Thank you, and good morning, and welcome to this second quarter presentation here at Fornebubotn. 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 level of 145,000 barrels achieved in the previous quarter. Based on these strong production figures for the first half of 2017, we are today increasing our full year production guidance to 135 to 140,000 barrels of oil equivalents per day. This is up from 128 to 135, 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 million US, or equal to earnings of approximately $0.18 per share. Free cash flow in the quarter was $145 million or approximately $0.40 per share. We paid out a dividend of $0.185 per share or $62.5 million US 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 cost, 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 two new infill wells on the Ula 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, Statoil, is doing an excellent job. We are also on track with our own operated projects and plan to submit three PDOs by the end of this year. Even though these are smaller projects compared to Johan Sverdrup, obviously, they are attractive investments with break-even 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. First, I will take you through the income statement, the balance sheet, and also the cash flow for the second quarter. We recorded total operating income of $595 million US this quarter, of which petroleum revenues were $590 million on a production of 142,700 barrels of oil equivalents 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 million in petroleum revenues, $502 million came from liquids sale, $83 million from gas sales, and we had another $5 million in tariff income this quarter. In addition, we had realized and unrealized gains on commodity hedges, which amounted to $3 million this quarter.
Production costs amounted to NOK 121 million, which is actually the same amount we had in the past two quarters. This equals to NOK 9.30 per barrel in oil equivalent, and this includes shipping and handling costs of NOK 2.50 per barrel. If we look at each of the various hubs this quarter, we had a production cost at Alvheim of NOK 4.50, Ivar Aasen of around NOK 8 per barrel. We had Skarv of NOK 9.30, Valhall/Hod at around NOK 16, and finally, Ula/Tambar at NOK 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 NOK 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. Exploration expenses, we expensed NOK 75 million this quarter.
This reflects acquisition of seismic data of NOK 17 million this quarter. We had dry hole costs of NOK 35 million. This includes Gohta-03 and Volund West wells, while we had other exploration expenses, including field evaluations and also area fees, which amounted to the remaining NOK 23 million that make up that balance. We had EBIT of NOK 395 million for the quarter. We had depreciation of NOK 184 million this quarter. This is in line with previous quarter, and this equates to around NOK 14 per barrel. EBIT was NOK 210 million for the quarter. If you look at the financial items, we had net financial items of a negative NOK 84 million this quarter. Net interest expense was NOK 31 million, in line with previous quarter. We had other financial income of NOK 15 million. This stems from realized and unrealized gains on derivatives. We had accretion expense of NOK 33 million.
Since we sent the redemption notice for the DETNOR03 bond in late June, we also charged the NOK 30 million call premium to the financial items this quarter. Profit before taxes was NOK 127 million. Tax expense for the period was NOK 67 million. This gives a tax rate of 53%. In this amount, it's a payable tax of NOK 102, and this has been offset by a positive change in deferred taxes of NOK 35 million. That gives us the net results here of NOK 60 million or NOK 0.18 per share. Our balance sheet has not changed materially during the quarter, and it stood at NOK 9.3 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 capital cost on Gohta.
Net of depreciation, PP&E increased by NOK 125 million during the quarter and ended at NOK 4.7 billion. Receivables and other assets were NOK 694 million at the end of the quarter. That's a small increase from the previous quarter of NOK 16 million, and this mainly relates to changes in long-term derivatives and also higher receivables from our accrued liftings. When it comes to taxes, we have recorded a short-term tax receivable of NOK 402 million at the end of this quarter, of which two-thirds is paid out in the third quarter and one-third paid out in the fourth quarter. 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 NOK 140 million.
The balance to the booked accrual on the other side of the balance sheet of NOK 225 million is related to accruals for old tax cases. Cash and cash equivalents ended at NOK 66 million at the end of the quarter. The other side of the balance sheet, equity, not much has changed. It is at NOK 2.45 billion or 26% book equity ratio. This is in line as it is only been the result for the period and offset with the paid dividend in the quarter. Other provisions for liabilities, NOK 2.33 billion. This is also in line with the previous quarter. Deferred tax increased by a smaller amount, NOK 39 million. This also just reflects the changes in deferred taxes in the P&L. Book value of interest-bearing debt, NOK 2.37 billion at the end of June.
This comprises of NOK 1.81 billion drawn on the RBL, NOK 554 million as the outstanding amount under the two unsecured bonds, DETNOR02 and DETNOR03. Other current liabilities increased to NOK 831 million in the quarter. This reflects an increase in both accounts payable and other current liabilities. The back of a continued strong production this quarter, we generated cash flows from operations of NOK 447 million, again, slightly higher than what we had in the previous quarter. Cash flows from investing activities were NOK 312 million. This reflects investments in fixed assets of NOK 271 million, of which the most significant investments this quarter were related to Johan Sverdrup of NOK 124 million. Here, the top side accounts for 50%. Ivar Aasen of around 40%. Here, production drilling accounts for about 80%. Alvheim at NOK 36 million. Here, the Volund infills that Karl will talk about accounted for 80%.
We had Valhall HOD of around 25%. Finally, some capitalized interest of NOK 24 million. In addition to these investments in fixed assets, we had investments in intangible assets of NOK 21 million. We had cash payments on decommissioning liabilities of NOK 20 million. The latter is an increase from the previous quarter because we had the Maersk Invincible rig going for a full quarter and commencing P&A activities at Valhall. Free cash flow was NOK 135 million in the quarter. We repaid around NOK 190 million on the RBL during the quarter for cash management purposes. We also paid out the NOK 62.5 million in dividends. The cash balance at the end of June was NOK 66 million. We had net interest-bearing debt of NOK 2.3 billion, slightly down from the previous quarter.
The end of the quarter, we had net debt over EBITDA decreased from 1.3 to 1.1. We had available liquidity of NOK 2.7 billion. Our board of directors have declared a quarterly dividend to be paid out in August of around NOK 62.5 million, which implies an annualized dividend yield of 4.7%. 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, 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. 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&P and Moody's. S&P assigned a BB+ 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 million, accessing a new market of debt funding for the company, as this was done under U.S. documentation. This bond has a five-year tenor and carries a fixed interest rate of 6%. This bond is callable from 2019, starting at a price of 103. The proceeds from this issuance will be used to take out the company's most expensive debt, the subordinated $300 million DETNOR03 bond, which was raised a little over two years ago.
This bond has a coupon of 10.25%. 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 DETNOR03, we are working with our bank syndicate in order to make certain amendments to the company's $4 billion RBL facility. The objective here is to achieve a more cost-effective structure, flexibility, and ease of administration. We expect to have these amendments approved shortly. As part of this process, the company intends to cancel the $550 million RCF, which also was established about two years ago. The graph here summarizes the changes we are making to 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 two layers in our capital structure, firstly secured and unsecured. We will have ample available liquidity. Finally, a more cost-effective structure, reducing our interest expenses of around $30 million per year based on the drawn amounts and the pro forma Q2 column at the right-hand side of this graph. Finally, we'll just revisit the 2017 full year guidance. 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 in the first half of 2017. The high production performance has been driven by continued high production from the Alvheim area, and in particular, the Viper-Kobra wells. We have, however, seen some decline from the Viper-Kobra fields recently.
There is also planned maintenance at both Valhall and Skarv in the third quarter. Our full year guidance range is therefore raised to 135,000-140,000 barrels of oil equivalent per day. Production cost has averaged $9.30 per barrel in the first six 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 lower their production costs guidance for the year to approximately $10 per barrel. The other parameters, they remain unchanged. CapEx for the first six months amounted to NOK 491 million. We do expect the total spend for the year to remain in the NOK 900 million-NOK 950 million range. Cash spend on exploration was NOK 120 million in the first half, with a run rate below our full year guidance of NOK 280 million-NOK 300 million.
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 NOK 28 million in the first six months. We do keep our guidance of NOK 100 million to NOK 110 million for the full year as we commenced the P&A activity at Valhall with the Maersk Invincible rig in the second quarter, and we will have this rig running for the two remaining quarters. That concludes my financial section, and I will let Carlo walk you through the operations. Thank you.
Okay. Thank you, Alexander. Let's move on to operations. Let me start with production. 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 initial estimates that was presented in January at the Capital Markets Day. As such, we are increasing our guidance. The main positive deviation is the continued high performance, both in terms of regularity, but particularly the well performance of the two Viper-Kobra wells that was drilled a couple of years ago. You may remember that these wells were planned as the single wells, and that the well plans changed radically during the drilling.
This, 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. 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 million BTU. In total, the production has been strong. We continue to see strong production, although slightly down in the next two quarters, impacted by a decline in the Viper-Kobra and the turnarounds at the Alvheim and Skarv.
I will now walk you through 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 $4.50 per barrel in Q2, which is quite surprising and really good figures. We continue to develop the Alvheim area and continue to follow the strategy we have for the last three years by adding new wells. Two new wells on Volund were completed in Q2. That's P9 and P10. One of them is already on stream, and the second is planned to start production in August. The drilling rig Transocean Arctic has now moved from the Volund template to the Boa template, where it's currently drilling the first of two infill wells.
These two wells are drilled on targets that was identified during the Boa Calm North multilateral drilled last year. After Boa, the rig will move to drill an exploration well in a 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. We continue to see lots of opportunities in the area. Meanwhile, we're also working on a PDO for the Storklakken project towards the end of this year. The Storklakken will most likely be developed as a tieback to the Alvheim FPSO, using the Valje tieback line, with an expected first oil in 2020.
As you may recall, we sold 35% of our owner interest in Storklakken to PGNiG in March. That's taking our ownership down to 65%, or broadly in line with the average share in the Alvheim area. Alvheim continue to be our most important asset and continue to be an asset that outperform expectations. Now, Valhall, which is obviously an asset that's been running by BP Norge and then accumulated into the Aker BP as the merger was completed last year. Production from Valhall was slower in this quarter compared to the previous quarter. This was partly driven by reservoir depletion, and partly driven by temporary shutdowns, mostly related to drilling and well activities. We've had a very high drilling and well activity on Valhall, with four parallel drilling and well operations ongoing at the field at the same time.
The Maersk Invincible has continued a P&A program. The IP drilling rig is progressing well on its infield production drilling program. In addition, we've had two wireline crews running production and abandonment well interventions. The activity has been really high at Valhall. Overall efficiency impacted by the well operations is 85% in the quarter. We continue to work the Valhall West Flank 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 second quarter, with the exception of some downtime due to power-related issues. The main remaining commission activities were completed in Q2, and water injection has commenced starting in May.
The drilling performance has been excellent and even stronger than previously. I will come back to that a little later. I assume the PDO program will be completed during Q3 this year and the rig moving towards drilling of wells at Hyrokkin and Storklakken, and later at Tambar. 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 Edvard Grieg. 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. This performance is highly dependent on a few wells and cyclical in nature. It's likely that the production performance at Ula will fluctuate from quarter to quarter.
The Tambar development project is progressing, focus in Q2 has been on procurement, engineering, and prefabrication in preparation for offshore facility modifications. We expect to start drilling of the two new Tambar wells in Q4 2017, with an outlook of first oil in 2018. These wells will be drilled using the Maersk Invincible rig that has, at that point in time, completed the PDO program at Ivar Aasen. The PDO for the Oda development was approved by the authorities in May, will be developed as a subsea tieback to Ula and will contribute positively to the Ula performance, both through additional gas that will go into our WAG scheme and also through reduced unit production cost.
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 cost. 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 working on this vintage asset will provide important learning for the company also going forward. Moving on to Snadd and to Skarv. The Skarv production was stable and high in the second quarter with a production efficiency of 96%. One of the Skarv wells was shut in during the quarter due to a Christmas tree failure, this has not had any material effect on production as other wells have compensated for the field production.
The well will be repaired and put back on production in due course, 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 Skarv now is to move on and move forward the Ærfugl Phase One development. We are preparing for final investment decision in Q4, the project consists of 3 subsea wells, which will be tied into Skarv and will be ready for production again in 2020. Estimated gross CapEx for phase 1 is about NOK 6 billion, in line with previously communicated estimates. Moving on to Johan Sverdrup. The Sverdrup development is progressing well and according to plan. At the end of the second quarter, we were about 60% complete with the phase 1 facilities construction.
The first steel jacket, the riser platform jacket, had been completed at the Kværner Verdal, we continue to see good drilling progress. The rig is currently drilling 10 injector wells, 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 2018. Now moving on to the North of Alvheim and Krafla-Åsgard area, which we call NOAKA for short. This can potentially become our next major development project. Gross resources in the area are estimated to be in excess of 400 million barrels of oil equivalents, spread across a number of discoveries.
In June, the licenses in the NOA area, the previously called North of Alvheim Area and the Krafla-Åsgard area, agreed on a collaboration agreement and plan for concept selection for a joint area development for the entire NOAKA area. Two concepts are to be evaluated, which the first one is the field hub located at the middle of area, approximately in line with the full 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 Statoil is responsible for the work in the Krafla-Åsgard area. The second concept to be evaluated is two unmanned production platforms tied back to a host platform.
For this concept, Aker BP is the operator in the North of Alvheim area and Statoil is responsible in the Krafla-Åsgard area. We expect the concept selection to occur in the first quarter of 2018. Moving on to exploration. During the second quarter, we completed two exploration wells, namely the Gohta-3 well in the Barents Sea and the Volund Vest well in the Alvheim area in the North Sea. Unfortunately, neither of these wells were successful. However, in the second half of 2017, we will step up our exploration activity. We plan to spud the Hyrokkin well in production license 677, northwest of the Valje field. Hyrokkin is defined as a geophysical anomaly, quite similar to the anomalies we see across the Valje field.
Gross pre-drill volume is in the range of 6 to 55 million barrels of oil equivalent, and the discovery could be tied back to the Alvheim FPSO, adding production to the Alvheim field. Following the Hyrokkin well, Maersk Interceptor will move on to drill the operated Nordfjellet discovery in PL 442 and also drill an appraisal sidetrack into the Delta discovery in the same license. Nordfjellet is a separate fault block in the Langfjellet area, which we drilled last summer and has the same play concept as for Langfjellet. The pre-drill estimate is roughly in the range of 10 to 40 million barrels on a gross basis. Also in the second half of this year, we will participate in the Statoil-operated Central 3 well in the Gina Krog area and the Lundin-operated Hufsa well, needs to have a new name, close to the Filicudi discovery in the Barents Sea.
Moving on to our improvement program, 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 BP are continuing to improve their 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. 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 Valhall drilling platform, we have recommenced drilling after two years of a drilling stop. The first new well commenced drilling in March and has now been delivered at a cost below NOK 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 about 700 meters, again, through an excellent team effort, where our 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 meant we could increase the post-drilling reserves from this well field by about 30%, from nine to 12 million barrels of oil equivalents. Another example, at the Ivar Aasen field, the team continued to deliver solid performance and to set new records. From the first well drilled on the field, the D-10 at 158 meters per day to the latest well, the D-12, which was drilled at a world-class 368 meters per day.
The drilling speed is more than doubled. Still, the team is eager to improve and deliver even higher performance in the next project. 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 improvements in performance. We delivered the West Olen well at less than half of the estimated cost. 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 efficiency and lean operations with high uptime and without any HSE incidents.
Our target is to deliver three 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 break-even 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 infill 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 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.
Hello, Rune Gør from SEB. On Gina Krog, if the Total and OKEA deal doesn't materialize, is that the stake you are interested in? How has the performance on Gina Krog been since the startup?
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 a significant upside and implement our improvement strategy. It's not at the top of our list. Now, the Gina Krog has had acceptable performance from startup. We've had a small leak, as been communicated in the media. Apart from that, it's been acceptable performance from startup.
Okay. Secondly, on the NOAKA, the two field solutions that you're studying, is it too early to say something about the economics between the two in terms of production volumes or break-even levels and so on? 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 concepts. Obviously, we've done some preparatory work to end up with those two concepts. It should be quite clear when we're communicating our intent to stay below 35 that both of these are competitive.
Okay. Thank you.
Good morning. Anders Holte from Danske Bank. Just a couple of questions from me. The seismic spend, as you mentioned this quarter, is that the sort of run rate we should expect quarterly going forwards? Then on the Q3 maintenance on Skarv and Valhall, 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. We decided to grab the opportunity and spent about NOK 17 million acquiring a quite valuable seismic library. Of course, this is following the cost reduction and drop on prices also in seismic on the Norwegian continental shelf. As such, it's in line, of course, with our strategy to increase exploration. You shouldn't expect us to do that every quarter. If that had 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 Skarv and Alvheim. The main scope is change out of key production items that have a limited lifetime, and also inspection programs that necessitate production shutdown.
We expect about 10 to 12 days on each of these fields.
Mattias Dokken, Handelsbanken Capital Markets. Is it possible to talk a bit about tie-in potential of the Nordfjellet prospect, if also possible to say something about the chance of success on that prospect and the prospects? 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? Thank you.
When it comes to, there are two possibilities. Probably the base case is to tie it back to the Alvheim FPSO, either through the Vilje flow line or as an independent flow line, depending on the size if there is a discovery. The Nordfjellet will probably be a part of the NOAKA field development as tie-in lengths are pretty long down to either the Oseberg area in the north or the Alvheim area in the south. I doubt that that can be technically feasible. Discovery is standard in the range of 20%-30% for both these prospects.
When it comes to PDO, 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 high productivity in the construction phase. Far we have seen in line with the market trends, a reduced 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 a result of our improved productivity from our internal improvement programs. I expect this to continue until final investment decision.
Thank you.
Okay. I think we'll take questions from the web, starting with Jayant at Lucror Analytics. Could you please explain the NOK 225 million of tax payable again and why it was not there last year?
Yeah, sure. The book tax receivable of NOK 225, it's really two components in there. It's NOK 140 or NOK 138 to be exact on accrual for taxes payable based on the operations of the first six months of this year. Naturally that wasn't booked last year. 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. I believe also for the latter, about 50% of that has an offsetting booking on the other side of the balance sheet for indemnities on those old tax cases.
Okay. There's a question from Yoann Charenton at Bank of America Merrill Lynch. Could you give some more color on the power issues at Ivar Aasen? What caused it? What stops it happening again? Does it impact Edvard Grieg production facilities?
Yeah. Obviously the Ivar Aasen 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. I'll refer to the operator to comment on the causes 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.
The second question is related to the Hurri prospect. It's missing from slide 19, and has this prospect got partner approval and is it likely to be spent this year, as per the operator's presentation?
Yeah. We are supporting the drilling of the Hurri project. As of currently, we are estimating spud in just over next year and have thus not included it into 2017 drilling program. Should that be the case, we're fine with that. As I said, we're supporting drilling of both the Hufsa and the Hurri prospects in that license.
Okay, last question from Raphael is related to Gohta and how much we still have capitalized for that asset on our balance sheet.
It's $75 million still capitalized.
Okay. There's a question from Teodor Sveen-Nilsen at SpareBank 1 Markets. What full-year production efficiency for Alvheim have you assumed in the updated production guidance?
I think we haven't really given that sort of detail, but it's lower than what we achieved in both the two 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? 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. 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? The second is related to Gohta. When will you or the operator be able to provide an updated resource estimate?
On Sverdrup, again, the operator will be the one who are providing that detail on the CapEx guidance. We should say that 2017 and 2018 are expected to be the two CapEx heavy years on Johan Sverdrup.
When it comes to Gohta, we are working with the operator to assess the results from the Gohta 3 well and the impact on reserves estimates. I assume 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. If we were going to steer 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. Our view is to work as hard as we can to get the cost down and the productivity up. 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 BOE on breakeven. 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. 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 and how to get there?
Well, I think I mentioned that we're expecting around NOK 30 million 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&P. I do not expect those changes to materially impact the rating that was then achieved.
Okay. We got question from Helge André Martinsen at DNB. How will the Valhall IP platform drilling program impact Valhall production going forward? What level of increase can we expect? Will the increase of recoverable reserves per well on Valhall IP increase the book reserves of the Valhall IP, the seven wells?
Well, of course, we wouldn't drill the production wells on Valhall if we didn't believe that they would increase production and/or reserves. If memory serves me correctly, we've already booked the reserves of the seven-well drilling program. Any increase in booked reserves will be a result of increased reserves as post-drill evaluations 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 seven-well program.
The second question there is, could you please indicate CapEx levels for the Valhall 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 NOK 7.2 billion.
Across?
Across, yes.
Across spaces. Okay, next question comes from Nikolas Kuzmanovic at Jefferies. First related to exploration, given the Kayak discovery in the Filicudi Johan Castberg area, Statoil has talked about Kayak as a potential tie-back to Johan Castberg. Would Filicudi or Hufsa Hurri, in the case of success, be viable for tie-backs to Castberg, or would a wider area development potential come into play?
Yeah. Kayak is in the Castberg license, so I think it's quite obvious that that will be a tie-back candidate to the Johan Castberg development. When it comes to evaluations in the Hufsa Hurri area, we agree with the operator that we need to see the result of the drill out or prospects in the area before we conclude on development options. Internally, we're keeping both tie-back and standalone field development options open.
Okay, second question from Nikki related to dividends. You mentioned NOK 30 million annual saving in interests expected post-debt restructuring. Can we expect, once process completed, the floor of the NOK 250 million dividend to be increased even before Johan Sverdrup?
Well, I think working 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-one on savings and dividend level. That's part of the overall assessment on what's the appropriate dividend level going forward.
Nikki, you should also see this as a part of our larger effort to improve cost structure and productivity in the company. That's not only pertaining to the physical disciplines, but also to the financial disciplines.
Okay. We got a question from David Mirza at Deutsche. Could you give us an example as to how your engineers have lowered engineering costs per ton? Is this fewer facilities needing a lighter jackup top or a sub-sea cost reduction?
No, I think so far what we've seen is that most of the effect is coming from engineering related to interface management of the different partners in the value chain. Also related to improved reuse of previous engineering. If you break up the engineering, you consider roughly a third of this is actually related to engineering and procurement management and 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. 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-Kobra currently producing? Do you plan to increase your hedging to reflect the increased production guidance? Lastly, Edvard Grieg appears to be processing more than the expected max volume. Is Edvard also entitled to any of the additional capacity, or is this limited to current throughput agreement?
When it comes to Viper-Kobra, 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 Volund pipeline tying back to the Alvheim field. There's also an optimization game between the existing Volund licenses and Viper and Kobra licenses. Complicated of course by two new high productive wells, the P9 and the P10, coming onto the same template. This is a continuous optimization where we try to keep the water volume flowing in our pipeline as low as possible and thus increasing oil volume up to Alvheim. We have expected to see water incursion in the Viper and Kobra area for a long time now. The development is much slower than we expected initially. Increased hedging.
Again, we still have 15% on the guided production level hedged. We've been monitoring and assessing whether to increase the amount of hedging with 17, and we're also monitoring and assessing whether to hedge for 2018. As of yet, we've not hedged more, and that is a pure pricing assessment.
When it comes to the access to the bottlenecking 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 Edvard Grieg 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 Hosie 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 today.
No, 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 a USD 4 billion facility.
Okay, that concludes the web questions.
Excellent. Thank you everybody for showing up, and thank you for everybody watching on the web. A very good summer to everybody.