Earnings Call: Q2 2018

Jul 13, 2018

On the financial side, there are no big surprises. The EBITDA amounted to US735 million dollars which is the highest result ever in a quarter for the company and was obviously positively impacted by higher oil and gas prices. Free cash flow was $211,000,000 which remained well above our dividend, which amounted to $112,000,000 in the quarter. Looking forward, we have a lot of exciting opportunities and activities coming up, both on the exploration side, on the digitalization side and on the further development of the Frosk discovery. I will come back to all of this in significant detail later on. But first of all, I'll let our eminent CFO, Alexander Kane, take you through the financial statements. Alexander, the floor is yours. Quarter based on production of 157,800 barrels of oil equivalents per day. We realized an oil price of $76.42 per barrel, which is up 11% this quarter. We had a pretty stable gas price. We realized a CAD0.28 per square cubic meter, which is equal to the same price in Q1. We had production expenses of $164,000,000 This is a reduction of $10,000,000 from the previous quarter. With the exception of Scarf, we saw a decrease in OpEx across all assets due to less well maintenance, less supply based cost, less shipping and handling and also some reallocations and reclassifications to CapEx including R and D. So overall, we had production costs per barrel of $11.40 which compares to $12.10 in the previous quarter. In the Alvheim area, we had costs of $30,000,000 or $5.40 per barrel. On Ivarossen, we had costs of $17,000,000 This equals to 7.9 $0 per barrel compared to $10 3 months ago. Vallalar HOD production costs amounted to 52 $1,000,000 down $6 from the previous quarter. This is equivalent to a drop from $18.50 per barrel to 17 dollars per barrel. Production costs on Ula Tambar amounted to $29,000,000 This is down from $34,000,000 in the previous quarter. This cost reduction combined with the increase in production seen from the Tambar wells pushed OpEx per barrel down from $46 per barrel in the previous quarter to $29 this quarter. On Skariv, we spent $5,000,000 more this quarter ending at 31 $1,000,000 or $12.30 per barrel. Not surprisingly, this increase comes as a result of the well maintenance work undertaken in the quarter and Kalle will revert to this topic in a few minutes. We then had EBITDAX of $810,000,000 in the quarter. We had exploration expenses of $75,000,000 Here, we have expensed $30,000,000 in seismic acquisition for new surveys in the Barents Sea. We also expensed the Svanfjall well for another SEK 18,000,000. In addition, we have the usual field evaluation costs, area fees and other exploration expenses that make up the balance of the total exploration expenses. We then had EBIT come in at SEK 735,000,000 for the quarter. Depreciation was $182,000,000 or about $12.70 per barrel. We had net financial expenses of SEK22 1,000,000 in the quarter versus an expense of SEK47 1,000,000 in the previous quarter. The positive change here compared to Q1 is mainly explained by currency effects and unrealized gains on derivatives. As usual, we have no disclosures that shows the various items that make up the net financial items in the quarter. This time, you can find them in note disclosure number 6. Then profit before taxes was €530,000,000 and we had a tax expense of $394,000,000 This gives us a tax rate of 74% compared to 62% in the previous quarter. Here, the higher tax rate is also explained by the currency effects of the U. S. Dollar strengthening against NOK going from NOK 7.84 at the end of the first quarter to 8 0.2 during this quarter. We then had net profit ending at SEK136,000,000 for the quarter. At the end of the second quarter, goodwill was unchanged at SEK1.860 billion, while other intangible assets were slightly down, but still booked at SEK1.99 billion. Net of depreciation, the total PP and E balance increased by SEK170,000,000 to SEK5.8 billion at the end of the quarter. Here, we had additions of SEK 338,000,000 and depreciations of SEK 167 1,000,000 Receivables and other assets were SEK820 1,000,000 at the end of the quarter. That's an increase of about NOK 57 1,000,000 in the quarter. Then the short term tax receivable related to the tax loss in Hess Norge is valued at SEK1.6 billion at the end of the quarter. The decrease in value of about $70,000,000 relates to revaluation of NOK balances as this is a NOK denominated tax loss sitting in the subsidiary Aker BPAS, previously known as Hess Norge AS. Cash and cash equivalents were SEK 49,000,000 thus bringing the total assets to SEK 12 point 1,000,000,000 at June 30, which is approximately the same as the last quarter. If we move to the other side of the balance sheet, equity was 3.64 $1,000,000,000 at the end of the quarter. This is a decrease of about $47,000,000 during the quarter, where the positive net result for the period of SEK136,000,000 was more than offset by a negative currency translation adjustment flowing through the OCI of SEK70 1,000,000 and the dividend payout of SEK112.5 million. Other provisions for liabilities increased slightly, sitting at SEK2.99 billion. Then we had deferred taxes amounting to around $1,500,000,000 and this reflects an increase of $168,000,000 during the quarter. This balance arises due to differences between tax and accounting. This quarter, the change can primarily be explained by higher tax depreciation than accounting depreciation, revaluation of tax balances due to FX and capitalized exploration costs, interest and actual decommissioning costs that were expensed for tax purposes. Book value of interest bearing debt, which consists of the bonds and the bank debt we have issued were SEK 3,000,000,000 at the end of the quarter. We then had an accrual for tax payable of SEK687 1,000,000 at the end of Q2. The most significant items here are the 2018 tax payable of €439,000,000 and an accrual for uncertain tax positions of SEK205,000,000 Other liabilities decreased from SEK 923 1,000,000 to SEK 861 1,000,000 in the quarter. This is mainly driven by a reduction in trade creditors and short term abandonment provisions. Cash flow from operations was SEK613,000,000 in the quarter. Cash flows from investing activities totaled $403,000,000 of which run $300,000,000 related to investments in fixed assets. Here, Valhall and Hod accounted for NOK98 1,000,000 Johan Sverdrup accounted for NOK88 1,000,000 and Ula Tamberg worth around €22,000,000 We also recorded decommissioning payments of €72,000,000 mainly related to the Maersk invincible running P and A activities at Valhall. We also had capitalized interest of SEK29 1,000,000 included in this figure. Thus, free cash flow was SEK210 1,000,000 in the quarter. On the financing side, we repaid another SEK65 1,000,000 on the RBL and we now have SEK3.6 billion of committed undrawn available capacity on our $4,000,000,000 bank facility. In addition, we paid out $112,500,000 in dividends during the quarter. At the end of the quarter, our cash balance was then $49,000,000 and the book value of the net interest bearing debt was SEK 3,000,000,000. Net debt over EBITDAX was lowered again. It's now down to 1.1 times. We still have the SEK1.5 billion bridge loan included in this net debt figure, whilst the SEK1.6 billion tax receivable is not included here. We are still expecting to see a disbursement of this tax loss in the second half of twenty eighteen. And finally, we are making some slight changes to our guidance for the full year of 2018. We still expect to see production average between 155,000 and 60,000 barrels of oil equivalents per day and we expect production cost to remain at around $12 per barrel. The run rate on CapEx in the 1st 6 months of the year has been lower than the estimate for the average for the year. We expect spending to be higher in the second half of the year when some projects like the Valhall projects are going into a more capital intensive phase. Therefore, we maintain our CapEx guidance of SEK1.3 billion. When it comes to spending on abandonment, we are reducing our estimate here from SEK350,000,000 to 250 $1,000,000 The Maersk Invincible rig is running ahead of schedule and we now expect to finalize its current P and A scope by the end of September. This means that we can move the rig over to the Valhall Flank North project in the 4th quarter and hence reduced spending on FX. This acceleration of scope on Valhall is now included in the CapEx guidance for the year. We're also upsizing our expected spending on exploration activities from SEK350,000,000 to SEK 425,000,000. There's 3 key reasons for this change. First, due to the success at the Frosk discovery, we've managed to secure a rig and commence drilling of another 2 wells in that area later this year. And secondly, we are investing more in seismic, mainly in acreage connected to the recent license awards. And thirdly, we are still booking costs related to Nuaka as field evaluation costs and part of exploration until a concept is selected by the partnerships. Now I will leave to Karl to talk more about these topics and more in his operational review. On operations, and this time, we'll go through the assets by assets, and I'll highlight the key elements and the key developments as we move along. So as usual, first of all, we'll start with Alvheim. The Alvheim area continues to be a success story for Aker BP. The production efficiency is high. In fact, it's almost world class with a high performing FPSO. The production cost remained slow in this quarter, averaging at $5.4 per barrel. And we have continued exploration success near existing infrastructure, which means every barrel has high value. When we took over our Alvheim about 4 years ago, production was on the decline, and we have subsequently managed to rest decline through a combination of relentless focus on operational efficiency and data gathering as well as drilling out resources in the area. This has contributed to solid revenues and low production costs. We continue to follow this strategy. And we have a lot of activities going on at Alvheim at the moment. Earlier this year, 2 new wells at the Boa reservoir were put on stream. These wells are now giving good contribution to production. And we are currently drilling another infill well at the Kamilian reservoir, which we'll put on stream later this year. In addition, we are drilling later this year an appraisal well at Gekko to prepare for further infill wells in the future. We have also embarked on the Skogul field development, which will be subsea well number 35 in the Alfheim area when it's put on production in early 2020. And we are also ramping up exploration activity in the Alfheim area. In the Q1 this year, we drilled the Frosk exploration well near Bola. The Bola, which you may know, is a tie back to Alfheim. This well proved up 30,000,000 to 60,000,000 barrels in resources, which was significantly larger than our pre drill estimates. The reservoir was found in an inject type structure with a high angle as shown on the picture in the illustration. These structures are hard to see on seismic and following the VIPKUBRA wells last year, Aker BP has developed in conjunction with our collaboration partners a seismic imaging tool allowing us to map such high angle injectites. This prospect discovery has paved the way for more exploration in the area, and we plan to drill 2 additional prospects later this year in the neighboring license, production license 869, where we have a 60% interest following a recent transaction. These 2 new prospects are named and Rumpetrol, both great Norwegian names, which probably can be translated to something like froglag and tadpole. And the combined gross power resource estimates is non is not impacted by the choice of names and rest at around 60,000,000 to 200,000,000 barrels, which even in the low end of the range would represent a significant resource addition for the Alvheim area and compound to further success low cost and high value in the Alvheim area. For the next step, we plan to embark on early next year is to drill a new well in Frosk, which will be used for test production through the Beyla template. I'm actually extremely pleased that we are able to start production only 1 year after discovery was made. The learnings from the FOSC test producers and the results from the upcoming exploration well will help us define the best development strategy for this new play. On Valhall, we are basically following the same playbook as we've used for a couple of years now on Alfheim. Shortly after we took over the field, we launched the IP drilling campaign, which is still ongoing. We immediately started on identifying and maturing new opportunities to create more value from this gigantic field. And through the Hess acquisition last year, we also increased our interest in this area from 36% to 90%. So far, this work has resulted in the Flank West project, which was approved by authorities in Q1 and are now in the execution phase. We are almost finished with the engineering and construction of the jacket and the topside structure has commenced at Kvaerner Vahdal. We have also commenced on the related modification activities at the Valhall field center. As Alexander alluded to, the early departure of the Masque Invincible has allowed us to ramp up investment activity also on the other flanks. And we have launched a project to revitalize the North Flank of Alhall, where we will drill new water injectors to increase reservoir pressure in addition to a new producer. After rig is done on the flank north, the rig will move to South Flank where it will likely drill 2 new producers before commencing the drilling campaign on the Flank West. We expect drilling on the North Flank to commence in the Q4 as previously announced, and these wells should be operational by Q2 next year. The plugging of the old Valhall well is a story of huge productivity gains. Keywords are continuous improvement, technology utilization and excellent cooperation with our key suppliers. The time it takes to plug a well has been significantly reduced, in turn meaning lower cost and an ability to redeploy the asset to more and more probably more exciting drilling activities earlier than previously expected. We are also moving forward with the Hod redevelopment in the Valhall area. The project aims to recover the remaining 64,000,000 barrels gross resources in Hod. The contemplated development concept is very similar to the Flank West with a new unmanned wellhead platform. We will in preparation for this project, we will drill an appraisal well on Hod next year and aim for our Concept Select in Q3 2019. Let me remind you that the resource potential in the Valhall area remains enormous. So far, only 25% of the oil has been produced and our ambition is to reach around 50% recovery. We are also stepping on the accelerator to revitalize the Ula as an oil area hub for the future, basically again following the same strategy as for Alfheim and Valhall. When we took over Ula and Tambor, the field seems destined for decommissioning in the mid-20s. Less than 2 years later, we have turned a trend on production with 2 new wells on Tambach and the Ola project is also well underway. However, we think there are a lot more to be done and have established a strategy to revitalize the Ula as an area hub to 2,040 beyond. Through this work, we have identified a number of new drilling targets. And in order to drill these targets, we have concluded that the existing fixed drilling rig on Ula is no longer fit for purpose. We will therefore remove the rig and instead convert the drilling platform to be used in conjunction with a high performance jackup rig of the generation we've had significant success with both on Valhall and on Niela Rosen. On the picture, you see a vessel placing rocks on the seabed in preparation for such a rig. We have also recently contracted a flotel to accommodate more personnel for the conversion work. And with this conversion, we will be able to drill new wells longer, more efficiently in less time than with the exist and eliminate the maintenance of the aging existing drilling rig. We will continue to mature opportunity set both in Ula and Rallhalle, Nai Ula and Tambor. And we are continuing to mature new exploration targets, which can be tied back to the Ula area. During the quarter, we completed the drilling of 2 new water injectors at the The picture you can see is of the mask interceptor sailing away from Iverossen after yet another drilling job well done. 1 of the new injectors have been started up and are performing very well with high injection rates and extremely good connectivity. The second water injector, which is the first of a horizontal water injector of its kind, the will be started up next week. And based on the drilling results, we expect this well also to be a success. These injectors will contribute to maintaining pressure in the reservoir and hence support pressure production level going forward. As you might recall, the PDO for Iver Osten also included the Hans discovery. We are currently drilling an appraisal well on Hans, which will give more answers on the resource potential prior to making the final investment decision. The same well will also test Slangferhoegar, yet another excellent Norwegian name, as an exploration target. This could, if successful, provide a meaningful addition to the Hanns volumes. And finally, the Ivarossen platform is now probably the most digitalized oil platform in the world. And our digitalization efforts has continued at full speed through the Q2. We are piloting digital operations in conjunction with Cognite's data platform and onshoring our offshore control room at the Eeva Rosen to Trondje. I will come back to our digitalization agenda very soon. And then finally, at Skov, we are able to keep up production in the Q2 despite several technical challenges on the assets. As you may recall, we have previously reported on some technical issues with the Christmas trees on 3 wells at Skov. In Q2, we repaired the second of these wells and put it back on production. Later in the quarter, a similar problem was discovered on yet another well and hence we have currently 2 wells out of production at Skav. We have also experienced several other technical hiccups in the quarter, but we're able to keep up production through resolute action by our employees and extremely good cooperation with our suppliers. In combination, they were able to quickly repair and replace the necessary components. The key element in our strategy for Skav is the Auful development, which if I am allowed to remind you represents gross reserves of 275,000,000 barrels. The project is moving ahead as planned. The main contracts have been awarded. The technology qualification is progressing well and fabrication activities have started. Afol will be developed in 2 phases, with production start in 2020 and for Phase 2 in 2023. We are now studying the potential for debottlenecking at Skalv, which could accelerate the 2nd phase by up to 2 years, which would obviously have an extremely positive impact on the net present value of the project. It is also a pleasure to report that Johan Sverdrup remains on track. This picture was taken just after the second top side was installed little more than a month ago. The financial outlook for Johan Smerdrup remains extremely robust with breakeven low oil prices for Phase 1 below $15 per barrel. And we really look forward to a production start, which remains on track for next fall. In the meantime, the PDO for Phase 2 of Johan Sverdrup have been submitted to the Norwegian authorities in the 3rd quarter will be submitted this Q3 this year. The project will increase production capacity from 440,000 to 660,000 barrels of oil equivalents per day gross when it's completed in 2022. When it comes to Norka, there are no big news to report today. We continue to work on refining the development concept, including offshore wind power, and we are in a constructive dialogue with our main partner Equinor. We maintain our position that the most profitable concept is a central processing hub, which is also the best alternative to maintain value creation and resource utilization in the entire area. And we remain very positive to the total resource potential in the area. Our goal, as previously stated, remains to reach a concept selection in the course of this year. And then on back to digitalization. I've been talking a lot about the potential for digital transformation for both Aker BP and for the industry previously. It's therefore a pleasure to report that the rollout of Cognite data platform combined with handheld tablets have commenced and are almost complete at Die Borossen. We now have a complete digital twin using Cognite's industrial data platform with live historical sensors instantly available on computers, tablets and mobile phones. All operators at Ivarossen are now using these handheld devices instead of paper. The tablets also have computer vision to read tags, identify components, etcetera, etcetera. I'm extremely impressed by the speedy rollout that we've seen so far, and we have many other digital projects ongoing at Aker BP. The improved access to data has already enabled new and improved ways of working and new and improved business models with some of our vendors and we see extremely high potential in this area going forward. The main focus for the next 12 months is to continue the work and expand both capacity and capabilities of those of these digital tools as well as rolling them out throughout the Aker BP portfolio. As Alexander has previously mentioned, and by 2 wells to and by 2 wells to be drilled in licenses that was awarded as late as January. We see exploration as a cost effective way to increase our resource base, and our exploration strategy is basically following 2 main themes. The first one we call ILX or near infrastructure exploration. That means infrastructure That means exploration near existing fields, targeting resources that can be produced through existing infrastructure. These opportunities can be developed quickly and at low cost and may also contribute to extend asset life and hence increase value of existing fields. The second exploration theme is focusing on finding new wells, new fields with potential for standalone field development. Our efforts would typically be distributed approximately sixty-thirty among these 2 or between these two categories. When you look at this year's program, we can easily recognize this strategy with a number of ILX wells in the Alfheim and Utsira area and wells with standalone potential both on the Utsira High and in the Barents Sea. If we take the midpoint on the remaining wells in Aker BP's 12 well drilling program, this represents an unrisked potential of nearly 500,000,000 barrels net to Aker BP. So I think it's easy to see why we are increasing this activity. And we're definitely looking forward to exciting second half when it comes to exploration. And then finally, the priorities remain unchanged also in this quarter. In terms of execution, we maintain focus on safe and efficient operations. We will continue our work on excellent project delivery. We are continuing unmitigated or unchallenged the improvement work with a focus on cost reduction and productivity gains. And finally, we continue to mature project below the $35 breakeven threshold. And then finally, we are seeking to maximize recovery from our existing resource base, exemplified by both the projects ongoing at Valhall and Ula that I've been through earlier in this presentation. And we are pursuing both organic and inorganic growth opportunities in our portfolio. Teilhard, it's Neste on Markets. A couple of questions for me. First, on the Frosk development, is it possible to indicate any total development costs or cost per BOE? On Fosk, I think that's a bit too early. The total development cost will depend on the total resources in the area and also the results from the Frosk test producer that will be drilled early next year. So we'll come back to that as soon as we have more detailed information on the chosen development concept. Okay. And on exploration, you definitely have highlighted you increased exploration efforts this year compared to 2017. Firstly, is that a reflection of that it's not so cheap to buy assets anymore? And secondly, should we expect that activity increase to continue into 2019? I think first of all, it's actually a reflection of an activity that we've carried out for a number of years. And if you look back, we've probably been number 2 in every second in every single round since 2015. That means we're actually the 2nd biggest licensee on the Norwegian continental, both in terms of number of licenses and in terms of net acreage. So it's actually quite evident that at some point in time, we would have to step up our drilling budget to step to drill out such an acreage. And then it's also a reflection that the cost of the exploration wells has over time gone down. And we're now able to drill exploration targets to mid-three thousand meters in the North Sea in about 14 days, which means it's actually a really cost efficient way of looking for new resources. And then as you're obviously aware, we have been agnostic in how we're adding resources to our portfolio with the only key measurement being value accretion to our shareholders. So that will mean that at times when the M and A market is hot, we are focusing on organic opportunities vice versa. That does not mean that we're not looking at inorganic growth opportunities. But it means that at this point in time, we're actually just benefiting from the fact that we've been extremely successful in the licensing rounds in the previous quarters years. Okay. Thank you. And one specific question on Jurgen, pretty wide resource, medium resource range. How much do you need to find to make it commercial viable? That's also a bit of a discussion. We've seen breakeven costs drop significantly of these areas, but this is one of the wells where we're looking for stand alone potential. So I think you need to see significant resource potential in order to see a stand alone potential in this area. Does that mean 300,000,000 barrels of oil? So far, we've seen stand alone potential as low as 200,000,000. Okay. Thank you. Okay. Questions on the web? Yes. We have a few questions there as well. First from Halvor Stram Neugord of SEB. His first question is on tax payable. You have booked $439,000,000 in tax payable relating to first half twenty eighteen. Is it fair to assume that onethree of this will be paid in Q3 and twothree of this in Q4? Yes. So let's just remind everyone that booking and the actual payments in the fall are 2 different topics such that when we book the tax payable, that's based on the actuals for the 1st 6 months. Then all oil and gas companies do estimate now on this time of the year how much the total tax payable for the 12 months will be. That said, I think the estimate of SEK439 is pretty close to what we would expect to pay for the 1st year. And then again, to remind everyone, the first three installments, there's 1 in Q3, there's 2 in Q4 and then there's another 3 early next year, then it would be 1 third of that in Q3 and 2 thirds of that amount. So yes, we believe that estimate is fair, the SEK439. Then Halliburton has also one more question. Is it possible to be more specific on the timing of when the Hess tax losses will be disbursed, Q3 or Q4? Yes. No, I wish you could be more specific, but that is an event that we don't really control. We do still believe second half. If it's September or if it's as late as November, we don't really know. But obviously, we hope we don't expect to see a payment this week or during vacation time now in July. So it will be later in the fall. But specifically which month, it's not really something it's hard to guide for us on that one. Then there is one question from Rafael at Bank of America Merrill Lynch. Regarding cash taxes, assuming $70 to $80 per barrel of Brent for the rest of the year, are you still expecting to pay $12 to $16 per barrel in cash taxes for the year as per your CMD guidance? And if so, could you help guide on phasing between 3Q and 4Q given the relatively low rate of cash tax year to date? Yeah. Okay. So do keep in mind that the actual tax paid in the beginning of this year that is related to the last three installments of the 2017 tax. So what we need to estimate now, it's tax payable for the 1st 6 months, payable later this year and any excess tax on 2017 when you compare those 6 installments to the actual. I think the latter was around NOK200 million that will be part of the tax payable later this quarter. So the guidance, I think we said $12 per barrel in a $70 hydrocarbon price, not realized Brent, but a mixed hydrocarbon price. So I think if you take that $12 and you use the midpoint of the production guidance, which is 150 7.5 times 3 65 days, you get to about 57,000,000, 58,000,000 barrels times 12. And you see that you're not far off based on the what we have booked already and how we see the forecast for the rest of the year. So long answer, but I think that guidance is still pretty good. Then there's a question from Johan Sharandon in Societe Generale. There are 3 questions actually. The first is, are you in position to prevent an escalation from the ongoing strike taking hold on the NCS that is led by the union SAIF? SAIF plans to have additional workers on strike from Sunday night. What could it mean for your drilling and production activity in the short term and over the summer? So to follow the first question, no, are not in a position where we can restrict this kind of activity on the Norwegian continental shelf. This is a right that the employees through their unions have according to the agreements in the Norwegian system. And then second, yes, the if the plans to increase the strike goes on, that means that activity in Deepsea Stavanger, which is currently drilling the Kamilian infill and the Valhall DP and IP will have to stop. Right now, we are securing the wells and running liners on Dibsisteranger, so it's still not stopped the maintenance, but also in terms of maintenance, but also in terms of stimulation activities that we can utilize the rig and the remaining crew rather than continue drilling. Of course, if the strike is prolonged, it will have later in the year an impact on when wells are put back in production, but we hope that we won't see that kind of effect. And if that's going to happen, the strike needs to be actually quite long. So in that case, we're actually feeling quite robust right now. Then Johan had a question on power prices. Power prices have risen in Norway so far this year and are generally expected to remain high for the rest of the year due to unusually low rainfall. What does it mean for Valhall's operating costs going forward? Would you be able to provide some details on your power supply related contracts? Well, generally, we're using about 50 megawatts as a general drawdown. So that should be about 800 megawatt hours or something in that range. If memory serves me right, I think we're spending about NOK 130 on average in power at Valhall each year. We are doing this in a split with long fixed price contracts and spot prices. And again, if memory serves me correct, it's a quite specific question. I think about 25% of the 2018 power has been fixed in low 20 Norwegian europerkowatt hour, and the rains remain floating on the spot. Now if you look at the forward price, my guess is that if you look at the existing, there's around if it's NOK130 is correct, let's say, NOK10 1,000,000 to NOK15 1,000,000 increasing, which is maybe around 0.5000000 $1,000,000 something not really a big impact probably. Again, long answer to a short question. Sorry about that. Then final question from Johan. Following the change in your debt structure since the start of the year, would you still guide for an average cost of debt of about 4% in 2018? Yes. The funny thing with the higher oil prices that we've drawn less on the bank revolver and we've had more of the unsecured bonds issuances. And so then the average cost of that will then trend upwards. So it might be higher than the 4%, but given the debt structure, that's probably a figure that's very easy to calculate just to look at the bond issuances that we have outstanding. Then what seems to be the last question comes from Alwyn Thomas of Exane BNP. He actually has 3 questions. First is on Novakka. If the concept selection is delayed further, how much could this save you from your CapEx budget? If you're forced to go with Equinor's proposal, what would be your strategy to develop or monetize the north of Alvheim fields? Well, when it comes we are obviously pushing for as rapid as possible concept selection, not necessarily because you are saving cost on 1 budget item and then adding cost on another budget item, but certainly because we want to accelerate the project itself. So that's our overriding ambition. And then on the second part of that question, we're actually quite confident that our proposal remains the most value creative, the best proposal to maximize resource utilization. And as such, those are the issues that we're focusing on at the moment. I think on the CapEx specifically, then yes, we had within the SEK1.3 billion CapEx guidance we had in the beginning of the year, we had catered for a bit of NOACO CapEx as such. So that goes down. But if you recall, we did say that due to the performance on Maersk Invincible, we're able to take that rig, reduce CapEx, move that into an acceleration of the Vallhavl Frank North, so that brings us a bit back up again. So it's a bit of pluses and minuses in the CapEx budget there. Alwyn's second question is on production. Can you outline what you expect from your main fields for 3Q 'eighteen including any maintenance impact and the power issues at Ivarossen? Well, if memory is again, if memory serves me correctly, I think we expect a pretty flat program on all the fields right now. There is work going on at Ula. We've recently had a slowdown to accommodate for the modifications in the hydrocarbon systems necessary to add Oda. But apart from that, I don't think there are any major changes in the next quarter. The power issues at Aesen is hard to plan for and as a result of variations in the power production plan and therefore very hard to guide on the effect of. We've seen a positive development in these cases in the last few months, and we hope that, that performance has continued to improve also in Q3. Okay. And then the final question from Alwyn, which is also the last question today. Do you think higher competition on the NCS will affect your ability or willingness to look for new acquisitions? And do you think this could also create cost inflationary pressures? And are you seeing any? Well, we welcome the increased competition on Norwegian Continental. We're firm believers in increased competition resulting in higher degree of innovation, better technical solutions and lower costs for the whole industry. So in fact, we welcome and are looking forward to competing with the newcomers on the Norwegian Continental Shelf. When it comes to cost and cost inflation, I think that's not necessarily related to the change of structure on the Norwegian continental shelf, but probably more related to the, let's say, more optimistic view that the industry seem to have been taking on the oil prices going forward. If I remind you on our improvement strategy, it's always been to increase productivity, not necessarily to focus solely on reduction of input cost in terms of unit cost. And therefore, we believe that our improvement strategy is actually more valuable in a higher and more competitive environment and one where you can see signs of cost inflation in terms of input factors, because it means that as the productivity increases, the cost differential actually also increases. So our competitive edge will also increase. And then the final question, I think, does that impact our ability and willingness to look for new targets? No, it does not. We will continue to be disciplined and only act when we can see value accretive transactions. That means value accretive to our shareholders and have proven that in the last years since 2014 with the first acquisition of Mauritan and Norway. So if that was the last question, I just want to close off the second quarter results by wishing you an excellent summer and an excellent holiday when you get that far. Thank you so much. Thank you.