Earnings Call: Q3 2017

Oct 30, 2017

Thank you, and a very warm welcome to everybody here from Fornebu Poonen. Good morning to all. And as usual, this has been a very eventful quarter for Aker BP. I wonder when I'm going to stop going to say that. Production amounted to about 132,000 barrels of oil equivalent in the quarter and was impacted by planned maintenance at Valhall and Skav in particular. Based on the strong production in the first half of the year, maintenance behind us and the outlook for the Q4, we expect full year 2017 production to end in the upper half of the previously guided 135 to 140,000 barrels of oil equivalent guidance range. Despite the lower production in the quarter, we present an EBITDA of USD 395,000,000 amounting to an earnings per share of $0.33 The free cash flow was a record four $45,000,000 in the quarter, and Alexander will walk you through the details in a moment. The Board has resolved to pay out dividend of €0.185 per share in November, which is, of course, the same level as in the previous quarters. And then finally, last week, we announced the acquisition of Hasnorge AS, giving us a deeper exposure to one of our core areas, the Valhall area. I will come back both to the transaction and to Valhall in more detail later. On the operational side, we have put 2 new infill wells on stream, Volund, and are on track to deliver 3 PDOs before year end. Before I leave the floor to Alexander to walk you through the financial statements, let me share with you some highlights from the Aker BP acquisition of Hess Norge. In consideration, we paid USD 2,000,000,000 for Hess Dowerway. These deals give us 150,000,000 barrels of oil equivalent of additional 2P reserves and close to 200,000,000 barrels of additional 2C reserves. It brings our operational our ownership interest in the Valhall area up to 100%. We also take over Hestowe's tax losses at a nominal value of US1.5 billion dollars We think this is a very attractive deal both in terms of price, but most importantly in terms of the upside potential we see in Valhall. Valhall is 1 of Norway's largest oilfields. And since the start in 1982, Valhall and Hod have produced more than 1,000,000,000 barrels of oil equivalents. By aggressively targeting the upside potential, our ambition is to get at least another 500,000,000 barrels out of the field. The acquisition will be financed by drawing $1,500,000,000 on our existing RBL and $500,000,000 in new equity, which will be raised through a private placement in the market. Aker and BP will subscribe for their respective shares and have guaranteed for the rest at market or at the minimum of NOK 155 per share. Going forward, our plan is to pro actively pursue the upsides in the field, sanction new projects and thus convert resources to reserves by investing more into our into the asset. You will recognize this as a strategy that we have pursued also in the past. We subsequently intend to fob down an interest in the field to a party which we can work together with to target the unlocked upside potential in the area either against cash or other assets. We expect to retain about 67% ownership in the field following such a farm down. And then I'll leave the floor to Alexander to walk you through the financials. Thank you, Karl. Good morning, everyone. As usual, I will take you through the income statement, balance sheet and cash flows for the quarter. I'll also give you a bit of an update on the financing activities that we finalized during the quarter. And finally, I'll give you a bit of an update on the 2017 guidance. The is not reflected in any of these figures. This acquisition will be accounted for at the time of closing of the transaction. We recorded a total operating income of $596,000,000 during the quarter, of which petroleum revenues accounted for €601,000,000 on a production daily of 131,900 barrels of oil equivalents. Out of these 601,000,000 in petroleum revenues CHF508 1,000,000 came from sale of liquids at the realized oil price of $55 per barrel. Then we had 86,000,000 coming from sale of gas at the realized price of CHF0.20 per standard cubic meter. Production costs amounted to $134,000,000 This was an expected increase from the previous quarter. This equals to $11.10 per barrel of oil equivalent, and this includes shipping and handling costs of 3 point $0.20 If we look at the each of the hubs this quarter, we had production costs at Alvheim of $4.50 Ivarossen at around $12 per barrel Skarv, 13 dollars per barrel Walhall Hod, dollars 21 per barrel and Ula Tambo at $44 per barrel. Karl alluded to this, but the higher production cost per barrel on most of our fields this quarter was caused by lower production volumes and costs associated with planned maintenance during the quarter. Other OpEx, corporate G and A came in at €3,000,000 this quarter. Then we expensed exploration costs of $64,000,000 The main items here were dry hole costs of €21,000,000 related to the Hiropkin and Nourfjalla wells. Then we had acquisition of Seismic Data this quarter of €16,000,000 And we had other exploration expenses, which includes area fees. It includes field evaluation costs of $28,000,000 This gave us an EBITDA of $395,000,000 which is pretty much in line with the previous quarter. After we deduct depreciation of $175,000,000 or $14.50 per barrel, we get to a EBIT of €219,000,000 Net financial items were a negative €9,000,000 this quarter. That's much impacted by the strengthening of the NOKIs against U. S. Dollar during the quarter. Net interest expense were $27,000,000 This was down from $31,000,000 in the previous quarter. We had accretion expense of $33,000,000 in line with previous quarter. Then offsetting these two items, we saw financial income of $55,000,000 mainly from realized and unrealized gains on derivatives. Profit before taxes was then $207,000,000 The tax expense this quarter was €97,000,000 which gives us a tax rate of 46%. Included in this amount was a payable tax of €66,000,000 and we had a change in deferred tax of €28,000,000 euros So despite a quarter with planned maintenance, we saw a record net profit for the quarter of $112,000,000 or $0.33 per share. Our balance sheet is down approximately $200,000,000 in the quarter, ending at SEK 9,100,000,000 at September 30. Both goodwill and other intangible assets were virtually unchanged from the previous quarter. Net of depreciation, property, plant and equipment came in at €4,800,000,000 It was a slight increase of €57,000,000 compared to previous quarter. Receivables and other assets were 1,000,000 at the end of the quarter. That's a small decrease from the previous quarter of around $18,000,000 This was mainly related to a decrease in accounts receivable, but partially offset by changes in short term receivables, inventories and short term derivatives. The short term tax receivable has, as expected, been reduced this quarter after a tax refund of CHF264 1,000,000 was disbursed. The remaining balance of CHF145 1,000,000 is expected to be paid out during the Q4. Cash and cash equivalents were €81,000,000 at the end of the quarter. On the other side of the balance sheet, book equity was DKK2.5 billion at the end of the quarter, up from the previous quarter due to the profit we saw this quarter. Other provisions for liabilities were unchanged at CHF2.3 billion. Deferred taxes increased by SEK12 1,000,000 during the quarter and ended up at about SEK1.14 billion. Book value of interest bearing debt was SEK2 1,000,000,000 at the end of the quarter. This comprises of 1 $400,000,000 drawn on the reserve based lending facility CHF626 1,000,000 relating to the 2 bonds that we have outstanding. Other current liabilities, this increased about €50,000,000 during the quarter to €882,000,000 This reflects an increase in short term abandonment provisions and other current liabilities. And then finally, we had tax payables of SEK265 1,000,000, which about SEK180 1,000,000 is expected short term tax payments. Now again, do keep in mind that this does not reflect any of the effects seen from the Hess transaction that Carla discussed a couple of minutes ago. On the back of a continued strong production in the quarter and the one off tax effects in the quarter, we generated cash flows from operation of SEK 7 €30,000,000 Cash flows from investing activities were €285,000,000 Of this, we had investments in fixed assets of €226,000,000 where Johan Sverdrup accounted for 75 $1,000,000 Alvheim, and that's mainly the Boa infill wells, accounted for around 40,000,000 Ivar Ossen accounted for €21,000,000 Vallar Hod 20, Ula Tambar In addition to these investments in fixed assets, we had investments in intangible assets of CHF33 1,000,000 and we had decommissioning payments of SEK27 1,000,000. The latter mainly related to the Maersk Invincible drilling rig and its P and A activities at Valhall. Thus, we had a free cash flow from the quarter in the quarter of CHF445 1,000,000. Cash flow from financing activities includes the cash effects of the $400,000,000 new bond issuance and the repayment of the Detnor 3 subordinated bond. In addition, we repaid around $410,000,000 on the RBL during the quarter for cash management purposes, and we also paid out $62,500,000 in dividends. The end of June cash balance of €81,000,000 and book value of net interest bearing debt was SEK1.94 billion, and that's down around SEK360 1,000,000 from the previous quarter. We had net debt over EBITDAX. It decreased from 1.1x to 1.0 and we had available liquidity of around $2,600,000,000 As previously communicated, the $550,000,000 RCF was canceled during the quarter. We also finalized the process of amending and simplifying the $4,000,000,000 reserve based lending facility. The facility amount and tenure is unchanged, and the facility still has a uncommitted $1,000,000,000 accordion option. The available amount is now determined annually based on a per barrel multiple, and we have full access to the $4,000,000,000 amount. The interest rate is LIBOR plus a margin between 2% 3% based on how much of the facility that is strong. Year to date 2017, our free cash flow and that is cash from operation less cash spent on investments has been $746,000,000 while we in the same period have paid out 1 100 €188,000,000 in dividends. This equates to a free cash flow cover of almost 4 times. Even if we adjust for the one off tax effects we saw this quarter, free cash flow coverage in the 1st three quarters were about 2.5x. In the past three quarters, we paid out a quarterly dividend of CHF62,500,000 and the Board has resolved to also pay a dividend of CHF62,500,000 in November. With the strong cash flow generation in 2017, the robust balance sheet of the company and the further strengthening of our earnings capacity following the Hess transaction, we announced last week an increase in annual dividends by €100,000,000 to €350,000,000 per year, with the first uplift from the 4th quarter now in 2017, meaning So when it comes to the 2017 full year guidance, we're only making some minor changes to the guidance today. Again, note that we are not including any effects from the Hess transaction. With the planned maintenance in the Q3 behind us, we see that it's likely we will achieve the upper half of the full year guidance on production between 135,000 and 140,000 barrels per day. Production cost has averaged $9.9 per barrel in the 1st 9 months. And with sustained high production in the Q4, we stick to the original guidance of $10 per barrel for the full year. CapEx for the 1st 9 months amounted to $663,000,000 whereas we still expect a total spend for the year to lie between $900,000 $9.50 Cash spent on exploration was SEK196,000,000 in the 1st 9 months of this year. We make no changes to the full year guidance of CHF280,000,000 to CHF 300,000,000. As for decommissioning costs, cash spent was €55,000,000 in the 1st 9 months of the year. Due to lower expected full year spend and slight change to scope, we now see total 2017 commissioning costs to be in the range of $80,000,000 to $90,000,000 Note that while the original guidance was based on a dollar NOK exchange rate of 8.5%, we now adjust the point forward guidance to be based on an exchange rate of 8. When it comes to guidance for 2018 and effects of the Hess transaction, this is something we will cover in our Capital Markets Day, which is planned for January next year. That concludes my financial section. And I will let Carla walk you through our operations. Thank you, Alexander. Well, while we have been busy on the M and A front, there is no less activity on the operation side. So I'll spend a little time today walking you through the key highlights of this quarter. Now Alexander started out by saying that we hadn't included the Hess effects of the Hess transaction. In this slide, I've cheated a little bit and for illustration purposes included the Hess volumes from effective date of 1st January 2017 to illustrate the production development in Aker BP from early 2015 and onwards. As we've already discussed, we have achieved a production level of 132,000 barrels of oil equivalent in Q3. And this is somewhat down from the levels that we've seen in the first half, mainly due to planned activities and some normal depletion as predicted earlier in the fields. Last quarter, we increased our guidance from 128,000 to 135,000 up to 135,000 to 140,000 barrels of oil equivalents per day. On the back of better than expected production, especially from the Alhall area, the fact that we have maintenance behind us and the recent updates from the operation, we expect the production to end up in the upper half of this 100 and 35,000 to 140,000 barrels of oil equivalent range. On pricing, we achieved an average oil price of $55 per barrel in the quarter versus Brent at $52 per barrel. The premium of $3 is higher than normal and mostly driven by favorable timing of lifting activities in the quarter. I think it's only natural to start this asset review with Valhall as we will be the 100 percent owner of the asset when the Hess transaction is completed. Valhall started production already in 1982, and the field center today consists of 6 separate steel platforms, including a process and accommodation platform that was put in place in 2013, preparing the field for decades of production. Production from the Wallach area was lower in Q3 than in Q2, mainly driven by planned maintenance and temporary shutdown of wells related to drilling and well operations that are ongoing at the field. The IP, that's the well drilling center program is well underway, and this will add 7 new production wells in the central part of the field. The drilling performance has been excellent to date and this is exemplified by the last well, which was shortest completion time of any well ever recorded on Valhall IP. The Valhall area contains massive in place volumes and only just over a quarter of the in in place volumes have been produced to date. Our ambition is to produce at least another 500,000,000 barrels in the coming years, and I fully expect that we can increase this number over time as we continue to work the assets. Going forward, we are applying new technology to increase field recovery. This includes multilateral wells that we have a lot of experience with from the Alvheim area, new completion techniques to replace fracking in the Chalk reservoir, improved monitoring and modeling, which in turn leads to better production and better decisions and increased oil recovery And we are also applying new technology to radically reduce time per well in relation to our P and A activities. I will come back to some of these programs later. In addition, we have initiated a series of projects where digital technologies are reduced are induced to reduce cost and increase productivity. As you know, we are working towards a PDO for the Valhall Flank West by year end. This will be developed by an unmanned wellhead platform with 12 well slots tied back to the field center. We will revert to the market with more details on CapEx and reserves for the Waaland flank West as the PDO is finished. What I can say at this stage is that we consider this a highly attractive project both in terms of CapEx per barrel and in terms of break even oil price. We also have a long list of additional projects in the Valhall area that are at different stages in terms of maturity and which we are working on in order to convert more resources to reserves and eventually production volumes going forward. I think many of you will recognize that this is basically the same strategy that we have pursued successfully in the Alvheim area in the past few years. And then speaking of Alvheim, our production in the Alvheim area was slightly down in Q3 compared to Q2. Production was impacted negatively by some outages in the Sage gas export pipeline and a planned emergency shutdown test. Still, the production efficiency was 96% underlying the strong operation performance of this asset. 2 new Vallal wells were bought on stream in Q3 and have shown excellent production so far. The Vaipakopra wells, which have contributed strongly the Alvheim production this year, is also being produced through the Wollern subsea manifold and have been choked down to make room for the new Wallen wells. The next infill drilling target is Boa, and we have started drilling of the first of 2 infill wells at Boa. In parallel, we are planning to submit a PDO for Storklakken before year end. Storklakken will be developed as a subsidy tieback to Alvib FPSO via the Velje pipeline, and we expect first oil in 2020. At Iverosten, things are basically developing as planned. The facilities have been working flawlessly and the operational availability in Q3 was a staggering 97%. We did, however, experience some power issues also in Q3, which has brought the overall production efficiency down to 82%, resulting in a slight dip in production. The overall scope in the PDO has now been completed, that is all systems up and running, all wells drilled. And in Q4, we expect to increase production from the Eva Osten field in line with the capacity agreement with Edvard Grieg. In fact, the field has reached its projected plateau already 1 year ahead of plan. The next step for Eeva Ous now is to drill another 2 water injectors in the east part of the field for pressure support. And we also plan to drill an appraisal well at Hans, which is a tieback to the First oil of Hans is expected in 2020. In addition and in as we normally do on all our fields, we have initiated an IOR program at Diversen aiming at increasing reserves and recovery over time, basically the same strategy. Production from Ula and Tamba is dominated by a few wells and is highly dependent on the effect of water alternating gas injection. Due to the simplicity of this injection activity, production is also likely to fluctuate from quarter to quarter. And in Q3, we experienced a slight downtick in production, while we in the previous quarter saw a significant increase. The Tambor redevelopment project is progressing on track, and we have now commenced drilling of the first of 2 new wells. We are also installing a new gas lift module to facilitate the Tambah production. 1st oil from the new Tambah wells is expected early next year. This Tamba story demonstrates Aker BP capability, capacity and willingness to invest to create value on Norwegian Continental Shelf. It's a great example of what we are aiming for achieving on all our mature assets. Before we took over operatorship, Tamba was heading for decommissioning. Only 1 year later, we have shot Nusasberg and now started drilling new wells to revitalize the field. This will create value for our shareholders and for the society and is a solid demonstration of our strategy in existing fields. The Oda field, which will be developed as a subsidy tie back to Ola is also moving forward. Even though Ula is a small part of our portfolio, it will have a positive impact on Ula for providing additional injection gas and reducing the unit cost when it starts production in 2019. On Skow, the production also dropped somewhat in Q3. This is mainly driven by planned maintenance, but it's also driven by 2 wells that are shut in due to technical issues. The Snug test producer reached its annual production volume limit earlier in Q3 and is also shut in for this reason. We are currently running a rig operation in order to recomplete the 2 shut in wells. And if operations go smoothly, we'll bring the wells back on stream in Q4. The main growth initiative at Skaav is the development of the Snod reservoir, and we are on track to deliver a PDO for Snod by year end. Snod will be a 2 phase development and each phase will consist of 3 subsea wells and associated tieback. Phase 1 will commence next year with 1st gas in 2020 and with a CapEx of roughly NOK6 1,000,000,000. Thereafter, we will do Phase 2, which is basically a repeat of Phase 1 for the other half of Snad. This will secure high utilization of the Alvheim FPSO for years to come. Now SNAAD is also a technology project where the first application of directly electrical heated pipe in pipe will allow for a long tieback. We're really excited about participating in the development and utilization of new technology also on Snod. On Johan Sverdrup, the story just keeps getting better. Shore as you can see in the picture and there is good progress on the drilling side as well. The project is firmly on track for first oil in 2019 and the cost estimates for Phase 1 has been further reduced since last quarter from NOK97 1,000,000,000 down to NOK92 1,000,000,000. 3Q has been a quarter impacted by activities related to maintenance and modification on our installations. This kind of activity is for us an integral part of how we run our operations maintenance and modification ongoing. The industry has for the last few years been reducing the MMO scope on the Norwegian continental Shelf. In Aker BP, we believe in pursuing a strategy where we aim to maximize productivity to ensure that we deliver as much scope as we possibly can for every input unit factor. The key reasons for this project is to pave the way for increased production, increased uptime, increased lifetime, facilitate tieback and in general reduce cost per barrel over time. We are really proud of activities that are currently ongoing on our assets. And in the same line of manner, the improvement program is starting to show tangible results. We are building strategic partnerships and our efforts to rearrange the value chain, align incentives and deliver projects more effectively is starting to show tangible results. One example is the Volund Infill project where we utilized the Subsea alliance with Aker Solutions and Subsea 7 and delivered a project 30% below budget where we've also reduced, as you can see on the graph, for market effects of another 30%. We will continue to work on this strategy and deliver more alliances in the time to come. Another good example of how we work on continuous improvement is the P and A campaign at Valhall. VP started this P A activity and as you can see had really good results from 2014 to 2016. Aker BP commenced on a new campaign earlier this year with a new rig. And by applying the learnings from the BP campaign, continuous improvement and applying the latest and best technology available, we've been able to continue the positive development and increase the speed. The last 2 wells have, in fact, been plugged in less than 30 days. In addition, we are progressing our vision of a fully digitalized value chain Following a process where we systematically assessed ongoing initiatives in the industry as well as other opportunities in other industries, we decided to support the creation of a new company called Cognite where we today own 10%. The main objective behind the establishment of Cognite is to create a data platform based on open architecture, well documented interfaces and with a data architecture general enough to handle all our data. The mantra will be that all data should be available always on any platform. In Aker BP, we believe that the challenges posed to this industry cannot be solved alone and that all solutions to be used by Aker BP in the future must support open architecture. Further, we firmly believe that sharing of data between the companies is a prerequisite for success and that no one company can solve all these challenges alone. All these activities are aimed at increasing productivity and reducing cost, which will allow us to do more projects and add more projects to the portfolio with breakeven of less than $25 per barrel. Now moving on to the exploration drilling activity. The Hiroken and L'Nurfjal prospects were drilled during the quarter, both unfortunately dry. The Delta appraisal well provided us with valuable information about the Fregama Delta discovery, and we're now in the process of analyzing the data in order to confirm the reserve estimates for the field. Drilling on the Lunin operated Hufsa prospect started earlier this month and results are expected shortly. After drilling of this well is completed, we will move on to drill the Hary prospect in the same license. Now while the results of the 2017 drilling campaign in the Barents Sea could have been better, we are still excited about our 2018 Barents Sea campaign. Next year, we plan to participate in 4 to 6 wells in the Barents Sea, including Stang Nestinden well on the Fedinski high and Svaanfjaller on the east side of the Lotbaj high. We will revert to the 2018 drilling schedule in the Capital Market Day in January, and this will include predrill estimates for the different wells we plan to drill. Now before we round off and open for Q and A, let me summarize our main priorities ahead. Please note that this slide is basically unchanged since last quarter. On the execution side, we continue to work hard to deliver efficient and safe operations with focus on optimizing production and keeping cost at bay and without any HSE incidents. We also remain firm in our ambition to submit 3 PDOs by year end. And as we are closing in on the deadline, we remain optimistic that we can achieve this. We continue our improvement program, which is not a traditional cost cutting exercise as I've tried to demonstrate. Instead, our ambition is to make radical changes to the way we work in order to achieve step changes in efficiency and cost. Three examples. New collaboration models with suppliers will allow us to increase productivity and reduce cost. Redecide the work processes will achieve better flow efficiency, higher productivity and ultimately lower cost as demonstrated in the InvinciBull P and A case. And finally, digitalization in order to increase value of data and speed up our decision processes will enforce the previous 2 mentioned projects. Our overarching threshold for new development is a breakeven below $35 per barrel. This is an ambitious target, which instills a huge amount of discipline in the organization and which will, over time, translate into attractive returns for all our shareholders. On the growth side of our business, we are planned for increased exploration activity next year. Alexander already alluded to the fact that we have increased seismic acquisition in Q3. While we're also working to mature the contingent resources in the vicinity of our field in parallel with the ongoing exploration activity. And finally, as illustrated by the Hess acquisition, we continue to pursue selective organic growth opportunities where the aim is to enhance production and increase dividend capacity. That concludes our presentation of today, and we will now open up for questions. Jonas and Tore, will you assist us? Taylor Nielsen, SPO Markets. First on Malala, really exciting this project to convert resources into reserves. But should we expect any impact on the year end 20 17 reserves by the current project? Or should we look more into year end 2018 to see any material impact on the 2P reserves? We will when we get to the Capital Markets Day update on the end of 2017. I think the expectation would be that if we manage to successfully sanction projects and deliver PDOs before we go on Christmas holiday, that would impact conversion of those projects from resources into reserves. Okay. That's clear. And for Q3, the P and L tax rate was very low. Could you provide some color on that? And should we expect the tax rate to stay that low, the P and L tax rate? The P and L tax rate. So as you know and you'll find it in the back of the financial statements, it's a very complex tax calculation. And what impacts it is the change in FX rates, because as you know that is calculated in Norwegian krones when you do the taxes then converted. So this year this quarter it is low, but FX materially impacts that. So lots of details in the tax note where you can see the changes in temporary differences and how that rolls into the change in deferred taxes. I mentioned the tax the payable tax, which is part of the P and L tax rate. And that is impacted by the tax payment we had this quarter. And again, as you know, already in May of this year, we need to estimate what we think the payable tax will be. And there's 3 installments in the fall of this year and then there's 3 installments in the beginning of next year. So there was one installment during the quarter which gave that element of the P and L tax. But the change in deferred tax is, of course, the tricky one, which is made in Nokia. So but how extrapolating how that will be going forward is somewhat difficult. Yes, I'm sorry. And then finally on M and A, you say that you will continue to pursue M and A opportunities, which, of course, makes sense in this part of the cycle. Do you still see sufficient opportunities in Norway? Or will you consider to also broaden the portfolio outside Norway? I'll leave that to Karl. We have this agreement. We are a Norwegian pure play company. So Aker BP will not pursue M and A activities outside of Norway, maybe with the expectation where there might be cross border issues related to fields and operations that we have ongoing on the Norwegian continental shelf. Yes, we see lots of opportunities in Norway still, but they may not be that easily transparent from outside. Maurice Lorentzon from E24. I have two questions for you. The first is on your commission expenses, if you could elaborate on that increase and where it's coming from? And the second question is about your power issues with Eeva Rosen towards Zwargregg. Are those resolved now or do you expect further challenges throughout the year? So the first one, Marius, was about decommissioning. Yes, the decommissioning cost that you're Yes. And it's decreased, not increased. Sorry. My Yes. That's okay. But could you elaborate on where that's coming from? Yes. So the decrease in the decom expense, it's just a slight change of scope in 2017. Karl did talk about the operations of Maschke Invincible and how that rig who's doing the P and A activity has been better than expected. But that rig is still on contract for the full year. So we're not seeing any efficiencies as such going into that CapEx spend this year. That would be more in later year, we'd see effects of that. So it's not a big change, but it's predominantly on the timing and scope this year. And then on the power issues with that project. We've we're working first of all, we're working very well with Lundin to solve the power issues. The collaboration is extremely good. The work is ongoing to resolve the power issues, and we are confident that we will resolve them shortly. In addition, we're taking compensating measures by running our essential field. Yes. Hello. Ivo Bartwick from ABN AMRO. Just a question on the snub technology development there and the heated pipe in pipe technology, how much that means for the breakeven on the project, the different suppliers of that solution and the technology risk associated to using that technology, if you could help us understand that a bit better? Yes, Heated directly heated pipeline has been used in the industry for a number of years. This is the first time we've used or are going to use directly heated pipe in pipe, meaning you have an inner pipe and an outer pipe. And then you have the insulation and the heating within the annulus between these pipes. Both Subsea 7 and Technip are in the process of qualifying this technology. It has been used elsewhere with great success. And in terms of application, this is mostly about extending tieback areas and reducing costs related to flow assurance. Otherwise, you would have to inject chemical engines into the pipeline stream to reduce hydrate risk, etcetera, etcetera. We firmly believe that this is a technology that not necessarily carry extra costs and extra risk on the execution, but it's still technology that needs to be qualified and brought forward. It will also be technology that will allow further tiebacks for other operators on the Norwegian continental shelf. And on the economic impact for the fleet? Well, of course, it reduced cost. And as much as we are reducing the need of utility equipment that we will otherwise use to guarantee flow assurance through the pipelines, such as mag rotation, migration on the FPSO, etcetera, etcetera. We have a few questions from the web as well. Let's start off. I think this question was partially answered earlier from Marius' question, but Rafael Gutage at Bank of America is asking whether the decomm costs, the reduction there is a one off or if we can extrapolate that run rate into 2018? Okay. Sounds a bit similar. Again, it's a slight change of scope this year. The stellar performance on the Maersk Invincible rig will not have an impact this year, but that will be hopefully seen going forward. When it comes to the and also do keep in mind that the decommissioning guidance we had this year, it did not cater for a full year with the Maschke Invincible rig. So we'll be updating that guidance for 2018 with a full year of Maschke Invincible operating. Okay. And we'll take a question from Alvin Thomas at Exane. How long will the MPD allow you to keep 100% of Valhall? Well, as we've already stated, our full intention is to sell down the to 67% roughly, either in terms of cash or in terms of a swap. So we do expect that there will be a condition from the Ministry of Oil and Energy of a sell down. Our intention is to do this as expediously as we possibly can while still catering for the fact that we do intend to sanction a number of projects in the next few months. Okay. We'll take a question from David Merzat at Deutsche. We had expected 2 weeks of planned maintenance on Greater Alvheim in the Q3. Why was this not performed? And second question is can you give us more color on the key risks of the Hurry and Hafsa wells? Maybe I wasn't 100% clear. We did perform maintenance stop on Alvheim this year, but we managed to short the duration from the Pronoz to 14 days. The main activity in that Alvheim shutdown was a test of the emergency shutdown system that was initiated at the commencement of the maintenance stop. Now the Hafsa and Hoeghi wells are in the same area as Filiqudi. That means that these traps in an extension basin. So while I won't go into specifics risks on these wells, the general risks in this area, meaning reservoir placement, reservoir quality and caprock and ceiling are the key risks of those 2 wells. Okay. And then a question from Ryan O'Sullivan at Citi. Could you provide more detail on the tax refund following the liquidation of BP Norway? Is there likely to be further refunds related to the liquidation? Okay. So the tax payment of €264,000,000 in the 3rd quarter, that solely relates to the tax loss that was sitting in BP Norway when that was related to the exploration related to the exploration activities that we had that will be reimbursed this year. And that is happening because we had a tax loss in 2016. So there's no further refunds expected from BP Norway. Now the tax effects of the Hess transaction we talked about earlier in the week or last week, but that is not included in any of these in these figures that are accounted for this quarter. Okay. We'll take a couple of questions from Nicky Kuzmanov at Jefferies. First related to the Hess acquisition. The working capital assumption upon completion, is that expected to reduce or increase the US2 $1,000,000,000 headline consideration? And the question why do you raise US500 million dollars of equity if paid back within 5 years of increased dividends? Okay. So the first one first. The effective date of the HES transaction is January 1, 2017. That means we'll be going through all activities and operations in 2017 and there will be a pro counter settlement upon closing, which is expected before year end. Now what that number will be based on all activities during the year, that is a bit too early to say, but that will be announced upon closing of the transaction. When it comes to the equity raise, well, we are in the fortunate position to have very supportive shareholders and raising equity as part of this transaction and making sure we have the robust balance sheet going forward, we think is a great position to be in. So raising that equity, having that robust balance sheet and being able to do further organic or inorganic opportunities, we think is a great spot to be in. Yes. And in addition, as Alexander already pointed out in the demonstration, the cash generation in Aker BP in the past quarters has more than supported the dividend policy that we have had. And looking forward, with with increased production, increased capacity, we thought it prudent to also cater for a bit higher dividend yield in the share. And the last question from Nicky is related to Stordklokken. Can we expect any Vilya choke back due to the share infrastructure by that time in 2020 when Stolklokken starts producing? That, of course, remains a bit to be seen. Our assumption as of today is that there will be sufficient volume in the pipeline to cater for both projects. That's all from the web. Then I say thank you for coming here to the 3 quarter day presentation, and have a safe journey home.