. We said around $ 11 billion in CapEx for 2018 and then on average $ 11 billion for the period 2018 to 2020. That guiding remains. On capital allocation, whether we buy more than we divest currently.
The proceeds from sales at $1.2 billion and $ 2.5 billion after tax in free cash flow. As I said, that number would have been more than double if it hadn't been for our acquisition. Yes, we have, over the last nine months, bought for more dollars than we have sold. We will always look for business opportunities. We see some areas around the world are perhaps more of a hotspots, and it's more difficult to make really good business deals. Whereas other places, we still believe that there might be room for doing good business deals. That is what we will seek for.
Perfect. Thank you very much.
We will take our next question from Lydia Rainforth from Barclays. Please go ahead.
Thank you, and good morning. Two questions if I could. One was just on the cost side, you did see a slight uptick in terms of the OpEx numbers. Is that something you're disappointed by, or is that as you would have expected given where the macro side is? The second one, just to come back to the cash flow allocation side. In terms of the, we talked a little bit about the buybacks, but can you just talk about how you see the dividends policy evolving as we go through the next two, three years? Thank you.
Thank you for your questions. On the OpEx and SG&A is up 10% year-on-year. I think it's important to be aware of some of the underlying effects behind this. If we take international first, the increase international is primarily due to new fields like Roncador, but also the fact that last year we had reversal related to positive asset removal obligation. We have higher royalty driven by higher prices. If you adjust for these items, the underlying cost per barrel basis is flattish or even slightly down actually. On the Norwegian Continental Shelf, we see there's one technicality, perhaps I should call it, that you should be aware of. Internally, the company we have said that the Nyhamna, Ormen Lange, the ownership of that asset is to belong to MMP and not DPN.
That means that the DPN have to pay for that service internally in the company. That the net effect for the totality of the company is zero. That explains some of the cost increase in DPN. We have new fields and preparation for operations. If we in addition adjust for the differences in turnaround effects on this, the production in the OpEx and SG&A per barrel basis for Norwegian Continental Shelf is up slightly below three %. Cost per barrel this quarter is then down compared to cost per barrel per second quarter. On dividend policy going forward, we have said that the dividend will increase in accordance with underlying earnings, that is still our guiding.
Great. Thank you.
We will now move to Mehdi Ennabati from Societe Generale. Please go ahead.
Hi. Good morning, all. I will ask two questions, please. The first one regarding the flexibility of your natural gas production. You've highlighted in the past that thanks to your compressors and some key gas fields, like Troll, for example, or Åsgard, you might be able to boost the natural gas production to create value. I wanted to know if you currently consider that the European gas price and European gas demand is allowing you to boost your gas production in the short term, meaning, during the fourth quarter and maybe during the first quarter. That's the first question. Second question, regarding your production trend in Angola. I've noticed it has been down 12% year-on-year during the first nine months of this year.
I wanted to know the reasons of such a decline and what will be the production trend in the following years for that country, particularly, as it looks like, it is a highly profitable production for you. Thank you.
Let me start with your second question on production trend, Angola. We see, obviously, the same numbers as you do, looking at the country and the different assets. We also believe that there might be room for actually fighting this decline, but that is highly dependent on achieving PSA extensions. On to your first question. I felt it was kind of twofold. One on gas prices and demand in Europe, and then on our flexibility on the Norwegian Continental Shelf. We have seen strong demand in Europe, and thereby higher prices over the last months and quarters. We expect that to continue in the short term. Why? Well, one, the indigenous production in Europe is declining and declining more sharply than historically, mainly related to the Netherlands. Second, we see on storage capacity in Europe, there is good storage capacity, but the storage levels are quite low.
We would expect that approaching winter, that there should be sort of a buildup of storage volumes. Thirdly, gas prices in Europe is exposed to the energy in global energy market. We see more or less all energy sort of bypassing Europe and heading for Asia. That also means that there is a kind of a surcharge then for gas prices to rise in Europe. On our gas machine in Norway and the flexibility, we have a couple of assets that represent such flexibility. Troll is one, and Oseberg is one. In the case of Oseberg, currently producing at minimum due to the lower prices now compared to what we will expect getting closer to year-end and winter period. This is well within what we are allowed to produce per year. We try to use that flexibility to maximize our revenue.
Thanks very much.
We will now take our next question from Jason Gammel from Jefferies. Please go ahead.
Thank you very much. Two questions from me as well. First, just another one on capital allocation. Is there any particular trigger that you would need to see on some of the leverage ratios on the balance sheet before you would move forward with share repurchases, or do you see those as linked but independent decisions? My second question involves Rosebank. An asset that you had decided to exit previously. What drove your decision to come back into the project? What's the path forward from here? I know that the previous operator had put quite a bit of effort into pulling down the costs. You also referenced your experience at Castberg. Will there be another iteration of project redesign? Thanks.
Well, on Rosebank, as you correctly point to, we exited Rosebank back in time. That was a non-operated position, 30%. We sold it in 2013. The oil prices back then were higher than today. Also, the CapEx estimates back then was higher than what we currently see. This opportunity arose then for us to take 40% and the operatorship. We looked at that opportunity, given our experience and given what we believe that we can create a value of this, we saw this as an attractive opportunity. Going forward, we have to wait for government approval and partner approval for this deal to go through. Of course, the development of this will be an FPSO with subsea tiebacks.
As you correctly point to, we have, among others, Johan Castberg, to draw upon when it comes to learnings. On capital allocation and trigger points, this is also a question I get quite frequently even out on the road, whether we have trigger points or not. We do not have any trigger points. Why? Because we feel that that would not be a prudent sort of management given the leverages or the elements that I pointed to. This is a combination of trying to strengthen our balance sheets, reducing the net debt ratio. We would like to maintain capital discipline and flexibility, and to better off whatever macro developments we will be facing. There is the opportunity space to build a stronger portfolio.
As an oil and gas company, we need to replenish, which we have been good at, both during the downturn as well as when we have seen an uptick in oil price. We will continue to look for good value opportunities. Remember a couple of points. One, it has to be good value opportunities, because that's the best way to create value for our shareholders. Two, no projects will be sanctioned until it is good enough.
Very clear. Thank you.
We will take our next question from Alastair Syme from Citi. Please go ahead.
Hi. A couple of questions. Turnarounds are normally pretty high in the summer months, so can you just explain what was special about this year that caused Norwegian production to be down 6%? I guess, put it another way, if you remove the effect of the turnarounds, what would the underlying production trend have been? Secondly, can I just come back to the Capital Markets Day? You presented that chart of the sort of the cash flow from operations guidance 2018-2019 average. Obviously 2018 has seen the benefit from significant tax tailwinds. Can you just sort of come back to that chart and remind us, is that how you see the average play out in 2018 and 2019, or how should we think about adjusting the tax in that chart versus what you are seeing here today?
Yes. If you start with your turnaround, I mean, the guide for the third quarter, expected turnaround effect of 80,000 barrels a day. I'm not sure, Svein, if you want to add some granularity to this one.
No, I think you're locked in on what you said. I did the turnaround at 2018. Most of that came from Norwegian Continental Shelf. If you also compare it with the third quarter last year, we also saw that the turnaround was approximately 30,000 more this quarter compared to last quarter. If you adjust for that one, then you see the production on the Norwegian Continental Shelf.
On the cash flow and the guidance, we indicated that we would deliver free cash flow of $12 billion in the period 2018 to 2020, accumulated $12 billion, and at an oil price of $70 a barrel. If you look at the first nine months of this year, we feel comfortable that we will be able to deliver on that guiding.
I was actually also referring to, there was a specific chart that sort of showed the cash flow from operations 2018 and 2019. It was a bit of a fuzzy bar chart, but sort of indicated numbers in the high teens for cash flow. Clearly, you're going to hit that this year in a $70 oil world. You've had significant tailwind from tax. How do we think about 2019 in that context?
Svein?
Okay. I'll just take that one. As we said there, we gave the scenarios for different price scenarios, 50/70 on average for 2018 and 2019. What we indicated and then took into account the tax effect that we had coming in from 2017. What could also then be looked at is when we look at the tax rate and the taxes payable as we have then taken out and showed in the account now for 2018. That could also then be an indication for also then what to expect going forward. Definitely taking into account the taxes from 2017 for the first half of the year. We are in the situation where we pay taxes on the results from 2018, and we had one tax payment in this quarter.
Sorry, just below the point, and your expectations for fourth quarter on tax?
We will have two tax payments on the Norwegian continental shelf in the cash flow. One was paid on 1st of October, which half of it was then adjusted for in the net debt ratio. The second one will come 1st of December. Both of them are then $ 14 billion.
Okay. Thank you very much.
We will take our next question from Anders Holte from Kepler Cheuvreux. Please go ahead.
Good afternoon, guys. Thanks for taking my questions. I just have two quite short ones. First of all, it's related to your list of priorities for next year. As your cash flow improves and as your position improves, it seems that the balance sheet is probably at the top of your list of priorities. If you'd take us through what then follow in terms of your priorities, would you prioritize first buybacks, or would you continue to look for more value-adding opportunities through M&A? Also, while we're onto the M&A, what does the opportunity set look like from where you're sitting at the moment? Previously, you have said that the opportunity set in the industry is as good as you have ever seen it. I just wonder if that's still the case right now. Thank you.
On the opportunity set, it is still very good on an aggregated level. There are some hot spots around the world where the competition is higher, you could say. The possibility to really make good value propositions based on a deal is somewhat tougher or more limited. There are still plenty opportunities, and we will continue search for them and hunt for them and see if we can strengthening and high grade our portfolio as part of this. The M&A is both a combination of acquiring assets, but also high grading by farming down or divesting assets. We have a tradition for not announcing neither sort of amounts of dollars, part of our program or any sort of possible deal prior to you read about them in the news.
On the priorities on a capital distribution, there is no change in our guiding on this topic. Scrip has ended, dividend has increased. Going forward, we have said emerging share buybacks dependent on market outlook and portfolio opportunities in combination with strengthening our balance sheet, meaning reducing the net debt ratio. That is the guidance I can provide you.
Okay, thanks.
We will take our next question from Jon Rigby from UBS.
Oh, hi. Yes, thank you. Couple of questions. First is on the tax. You made some comments around the international tax rate looking lower at these oil prices. I just wonder whether you could give me some sort of further color around how long you would see that and to what sort of sensitivity there is to oil price assumptions. Then sort of as an aside, is that effect carried forward into the cash flow, or is this effectively an accounting effect in the P&L? The second question is about your U.S. onshore. The key advantage of U.S. onshore seems to me, or one of the key advantages is flexibility.
I know that you're cutting CapEx this year, but isn't there a case to say that voluntarily you start to raise CapEx, particularly in the U.S. onshore, where you can take advantage of the short cycle aspects of that element of your upstream portfolio? Thanks.
Very good. On tax first, tax international. We elaborated around this during second quarter, where we had internationally a tax rate of 27%. This quarter it's lower. We said then at 27%, that that could be seen as a representative level at these commodity price levels that we currently are seeing. That means that this low tax rate, that we are earning good money in countries with low tax rate or no tax rate. This is why we can report highest earnings after tax ever internationally. I also think that 27% compared to an even lower tax rate this quarter, I think you should remember that this quarter were no exploration activities in the countries with the low or no tax rate. You can't sort of assume, take that for granted going forward.
Still our best guidance, given the current commodity prices is around what you saw with international tax rate for our second quarter. Yes, you see this count into the cash flow numbers. On U.S. onshore and the flexibility and activity level, I think I'll let that to Morten or Svein to comment on. Before I do that, to comment on cutting CapEx this year. That is one way of looking at it, but it is not cutting from the point of view that we just slashed the budget because we want to take down the activity level. The result of going down from around $ 11 billion to around $ 10 billion in guidance is as a result of being more efficient in the execution of project deliveries and strong capital discipline. Mainly the first one. Yeah.
On the onshore activity in U.S., we are also then following closely what's going on. As we have said that we have flexibility here in the operations. When you compare it to the production one year ago, it has then increased. We are now producing around 275. A year ago, we have approximately 225. Then increasing it in line with prices. We are in the operations. As we end the quarter, we have three rigs in place there. Also on the non-op, there are more rigs now than earlier. It's about then utilizing the flexibility. What is also important is then the completion of the wells, as Lars Christian said also in his presentation, that production is going up also due to the fact that we have completed more wells.
It's a combination of both drilling as well as doing completion on the wells already drilled.
Can I just follow up? Do you have the capacity or the capability or the acreage to lift activity rates should you choose to from here?
There is flexibility in the onshore then to adjust activity. Yeah.
Okay. Thank you.
We will now take our next question from Christyan Malek from JP Morgan.
Hi, good morning. Thanks for taking my questions. Two please. First, sorry to come back on this tax. Can you give us visibility in terms of how long this is going to last in terms of these effective subsidies through the unrecognized or deferred tax assets that you have in the U.S.? Is this sort of into perpetuity for the next few years, or do we talk to the close of this year? I understand the relationship with the oil price and the fact it's being generated through U.S., but just to what extent can you provide a quantum and a sort of an expiry in terms of when it sort of rolls over, to help us model the numbers better through the U.S. in terms of tax rate? The second question regarding understanding capital allocation philosophy that you have, and there are no triggers.
Just to flip it around perhaps, what is the incentive to take advantage of more opportunities when you have fantastic assets as it stands? Put another way, do you have to keep delivering production growth through the medium term as opposed to just consolidating your assets and giving the market the cash back through whatever means that you have? I just want to understand the debate that you're having at the board. What is it that seems to lean you more into M&A and taking advantage through a lower balance sheet gearing over and above cash allocation, cash return? I just want to understand the debates you're having. If I can ask sort of a sub part to that question.
In energy transition, you talk about the CapEx potential to rise to sort of $500 million-$750 million per year to 15%-20% of group spend by 2030. Quite a big uplift. Would it be perhaps that this is where you're looking to save your dollars and keep your powder dry in terms of putting it into energy transition, again, over and above returning it back to shareholders? Thank you.
Let me start with your second question, this question of tax rate and deferral, perhaps Morten can give you some more granularity. As an oil and gas company, we need to replenish our volumes, unless we will decline. We have a very strong, healthy next generation portfolio to come on stream by 2022, bringing 3.2 billion barrels of equity to the company and shareholders. The 3.2 billion barrels is of the lifetime of those assets that we start up by 2022. Average break even $21, with an internal rate of return of more than 30%. I think that is a very attractive value proposition also for shareholders.
When we look at the unsanctioned portfolio and the opportunity space we see to take on more, we would like to take on more good projects so that we can keep giving a healthy return to the shareholders through those value propositions and those activities. Morten on the tax rate and deferred taxes, especially in the U.S.
Thank you very much, Christyan. I would also like to just refer back to the 2017 annual accounts, note 9 regards to the unrecognized deferred tax assets. There is quite some thresholds that we need to pass before we can start recognizing deferred tax assets. Before, we should be really confident before doing that, we will not go out with estimates. You can say that so far we have not recognized significant parts relating to our U.S. operations. That will come in when we pass these high thresholds given by the accounting standards. This is also driven by the technical requirements set from the accounting standards.
Before we go to the next question, can I just ask that we keep the questions tight? In fact, we're taking the questions in the order in which they are polled. We want to try to keep this call within the hour or only shortly after that. We still have around half a dozen to go. Can I ask to keep it to one, maximum two, definitely not three, and we'll try and get through this for the benefit of everybody. Thank you.
We will now move to our next question from Rob West from Redburn. Please go ahead.
Thank you very much. I'll keep them really quick, per Peter's suggestion. One, just with those Vestflanken online, could you update us on your reflections from doing that project and any future unmanned wellhead platforms that you feel are now more likely to go ahead now that you've learned the lessons from that one? Second question is back on shale, just the Marcellus and the ramp-ups that you've had there. Is that growth rate going in line with what you would have expected around the start of the year? Has something changed to unlock some extra growth, particularly from the Marcellus part of the shale portfolio? Thank you.
Well, on those by Vestflanken, a very profitable project, well executed, delivered at a cost more than 20% below the FID or the platform development and operation estimate. We'd love to look for a sort of on a copy-paste opportunity for that kind of thinking and development. On Marcellus and the Appalachian side.
I think at the CMU, we indicated the total production done for U.S. here, including the Appalachians, which is both non-op and the operated part that we're having. We are in line with what we said at the CMU. Things are going then according to plans.
Great. Thank you.
We will take our next question from Alwyn Thomas from Exane. Please go ahead.
Good morning. Just a couple of quick questions from me. Firstly, could I refer back to the Norwegian production question? We have seen some issues this year, some reported issues in May and also September by the NPD. Could you comment on the sort of reservoir across your portfolio and whether you're seeing decline rates higher than expected, and perhaps whether this should lead to higher drilling or maintenance CapEx into next year? If I may just ask the CapEx question in a slightly different way. If you say $ 10 billion is your base from this year, what makes it more expensive into next year and future years and bridging the gap? Thank you.
Well, on Norwegian production and the decline rate is as expected, meaning in accordance with the guidance of a 5% decline. The quality of assets on the Norwegian continental shelf is still very good. Still some tieback opportunities that we're looking at and infill wells and drilling. We do not see any sort of relationship between sort of this decline rate and the need to do sort of much more maintenance to sort of maintain the production level. This is more about infill drilling and tiebacks to fight this decline rate than anything else. The regularity of the assets in third quarter were up compared to second quarter, and very good results. On the CapEx and the around $10 billion in guidance for this year compared to then around $ 11 billion going forward. On the $11 billion, this is currently very healthy, steady.
Represents a healthy, steady activity level given the size and the capacity of our organization. I think that is key to take in. One of our key learnings through the downturn was that you never sanction a project before it is as good as it can get. It's very important now that the prices comes up, that we are not tempted to sanction projects because they're almost as good as they get. If we feel it's the right thing to do to send it back and have them to go through it one more time, we will continue doing so, because ultimately that is what really brings the cash to the company and value creation. The second learning is, you don't overstretch your organization, because if you do, then that will influence the whole sort of quality and the execution machine as such, as an organization.
If you want to sort of increase your activity level substantially, then you have to do something about the manning side so that you maintain sort of a good enough capacity. I'm not saying that people have slack in that organization, because that's far from the case. Overstretching is not good either. That was also part of the learning from the downturn. Bridging it from currently guidance of around $ 10 billion for this year and back to an average of $ 11 billion over the next couple of years. That is just to say that is the healthy, steady activity level. And we need to replicate over achievements in many ways on the execution level that we have done this year. I, fingers crossed, I hope for that to happen. We need to be prudent in our guidings externally as well as our planning internally.
This is sort of a P50 estimate of what we believe the ultimate spending will be given what we have our project portfolio for 2019 and 2020.
Okay. Thank you.
We will take our next question from John Olaisen from ABG.
Thank you for taking my question. First question on the CapEx. Does the lower CapEx plan for 2018 alter the guidance that you provided earlier this year of an average CapEx of $11 billion for the period 2018, 2019, 2020? That was my first question. On the second question, Lars Christian, you have experience now from both Norway, onshore North America, and also offshore internationally. Where do you think Equinor has the best competitive advantage of these three areas? Thank you.
On CapEx guiding, we have said $11 billion for the period average 2018-2020. That remains our guiding independent on us guiding around $10 billion for this year. If I look at to your second question onshore, offshore, whether it's international or in Norway. This is many ways you can slice this, I think, an answer to this. If I look at an oil and gas development, it is about four levers that you have to pull to make it work. One, it is about reservoir understanding, and we are among the best when it comes to that. Two, it is about drilling wells and being good at it. If you look at the external benchmark for the time being over the last couple of years, well, we've been ahead of the pack. Three, it is about building good, strong organizations.
I think both the Canadian development and then Brazil and whatever we have in Norway, to mention a few, we are good at attracting talent, local talent, and combine that with the experience of the mothership. Fourthly, it is about deploying technology. Technology development and technology is in our DNA, and this is about deploying it. For me, it's not whether it's offshore or onshore or one basin or the other. What we really need to continue looking for is the best assets, regardless of whether it's onshore or offshore or wherever. The only thing that we need to comply to, of course, is sanctions and the no-go zones that are put in place around the world. We adhere to that, definitely.
No difference whether it's onshore in Argentina or offshore in the Barents Sea in Norway, you are just as successful.
If it's a good asset in Barents Sea, I'm game. If it's a good asset in Argentina onshore, I'm game.
Sounds great. Thank you.
We will now move to our next question from Rafal Swiatkiewicz from Bank of America Merrill Lynch.
Good morning. Thank you for taking my question. Just drilling down back onto the CapEx guidance, apologies for this. In the last 3 months, what has specifically led to a $1 billion saving in your CapEx budget? Is it actually just release of contingency on things like Johan Sverdrup Phase 1, which you updated in August? Or is it actually deferring sanction decisions, for example, perhaps NOAKA this year? Or is it indeed a bit of rounding in there because it looks like it's to the nearest billion, correct me if I'm wrong. Secondly, just on exploration, given that you've done all these acquisitions this year, spending $1.5 billion on exploration this year, should we expect intensity on exploration to be consistent over the coming years? Or should we perhaps expect a pullback as you digest your acquisitions? Thank you.
Well, first of all, going from around $11 billion to around $10 billion is not necessarily equal to us reducing it by exactly $1.0 billion. There was a part 2 to that question, wasn't it?
Which?
CapEx side of it.
Contingency release.
Was it more on the CapEx side, or is it just.
Contingency release or deferring project sanctions. I just wanted to know what the split was on that, please, driving to a $1 billion saving.
Yeah. As I said, it's not exactly $1 billion in reduction since it's around $11 billion to around $10 billion. On those improvements, we do internally twice a year a full run through of all our projects. That was done recently. When we look at it, we see that across the board, regardless of whether it's a large project, big project or a small one. We see positive contributions in bringing down the overall CapEx spending for this year. It's impossible to pinpoint one explanation. The big bucket that contributes the most is stellar project execution. That's that part of it. On exploration, we have taken exploration acreage over the last couple of years and tried to high-grade drilling targets to feed the exploration machine, to put it like that. We maintain the guidance for this year at $1.5 billion.
We haven't given any indication of what to expect over the next couple of years, except that we have said on a number of drilling of wells, that we should expect a level between 30 - 40 wells year-on-year.
All right. Thank you for the color.
We will now take our next question from Robert Pulleyn from Morgan Stanley. Please go ahead.
Thank you, gentlemen. I have one question. Following on from your explanation of your disciplined approach and your operational success, may I ask a little bit around the opportunity set of future projects beyond Greater Carcará ? Because at some point, obviously the geology matters in terms of your opportunity set as to what IRRs and breakevens can be achieved. Does the opportunity set of what you have in the next 5 to 10 years hopper support this view that you can maintain this capital discipline and deliver similar breakevens and IRRs? Thank you very much.
This is a very key question, a very good one too. I think the industry for many years has said that the easy barrels are gone. From that aspect of it's more and more demanding to produce. Usually that means that they will also be somewhat more expensive compared to the easy barrels. Of course, there is another factor that counters this, and that is technology development. We have seen huge contributions in the area of technology development and have brought down then the cost per barrel, both when it comes to exploring, developing and producing. We expect that to continue. Digitalization is one area that will contribute in all these elements or part of the value chain for oil and gas development. The opportunity set around the world, yes, there is fierce competition for good assets.
I think that we have been able to demonstrate over the last couple of years an ability to be quite successful in taking on good assets and going forward, and that is our ambition. We will only take on projects that we are sure that can represent good value propositions and not erode value. Taking us back to the Capital Markets Day, we also said when we looked at the unsanctioned portfolio, that our average breakeven were brought down 30% over the last 12 months leading up to February, and giving us comfort that as we work then going forward, that we can still improve that portfolio somewhat more.
Thank you very much. I'm sure this topic will be revisited, in the interest of keeping it tight, I'll hand it over. Thank you.
We will now take our next question from Thomas Klein from RBC. Please go ahead.
Hi. Thank you for taking my question. We've been hearing about capital allocation this morning. I just wanted to ask one question on another potential aspect of this on offshore wind, and how you're seeing opportunities there. I know you recently signed an MoU with Petrobras, and Ideol in Poland before that. Any more color on this side would be helpful. Thank you.
Okay. Thank you. On the offshore wind, as you said, we signed an agreement earlier in Poland this year. We're looking into that one and working with that one. We also then secure positions then in U.S. that we're also working on maturing outside New York. In U.K., we have the Dogger Bank area. That is also what we are looking at. We are then looking if there are other opportunities that could fit as well. Currently those are the areas that we currently have in our portfolio.
Okay. Thank you.
Okay. Thank you.
We will take our next question from Giacomo Romeo from Macquarie. Please go ahead.
Hello. Thanks for taking my question. Only one very quick question from me. Just looking at the Roncador field, this is one of the fastest declining assets in the Campos Basin in Brazil in general. Just wondering if you can provide a bit more details on the opportunity set there for you. You discussed the improved recovery rate in the past, but when do you think we could start seeing improvement in decline rates? Attached to that, whether you see a greater opportunity from doing more work on mature assets in Brazil alongside Petrobras.
We have a very strong and good relationship with Petrobras. In the current environment in Brazil, we are able to progress our business and get the approvals. We have also a very good relationship with the authorities. In the case of Roncador, it's not that many months since we finalized that deal and started the bookings. That also means that was the opportunity for us to really be able to look into the books from the point of view to start looking at IOR opportunities, and we are in a very early phase of looking at those. We still believe that there is an opportunity and should be an opportunity to improve the recovery factor for that asset.
Thank you.
We will take our next question from Jason Kenney from Santander. Please go ahead.
Hi, good afternoon. Thanks for the question. I'm going to hark back over a decade to when your company, indeed many oil companies, were happy to talk about return on capital employed. I'm just thinking if you would be feeling more confident about setting return on capital employed targets in your Capital Markets Day in February. Obviously, you're enjoying the oil price ride at the moment, your underlying capital discipline, everything we've heard about capital allocation just through this call and through this year. What do you think is an acceptable through-cycle return on capital for a company of your size today?
Well, if I take you back to the CMU, we had a ROACE of 8% in 2017, we guided up to 12% in 2020 based on an oil price of $70 a barrel. On path to deliver 12% in 2020. We sort of guided at 10% in 2018. We are on good path and are comfortable as our ability to deliver on the 12% in 2020.
Thanks.
With that one, that's the final question that we're able to take today. Last one that we've had. Thank you to everybody. Always appreciate the calls and questions, and as ever, please contact IR if there's any further questions or follow-ups. I'd like to thank all my colleagues for joining us today. Remind you that the fourth quarter is on the 6th of February and will be accompanied by our Capital Markets Day in London, and we look forward to seeing you then. Thanks, everybody. Goodbye.