Earnings Call: Q2 2017

Jul 14, 2017

Thank you, and good morning, and welcome to this 2nd quarter presentation here at Vornenby Poten. And of course also welcome to everybody viewing this on webcast. I am pleased to present yet another quarter of progress and strong performance for Aker BP. The production in the quarter amounted to 143,000 barrels of oil equivalents per day, which is just short of the record label record level of 100 and 45,000 barrels achieved in the previous quarter. Based on these strong production figures for the first half of twenty seventeen, we are today increasing our full year production guidance to 135,000 to 140,000 barrels of oil equivalents per day. This is up from 128,000 to 100 and $35 which was the previous guidance. Correspondingly, we have lowered our production cost guidance for the year from approximately $11 per barrel to approximately $10 per barrels. In the quarter, we achieved an EBITDA of $395,000,000 or equal to an earnings of approximately $0.18 per share. Free cash flow in the quarter was $145,000,000 or approximately $0.40 per share. We paid out a dividend of $0.185 per share or $62,500,000 in Q2 and the Board has resolved to pay the same amount also in Q3 in line with our previously communicated dividend strategy. On the funding side, we have taken further steps to diversify our capital structure and to reduce our interest costs and Alexander will revert to this shortly. On the operational side, I'm pleased to see that we continue to push our improvement agenda and are starting to see some very interesting results, both in terms of productivity increase and then, of course, also in terms of cost reductions. I will talk more specifically about the latest achievements in our drilling performance later in this presentation. Now the drilling activity has obviously also resulted in new production wells. And we have recently completed 2 new infill wells, also resulted in new production wells. And we have recently completed 2 new infill wells on the woolen field, which will contribute to production from Q3 and onwards. On the field development side, we are on track. The most important project is, of course, the Johan Sverdrup field, where the operator Stottweil is doing an excellent job. But we are also in track with our own operated projects and plan to submit 3 PDOs by the end of this year. Even though these are smaller projects compared to Johan Sverdrup, obviously, they are attractive investments with breakeven prices well below $35 per barrel. I will now leave the floor to Alexander, who will walk you through the financial statements and financing update. Alexander, the floor is yours. Thank you, Karl. Today, I'll walk you through some of the changes in our capital structure and provide some updates on our 2017 guidance. But first, I will take you through the income statement, the balance sheet and also the cash flow for the 2nd quarter. We recorded total operating income of USD595 1,000,000 this quarter, of which petroleum revenues were $590,000,000 on a production of 142,700 barrels of oil equivalent per day. We realized an oil price of $51 per barrel in the quarter and a gas price of $0.18 per standard cubic meter. Out of the $590,000,000 in petroleum revenues, DKK502 1,000,000 came from liquids sale, DKK 83 1,000,000 from gas sales, and we had another $5,000,000 in tariff income this quarter. In addition, we had realized and unrealized gains on commodity hedges, which amounted to $3,000,000 this quarter. Production costs amounted to $121,000,000 which is actually the same amount we had in the past two quarters. This equals to $9.30 per barrel in oil equivalent, and this includes shipping and handling costs of 2.50 dollars per barrel. If we look at each of the various hubs this quarter, we had a production cost at Alvheim of 4.50 dollars Ivarossen of around $8 per barrel. We had Skarv of $9.30 Varhall Hod at around $16 and finally, Ula Tambar at $39 per barrel. If we look at other operating expenses, this includes costs such as preparation for operations, corporate overhead. This came in at only $3 per $3 this quarter, and it was positively affected by certain one offs we had. As such, the previous quarter's expense is probably a better run rate going forward. On exploration expenses, we expensed SEK75 1,000,000 this quarter. This reflects acquisition of Seismic Data of SEK 17,000,000 this quarter. We had dry hole costs of $35,000,000 This includes Gota 3 and Wollen West wells, while we then had other exploration expenses, including field evaluations and also area fees, which amounted to the remaining 23 $1,000,000 that make up that balance. We then had EBIT of 3.95 $1,000,000 for the quarter. We had depreciation of $184,000,000 this quarter. This is in line with previous quarter, and this equates to around $14 per barrel. EBIT was then 210 $1,000,000 for the quarter. If we look at the financial items, we had net financial items of a negative 84 $1,000,000 this quarter. Net interest expense was $31,000,000 in line with previous quarter. Then we had other financial income of $15,000,000 This stems from realized and unrealized gains on derivatives. We had accretion expense of SEK33 1,000,000. And since we sent the redemption notice for the Detnor 3 bond in late June, we also charged the $30,000,000 call premium to the financial items this quarter. Profit before taxes was 127,000,000 dollars Tax expense for the period was 67,000,000. This gives a tax rate of 53%. In this amount, it's a payable tax of NOK102,000,000 and this has been offset by a positive change in deferred taxes of SEK 35,000,000. That gives us the net results here of SEK 60,000,000 or SEK 0.18 per share. Our balance sheet has not changed materially during the quarter, and it stood at SEK9.3 billion at the end of the quarter. For both goodwill and other intangible assets, these are virtually unchanged during the quarter, though the latter has been affected by the expense of capitalized cost on Goethe. Net of depreciation, PP and E, increased by 125 $1,000,000 during the quarter and ended at $4,700,000,000 Receivables and other assets were $694,000,000 at the end of the quarter. That's a small increase from the previous quarter of $16,000,000 dollars And this mainly relates to changes in long term derivatives and also higher receivables from our crude liftings. When it comes to taxes, we have recorded a short term tax receivable of 402 $1,000,000 at the end of this quarter, of which twothree is paid out in the 3rd quarter and onethree paid out in the 4th quarter. Then however, following our strong operations in the first half of the year, we also estimate tax payables in the second half of the year of around $140,000,000 And the balance to the booked accrual on the other side of the balance sheet of $225,000,000 is related to accruals for old tax cases. Cash and cash equivalents ended at $66,000,000 at the end of the quarter. On the other side of the balance sheet, equity, not much has changed. It's at DKK2.45 billion or 26 percent book equity ratio. This is in line as it's only been the result for the period and offset with the paid dividend in the quarter. Other provisions for liabilities, SEK 2,330,000,000. This is also in line with previous quarter. Deferred tax increased by a smaller amount, SEK 39,000,000. And this also just reflects the changes in deferred taxes in the P and L. Book value of interest bearing debt, SEK 2,370,000,000 at the end of June. This comprises of SEK1.81 billion drawn on the RBL and then DKK554 1,000,000 as the outstanding amount under the 2 unsecured bonds, Detnor 2 and Detnor 3. Other current liabilities increased to SEK 831,000,000 in the quarter. This reflects increase both accounts payable and other current liabilities. On the back of a continued strong production this quarter, we generated cash flows from operations of $447,000,000 again, slightly higher than what we had in the previous quarter. Cash flows from investing activities were DKK312 1,000,000. This reflects investments in fixed assets of $271,000,000 of which the most significant investments this quarter were related to Johan Sverdrup of SEK124 1,000,000. Here, the top side accounts for 50%. Ivar Osen of around 40%. Here, production drilling accounts for about 80%. Alveim at DKK36 million. Here the Boulen infills that Karl will talk about accounted for 80%. And then we had Vallalh Pod of around 25% and finally, some capitalized interest of CHF 24,000,000 dollars In addition to these investments in fixed assets, we had investments in the intangible assets of 21,000,000 and we had cash payments on decommissioning liabilities of SEK20 1,000,000. Now the latter is an increase from the previous quarter because we had the Mask Invincible rig going for a full quarter and commencing P and A activities at Valhall. So thus, free cash flow was SEK135 1,000,000 in the quarter. Then we repaid around DKK190 1,000,000 on the RBL during the quarter for cash management purposes, and we also paid out the DKK 62 $500,000 in dividends. The end of the cash balance at the end of June was then $66,000,000 and we had interest net interest bearing debt of $2,300,000,000 slightly down from the previous quarter. At the end of the quarter, we had net debt decrease net debt over EBITDAX decreased from 1.3000000 to 1.1000000, and we had available liquidity of SEK2.7 billion. Our Board of Directors have declared quarterly dividend to be paid out in August of around DKK62,500,000 which implies an annualized dividend yield of 4.7%. Following the merger that created Aker BP last year, we have been working to assess the capital structure and debt composition with a goal to improve flexibility but also to reduce our cost of funding. Whilst we enjoy strong support from our bank group, we seek to balance the secured and the unsecured debt on the company's balance sheet. As the company has grown in size, a natural development has been to complement our presence in the Nordic bond market with the deeper international markets. This spring, we obtained a credit rating from international credit rating agencies, S and P and Moody's. S and P assigned a BB plus corporate credit rating with stable outlook, while Moody's assigned a BA2 credit rating also with stable outlooks. Last month, we raised a new senior unsecured bond of $400,000,000 accessing a new market of debt funding for the company as this was done under U. S. Documentation. This bond has a 5 year tenure and carries a fixed interest rate of 6%. This bond is callable from 2019 starting at the price of $103 The proceeds from this issuance will be used to take out the company's most expensive debt, the subordinated 300,000,000 debt NOK 3 bond, which was raised a little over 2 years ago. This bond has a coupon of 10.25 percent, and the company sent a notice to the bondholders informing about our intent to redeem the bonds at 110% plus accrued interest. We expect to have this completed during the month of July. In addition to this issuance and the consequent redemption of Detnor 3, we are working with our bank syndicate in order to make certain amendments to the company's $4,000,000,000 RBL facility. The objective here is to achieve a more cost effective structure and flexibility and ease of administration. We expect to have these amendments approved shortly. As part of this process, the company intends to cancel the R550 1,000,000 RCF, which also was established about 2 years ago. The graph here summarizes the changes we are making through the capital structure. Collectively, we believe these changes improves the capital structure as we will have a simpler secured bank structure. We will only have 2 layers in our capital structure, firstly unsecured and unsecured. We will have ample available liquidity. And finally, a more cost effective structure, reducing our interest expenses of around $30,000,000 per year based on the drawn amounts and the pro form a Q2 column at the right hand side of this graph. Finally, we'll just revisit the 2017 full year guidance. And this time, we are making a couple of changes to the guidance parameters that we shared in the beginning of the year at the Capital Markets Day. Following a continued strong production in the second quarter, production has averaged 144,000 barrels per day the first half of twenty seventeen. The high production performance has been driven by continued high production from the Alvheim area and, in particular, the Viper Cobra wells. We have, however, seen some decline from the VIP COBRA fields recently. There is also planned maintenance at both Valhall and Stalv in the Q3. Our full year guidance range is therefore raised to 135,000 to 140,000 barrels of oil equivalent per day. Production cost has averaged $9.30 per barrel in the 1st 6 months of the year, again driven by the higher production volumes and the fact that a large part of the production cost is fixed. As a consequence of the increased production range, we also lowered the production cost guidance for the year to approximately $10 per barrel. The other parameters, they remain unchanged. CapEx for the 1st 6 months amounted to SEK491,000,000, but we do expect the total spend for the year to remain in the SEK 900,000,000 to SEK 950,000,000 range. Cash spend on exploration was €120,000,000 in the first half with a run rate below our full year guidance of $280,000,000 to $300,000,000 This is driven by the fact that we have higher equity in the wells planned during the second half of the year. As for decommissioning costs, cash spend was only 28,000,000 dollars in the 1st 6 months. But we do keep our guidance of $100,000,000 to $110,000,000 for the full year as we commenced the P and A activity at Valhall with a Maersk Invincible rig in the second quarter, and we will have this rig running for the 2 remaining quarters. That concludes my financial section, and I will let Karl who walk you through the operations. Thank you. Okay. Thank you, Alexander. So let's move on to operations. Now let me start with production. And as been previously stated a couple of times, we've seen very high production in the quarter amounting to 143,000 barrels of oil equivalents per day. These numbers are obviously higher than our estimates initial estimates that was presented in January at the Capital Markets Day. And as such, we are increasing our guidance. Now the main positive deviation is the continued high performance both in terms of regularity, but particularly the well performance of the 2 wiper and Cooper wells that was drilled a couple of years ago. Now you may remember that these wells were planned as single wells and that the well plans changed radically during the drilling. And this is to me is an example of how increased productivity and focus on swift decision processes can actually have a significant impact on the bottom line as we changed both the length of the wells and also changed from single laterals to dual laterals inside of a week. Now the realized pricing in the quarter was $51 a barrel, which is pretty much in line with Brent And the realized gas prices was about $0.18 per cubic meter, which is equivalent to roughly $5 per 1,000,000 BTU. So in total, the production has been strong. We continue to see strong production, although slightly down in the next two quarters, impacted by decline in the Waipakobwa and the turnarounds at the Alfheim and Skov. I will now walk you through some of the all of the assets and provide some highlights on each of the assets as we see them from our side. Alvheim is continuing to beat expectations and provide quite amazing performance. The operating efficiency or production efficiency in the quarter was 98% and the production cost was $4.5 per barrel in Q2, which is quite surprising and really, really good figures. We continue to develop the Alvheim area and continue to follow the strategy we have for the last 3 years by adding new wells and 2 new wells on Wollern were completed in Q2, that's P9 and P10. Wollen is already on stream and the second is planned to start production in August. The drilling rig Transocean Arctic has now moved from the Wollen template to the Boa template where it's currently drilling the first of 2 infill wells. These two wells are drilled on targets that was identified during the Boakam North multilateral drilled last year. And after Boa, the rig will move to drill an exploration well in the prospect named Frosk in the southern part of the Alvheim area. Our subsurface team continue to mature new drilling opportunities in the Alvheim area to fill the FPSO also in the years to come, and we continue to see lots of opportunities in the area. Meanwhile, we're also working on a PDO for the Sturglaken project towards the end of this year. The Sturglaken will most likely be developed as a tieback to the Alfheim FPSO using the Wilje tieback line with an expected first oil in 2020. And as you may recall, we sold 35% of our owner interest in Stuttlakend to PGNIG in March and that's taking our ownership down to 65% or broadly in line with the average share in the Alvheim area. So Alvheim continued to be our most important asset and continued to be an asset that outperformed expectations. Now, Walhalla, which is obviously an asset that's been running by BP Norway and then accumulated into the Aker BP as the merger was completed last year. Production from Nualal was slower in this quarter compared to the previous quarter. This was partly driven by reservoir depletion and partly mostly related to drilling and well activities. We've had a very high drilling and well activity on the field at the same time. The Masque Invincible has continued a P and A program. The IP drilling rig is progressing well on its infield production drilling program. And in addition, we've had 2 wireline crews running production and abandonment well interventions. So activity has been really, really high to allow. Overall efficiency impacted by the well operations is 85% in the quarter. Now we continue to work the project and are in the process of preparing for a PDO. First oil is thus expected also in 2020 for this project. Moving on to Ivar Aasen. We've seen excellent production performance also in the Q2 with the exception of some downtime due to power related issues. The main remaining commission activities were completed in Q2 and water injection was commencing has commenced starting in May. The drilling has performance has been excellent and even more even stronger than previously and I will come back to that a little later. And we assume the PDO program will be completed during Q3 this year and the rig moving towards drilling of wells at Hrokin and Storklaken and then later at Tamba, I'll come back to the exploration drilling later. The field is now ready for further ramp up in Q4 2017 in line with the throughput agreement on Advert Grieg. Now moving to Ula, which is our oldest asset. The production increased by about 20% in the quarter compared to the previous quarter. The main increase is related to WAG performance And this performance is highly dependent on a few wells and cyclical in nature. So it's likely that the production performance at Ula will fluctuate from quarter to quarter. The Tamari development project is progressing and focus in Q2 has been on procurement, engineering and prefabrication in preparation for offshore facility modifications. We expect to start drilling of the 2 new Tamba wells in Q4 2017 with an outlook of first oil in 20 18 and these wells will be drilled using the Masque Invincible rig that has at that point in time completed the PDO program at Ivarossen. The PDO for the Oda development was approved by the authorities in May and will be developed as a subsidized back to Ula and will contribute positively to the Ula performance both through additional gas that will go into our bank scheme and also for reduced unit production costs. Now to further reduce the cost per barrel on Ula and to increase production, the key measures that we are implementing going forward is to take an opportunity to add all valuable barrels to the field, to apply efficient technologies to reduce costs. We're implementing a lean operation scheme to further keep cost low and keep working the reservoir and keep adding near field resources. I'm pretty convinced that this vintage working on this vintage asset will provide important learning for the company also going forward. Moving on to Snudd and to Skov. The Skov production was stable and high in the second quarter with a production efficiency of 96%. 1 of the Skow wells was shut in during the quarter due to a Christmas tree failure, but this has not had any material effect on production as other wells have compensated production. The well will be repaired and put back on production in due course. And in the meantime, we're also taking steps to prevent similar problems occurring elsewhere in the field. Apart from our daily operations, our main focus on Skav now is to move on and move forward the Snod Phase 1 development. We are preparing for final investment decision in Q4 and the project consists of 3 subsea wells which will be tied into Skov and will be ready for production again in 2020. Estimated gross CapEx for Phase 1 is about NOK6 billion in line with previously communicated estimates. Then moving on to Johan Sverdrup. The Sverdrup development is progressing well and according to plan. At the end of the Q2, we were about 60% complete with the Phase 1 facilities construction. The first steel jacket, the Ryerson platform jacket had been completed at the Kvaerner Vardal and we continue to see good drilling progress. The rig is currently drilling 10 injector wells followed by which is of course following the producers and pilot wells that was been drilled previously. The PDO for Phase 2 will increase production capacity to roughly 660,000 barrels of oil equivalent and is expected to be delivered during the second half of twenty eighteen. Now moving on to the north of Alvheim and Asakafla area, which we call Noaca for short. This can potentially become our next major development project. Gross resources in the area are estimated to be in excess of 400,000,000 barrels of oil equivalent, but spread across a number of discoveries. In June, the licenses in the Neuwa area, the previously called north of Alvheim area and the Graf Larche area agreed on a collaboration agreement and plan for concept selection for joint area development for the entire Norkov area. Two concepts are to be evaluated, which the first one is a field hub located at the middle of area approximately at in line with the Fuller field with processing and export capacities. The different fields will be tied in from subsea templates and normally not manned installations to the field hub. Aker BP is the project lead for the hub and the south area, while Satoel is responsible for the work in the Kaffla, Asha area. The second concept to be evaluated is 2 unmanned production platforms tied back to a host platform. For this concept, Aker BP is the operator in the north of Alvheim area and Stottal is responsible in the Krafla Asha area. We expect concept selection to occur in the Q1 of 2018. Moving on to exploration. During the Q2, we completed 2 exploration wells, namely the Gotter III well in the Barents Sea and the Wallen West well in the Alvheim area in the North Sea. Unfortunately, neither of these wells were successful. However, in the second half of twenty seventeen, we will step up our exploration activity. We plan to spud the Hyrokin well in production license 677 Northwest of the Velia field. Hyrokil is defined as a geophysical anomaly quite similar to the anomalies we see across the Velia field. Gross pre drill volume is in the range of 6000000 to 55000000 barrels of oil equivalent and discovery could be tied back to the Alvheim FPSO adding production to the Alvheim field. Following the Hyraken well, the Maske Interceptor will move on to drill the operated Norfjaller discovery in PL-four forty two and also drill an appraisal site track into the Delta discovery in the same license. Nuviale is a separate fault block in the Langfjall area, which we drilled last summer and has the same plate concept as for Langfjall. The pre drill estimate is roughly in the range of 10,000,000 to 40,000,000 barrels on a gross basis. Also in the second half of this year, we will participate in the Suttell operated Central Tree well in the Gino Korg area and Lundin operated Hufsavel, needs to have a new name close to the Fili Kuti discovery in the Barents Sea. Now moving on to our improvement program and this time exemplified by the drilling and well performance in Aker BP. I'm really proud to see how the drilling and well department in Aker Aker BP are continuing to improve the performance and productivity, not only on one rig, but across the different licenses. We are really starting to see some great results from this work. And the main element of this is a culture for chasing improvements and an interest in learning from previous operations and sharing this learning with our vendors so that production and performance can be sustained over time. A couple of examples. At the Wallhalle drilling platform, we have recommenced drilling after 2 years of a drilling stop. The first U well was commenced was delivered commenced drilling in March and has now been delivered at a cost below $5 per barrel. Even on this well, we've seen excellent drilling progress and cost well below the planned cost and the previous cost we saw on the IP rig at the Valhall field. In this well, we extended the horizontal section by 700 meters, again, for an excellent team effort, where drilling contractors, the subsea department and the drilling and well team contributed to extending the horizontal section. This extension of the horizontal section in turn then meant we could increase the post drilling reserves from this field by about 30% from 9,000,000 to 12,000,000 barrels of oil equivalents. Another example, at the Eva Boson field, the team continued to deliver solid performance and to set new records. From the first well drilled on the field, the D10 at 158 meters today per day to the latest well, the D12, which was drilled at the world class 3 68 meters per day, the drilling speed is more than doubled. And still, the team is eager to improve and deliver even higher performance in the next projects. I think there is somebody up there that are really sorry that the PDO program is nearly coming to an end. Also in exploration drilling, I'm pleased to see strong improvement in performance. We delivered the West Wallen well at less than half of the estimated cost. And even though the results from the well was disappointing, the reduced well cost will help us explore more for less money. Now to end our presentation, let me spend a little time on our main priorities going forward. On the execution time side, we spend our time securing that we delivered flow efficient and lean operations with high uptime and without any HSE incidents. Our target is to deliver 3 PDOs by year end and we're working diligently to secure that we are doing so. We continue our improvement efforts by prioritizing activities that result in increased productivity and therefore reduced cost. The work on establishing alliances and other ways of collaborating with the vendors to secure sustained competitive advantage by increased productivity is continuing and there will be more news on that later this year. Our overarching threshold for new development is a breakeven price of below $35 per BOE. On the growth side of our business, we are stepping up exploration activity in the second half of the year, and we continue to mature new infield opportunities in the vicinity of our existing fields and subsequently drill these out. Lastly, we pursue selective growth opportunities to enhance production and increase dividend capacity. Overall, our main focus going forward will be the same as it's been in the last few quarters and in fact, in the last couple of years and that's to secure a high performance from the company while looking for growth opportunities. That concludes the presentation today and we will now open for questions. And I'll invite Alexander back on stage. Thank you. Halvor Nygard from SEB. On Ginekrog, if the Total and Okay deal doesn't materialize, is that a stake you are interested in? And how has the performance on Ginekrog been since the start up? Well, I think the Total and Okea will need to comment on their process. So far we've not been a part of that discussion. However, as we're looking at most of the assets that's for sale, if the price is right, we may be interested. This will, however, be outside our stated strategy of focusing on operated assets, where we can see significant upside and implement our improvement strategy. So it's not at the top of our list. Now the Gino COG has had acceptable performance from start up. We've had a small leak has been communicated in the media. But apart from that, it's been acceptable performance from startup. Secondly, on the Nuaka, the 2 field solutions that you're studying, is it too early to say something about the economics between the 2 in terms of production volumes, breakeven levels and so on? Or do you have that to provide? No, I think we'll have to run through the concept selection phase in order to provide more robust cost estimates on those two selection on those two concepts. Obviously, we've done some preparatory work to end up with those two concepts. So it should be quite clear when we're communicating our intent to stay below 35 that both of these are Good morning. Anders Holte from Danske Bank. Just a couple of questions for me. The seismic spend, as you mentioned this quarter, is that the sort of run rate we should expect quarterly going forward? And then on the Q3 maintenance on Skarib and Malal, if you could expand on the extent of the maintenance and the impact on the production? That would be good. Thanks. When it comes to seismic, this is a one off. This was an opportunity to acquire quite a large seismic library that materialized in the quarter. And we decided to grab the opportunity and spent about $17,000,000 acquiring quite valuable seismic library. Of course, this is following the cost reduction and drop on prices also in seismic on the Norwegian continental shelf. And as such, it's in line, of course, with our strategy to increase exploration, but you shouldn't expect us to do that every quarter. If that occurred, we would probably be the biggest owner of seismic libraries quite quickly. Now when it comes to turnarounds, these are normal turnarounds that is happening at the fixed intervals at both Skav and Alfheim. The main scope is change out of key production items that have a limited lifetime and inspection programs that necessitate production shutdown. We expect about 10 to 12 days on each of these fields. Is it possible to talk a bit about tie in potential of the Noufjell prospect? And if also possible to say something about the chance of success on that prospect and the Hiroykyn prospects? And then my second question would be, assuming the 3 PDOs that you plan for this year, is it possible to say if it's reasonable to assume higher or lower CapEx in the years forward? When it comes to Hirokien, there are 2 possibilities. Probably the base case is to tie it back to the Alvheim FPSO, either through the Velje flow line or as an independent flow line depending on the Nohaka field development as tire lengths are pretty long down to either the Ussabag area in the north or the Alheim area in the south. I adopted that can be technically feasible. Discoveries stand in the range of 20% to 30% for both these prospects. Now when it comes to PDO, I think we I think the key issue for the concept selection phase for a lot of these is to find robust development solutions that reduce our engineering cost in line with the previously communicated drive to reduce engineering cost to about 65 hours per ton and to ensure that we get the high productivity in the construction phase. So far, we have seen in line with the market trends, reduce the cost from the previous assessments that's been done in the early phases of the project, both as a result of market effect, but also as of our improved productivity from our internal improvement programs. I expect that this to continue until final investment decision. Okay. I think we'll take questions from the web, starting with Jeyant at Lukro. Could you explain the €225,000,000 of tax payable again and why it was not there last year? Yes, sure. So the book tax receivable of $225,000,000 it's really 2 components in there. It's $140,000,000 or 138, to be exact, on accrual for taxes payable based on the operations of the 1st 6 months of this year. So naturally, that wasn't booked last year. And the remaining part of that balance is related to old tax cases, of which they were sitting previously in deferred taxes but are now sitting in payable taxes. And I believe also for the latter, 50% of that has an offsetting booking on the other side of the balance sheet for indemnities on those old tax cases. Okay. And there's a question from Rafael Gautaj at Bank of America Merrill Lynch. Could you give us some more color on the power issues at Ivarossen? What caused it? What stops it happening again? And does it impact Edvard Grieg production facilities? Yes. Obviously, the Evossen field is getting all its power for injection and production purposes. That is all power apart from the essential power from the Edvard Grieg field. And then I'll refer to the operator to comment the courses and the measures that are being taken. However, we do work very closely with the operator of Edvard Grieg to support their efforts in stabilizing the power plants. And the second question is related to the Hurry prospect. It's missing from Slide 19. And has this prospect got partner approval? And is it likely to be spread this year as per the operator's presentation? Yes. We are supporting the drilling of the Harrier project. As of currently, we are estimating spud in just over next year and that does not include it into 2017 drilling program. Should that be the case, we're fine with that. And as I said, we're supporting drilling of the both the Hufsa and the Hurry prospects in that license. Okay. And last question from Rafael is related to Gutta and how much we still have capitalized for that asset on our balance sheet. It's $75,000,000 still capitalized. Okay. There's a question from Theodor Sven Nielsen at Spadovank end markets. What full year production efficiency for Alvheim have you assumed in the updated production guidance? I think that's we haven't really given that sort of detail, but it's lower than what we achieved in both the previous quarters. Okay. Second question is related to dividends in 2018. Do you expect to provide a specific dividend guidance for 2018 as you did for 2017? And what will this dividend be based on EPS, free cash flow or any other parameters? No, I think you should expect us to keep the current level of dividends. And at that point in time where we'll change it, that will be when we'll have to make more details around that. So expect this level to stick until we get back with new guidance on that. Okay. Two more questions from Teodor. One is related to Sverdrup. Is it fair to assume that 2018 CapEx will be as 2017 CapEx or slightly lower? And the second is related to Gutter. When will you or the operator be able to provide an updated resource estimate? On Sverdrup, again, the operator will be the one who'll provide you that detail on CapEx guidance. But we should say that 'seventeen and 'eighteen are expected to be the 2 CapEx heavy years on Johan Sverdrup. When it comes to Gota, we are working with the operator to assess the results from the Gota 3 well and the impact on reserves estimates. I assume that, that will happen before the end of the year. Okay. Moving on to Alwyn Thomas at Exane BNP Paribas. Given the recent fall in oil price, how does this affect your operational plans or targets in the short term? Are you seeing a continued slide in new project costs? Well, we have tried to keep our long glasses on when it comes to volatility and focus on cost reductions and productivity improvements. We will see, at least in my view, high volatility in the oil and gas prices in the years to come. And if we were going to stay from quarter to quarter, depending on what the oil price may or may not be in that quarter, I think we would quite quickly lose our strategic direction. So our view is to work as hard as we can to get the cost down and the productivity up. And as I said, to sanction projects well below what I think we all assume to be the floor for the oil price at $35 per 1,000,000,000 breakeven. And as such, try to keep a steady course. Now, we continue to see costs coming down. I don't expect prices as such to come down significantly from the level as it is today as I see a lot of the revenue already taken out in the value chain of the vendors and sub vendors. However, I expect to see increase in productivity, resulting in lower achieved cost per installed ton or other relevant resource measure as a result of productivity and flow efficiency increasing measures. But I don't necessarily expect to see prices come down as such. Okay. There's a question also on the new capital structure. How much will this save you in interest costs? And do you see a path for an improved credit rating in how to get there? Well, we I think I mentioned that we're expecting around €30,000,000 in annual savings with these changes, all the changes I talked about in place. We just recently, a couple of months ago, obtained the credit ratings from Moody's and S and P. So I do not expect those changes to materially impact the rating that was then achieved. Okay. We've got a question from Helgandrea Martenssen at DNB. How will the Valhall IP platform drilling program impact Valhall production forward? What level of increase can we expect? And will the increase of recoverable reserves per well on Valhall IP increase the booked reserves of the Valhall IP the 7 wells? Well, of course, we wouldn't drill the production wells on Valhalla if we didn't believe that they would increase production and or reserves. If memory serves me correctly, we've already booked reserves of the 7 well drilling program. So any increase in booked reserves will then be a result of increased reserves as post drill evaluation rather than pre drill evaluations. Productions are obviously going to come up. I think I'll await the performance of the first couple of wells until we guide the market on what level of production increase we will see from the 7 well program. And second question there is could you please indicate CapEx levels for the Valhalla West Flank project? Again, we haven't communicated that kind of detail at this point in time. However, it could be found in the environmental impact assessment. We think the number stated there is roughly NOK7.2 billion. Gross, yes. Gross basis. Okay. And next question comes from Niki Kuzmanov at Jefferies. First related to exploration. Given the Kayak discovery in the Filiqiu, Johan Castberg area, Stavall has talked about Kayak as a potential tieback to Johan Castberg. Would Filicudi or Hafsaan Hurry, in the case of success, be viable for tiebacks to KOSPIK? Or would a wider area development potential come into play? Yes. Kayak is in the KOSPIK license. So I think it's quite obvious that, that will be a tieback candidate to the Johan cost bag development. When it comes to evaluations in the Hufsa and Hari area, we agree with the operator that we need to see the result of the drill out of the prospects in the area before we conclude on development options. Internally, we're keeping both tieback and standalone field development options open. Okay. Second question from Nicky related to dividends. You mentioned €30,000,000 annual saving and interest expected post debt restructuring. Can we expect, once process completed, the floor of the €250,000,000 dividend to be increased even before Johan Sverdrup? I think working well on the capital structure, optimizing it and making sure we have the best structure possible is just ongoing work for us at Aker BP. I don't necessarily see a one to 1 on savings and dividend level. That's part of the overall assessment on what's the appropriate dividend level going forward. And Nicky, you should also see this as a part of our larger effort to improve cost structure and productivity in the company. And that's not only pertaining to the physical disciplines, but also to the financial disciplines. Okay. We got a question from David Mersey at Deutsche. Could you give us an example as to how your engineers have lowered engineering cost per tonne? Is this fewer facilities needing a lighter jack up top or at subsea cost reduction? No, I think the so far, what we've seen is the most of the effect is coming from engineering related to interface management, management of the different partners in the value chain, but also related to improved reuse of previous engineering. If you break up the engineering, consider roughly a third of this is actually related to engineering and procurement not engineering as designing of the topside facilities. We see the largest results so far as a consequence of our alliance structure, which to a large extent takes away the need for extensive interface engineering between the different parts in the field development. Utilization of digital tools is also increasing productivity engineering and last but not least, reuse of existing engineering, existing packages has also reduced the engineering hours per ton. Okay. Moving on to RBC and Victoria McCulloch. How is Viper Cobra currently producing? And do you plan to increase your hedging to reflect the increased production guidance? And lastly, Evard Grieg appears to be processing more than the expected MAX volume. Is Igor Osen entitled to any of the additional capacity or is this limited to current throughput agreement? When it comes to Waipakobwa, the production is a little bit down as water is starting to influx in some of these wells. However, we are currently running up against maximum capacity limitations in the Wollern pipeline tying back to the Alvheim field. So there's also an optimization game between the existing Wollern licenses and Wiper and Cobalt licenses, complicated, of course, by 2 new high productive wells, the P9 and the P10 coming onto the same template. So this is a continuous optimization where we try to keep the water volume flowing in that pipeline as low as possible and thus increasing oil volume up to Alvheim. We incursion in the Waipemcuba area for a long time now. And the development is much slower than we expected initially. Increased hedging. We still have 15% of the on the guided production level hedged. So we've been monitoring and assessing whether to increase the amount of hedging for 'seventeen, and we're also monitoring and seeing and assessing whether to hedge for 2018. But as of yet, we've not hedged more, and that is a pure pricing assessment. And when it comes to the access to debottlenecking volumes on Edvard Grieg, there is a provision in the throughput contract where we are entitled to a certain amount of this for a certain amount of time and thus by referral to production increase in Q4 2017. We are in the process of completing the last producer on the Eeva Wassen field, making us quite confident that we'll be able to utilize that increased production allowance. Okay. We'll take the last question from the web. James Hossey at Barclays. Should we expect your planned RBL amendments to include a change in the size of the committed facility? No. That was the easiest answer to it. No. It's so we'll get back and share more details on the new RBL amendments, but we do not expect a change in the size. We expect that to remain at the $4,000,000,000 facility. Okay. That concludes the web questions. Excellent. Thank you, everybody, for showing up, and thank you for everybody watching on the web and a very good summer to everybody.