Thank you. A very warm welcome to everybody here from Fornebuporten. A good morning to all. As usual, this has been a very eventful quarter for Aker BP. I wonder when I'm going to stop saying that. Production amounted to about 132,000 barrels of oil equivalent in the quarter and was impacted by plant maintenance at Valhall and Skarv in particular. Based on the strong production in the first half of the year, maintenance behind us, and the outlook for the fourth quarter, we expect full year 2017 production to end in the upper half of the previously guided 135,000 to 140,000 barrels of oil equivalents guidance range. Despite the lower production in the quarter, we present an EBITDA of $395 million, amounting to an earnings per share of $0.33.
The free cash flow was a record $445 million in the quarter. Alexander will walk you through the details in a moment. The board has resolved to pay out dividend of $0.185 per share in November, which is of course the same level as in the previous quarters. Finally, last week, we announced the acquisition of Hess Norge AS, giving us a deeper exposure to one of our core areas, the Valhall area. I will come back both to the transaction and to Valhall in more detail later. On the operational side, we have put two new infill wells on stream, Volund, and are on track to deliver three PDOs before year-end. Before I leave the floor to Alexander to walk you through the financial statements, let me share with you some highlights from the Aker BP acquisition of Hess Norge.
In consideration, we paid $2 billion for Hess Norway. This deal gives us 150 million barrels of oil equivalent of additional 2P reserves and close to 200 million barrels of additional 2C reserves. It brings our ownership interest in the Valhall area up to 100%. We also take over Hess Norway's tax losses at a nominal value of $1.5 billion. We think this is a very attractive deal, both in terms of price, but most importantly in terms of the upside potential we see in Valhall. Valhall is one of Norway's largest oil fields. Since the start in 1982, Valhall and Hod have produced more than 1 billion barrels of oil equivalents. By aggressively targeting the upside potential, our ambition is to get at least another 500 million barrels out of the field.
The acquisition will be financed by drawing $1.5 billion on our existing RBL and $500 million in new equity, which will be raised through a private placement in the market. Aker and BP will subscribe for their respective shares and have guaranteed for the rest at market or at the minimum of NOK 155 per share. Going forward, our plan is to proactively pursue the upsides in the field, sanction new projects, and thus convert resources to reserves by investing more into the asset. You will recognize this as a strategy that we have pursued also in the past. We subsequently intend to farm down an interest in the field to a party which we can work together with to target the unlocked upside potential in the area, either against cash or other assets. We expect to retain about 67% ownership in the field following such a farm down.
I'll leave the floor to Alexander to walk you through the financials.
Thank you, Karl. Good morning, everyone. As usual, I will take you through the income statement, balance sheets, and cash flows for the quarter. I'll also give you a bit of an update on the financing activities that we finalized during the quarter. Finally, I'll give a bit of an update on the 2017 guidance. The acquisition of Hess Norge is not reflected in any of these figures. This acquisition will be accounted for at the time of closing of the transaction. We recorded a total operating income of $596 million during the quarter, of which petroleum revenues accounted for $601 million on a production daily of 131,900 barrels of oil equivalents. Out of these $601 million in petroleum revenues, $508 million came from sale of liquids at a realized oil price of $55 per barrel.
We had $86 million coming from sale of gas at a realized price of $0.20 per standard cubic meter. Production costs amounted to $134 million. This was an expected increase from the previous quarter. This equals to $11.10 per barrel of oil equivalent, and this includes shipping and handling costs of $3.20. If we look at each of the hubs this quarter, we had production costs at Alvheim of $4.50, Ivar Aasen at around $12 per barrel, Skarv, $13 per barrel, Valhall/Hod, $21 per barrel, and Ula/Tambar at $44 per barrel. Karl alluded to this, the higher production cost per barrel on most of our fields this quarter was caused by lower production volumes and costs associated with planned maintenance during the quarter. Other OpEx, corporate G&A came in at $3 million this quarter. We expensed exploration costs of $64 million.
The main items here were dry hole costs of $21 million related to the Hurokken and Nordfjellet wells. We had acquisition of seismic data this quarter of $16 million, we had other exploration expenses, which includes area fees, it includes field evaluation costs of $28 million. This gave us an EBITDA of $395 million, which is pretty much in line with the previous quarter. After we deduct depreciation of $175 million or $14.50 per barrel, we get to an EBIT of $219 million. Net financial items were a negative $9 million this quarter. That's much impacted by the strengthening of the NOK against US dollar during the quarter. Net interest expense were $27 million. This was down from $31 million in the previous quarter. We had accretion expense of $33 million, in line with previous quarter.
Offsetting these two items, we saw financial income of $55 million, mainly from realized and unrealized gains on derivatives. Profit before taxes was $207 million. The tax expense this quarter was $97 million, which gives us a tax rate of 46%. Included in this amount was a payable tax of $66 million, and we had a change in deferred tax of $28 million. Despite a quarter with planned maintenance, we saw a record net profit for the quarter of $112 million, or $0.33 per share. Our balance sheet is down approximately $200 million in the quarter, ending at $9.1 billion at September 30th. Both goodwill and other intangible assets were virtually unchanged from the previous quarter. Net of depreciation, property, plant, and equipment came in at $4.8 billion. It was a slight increase of $57 million compared to previous quarter.
Receivables and other assets were $676 million at the end of the quarter. That's a small decrease from the previous quarter of around $18 million. This was mainly related to a decrease in accounts receivable, but partially offset by changes in other short-term receivables, inventories, and short-term derivatives. The short-term tax receivable has, as expected, been reduced this quarter after a tax refund of $264 million was disbursed. The remaining balance of $145 million is expected to be paid out during the fourth quarter. Cash and cash equivalents were $81 million at the end of the quarter. On the other side of the balance sheet, book equity was $2.5 billion at the end of the quarter, up from the previous quarter due to the profit we saw this quarter. Other provisions for liabilities were unchanged at $2.3 billion.
Deferred taxes increased by $12 million during the quarter and ended up at about $1.14 billion. Book value of interest-bearing debt was $2 billion at the end of the quarter. This comprises of $1.4 billion drawn on the reserve-based lending facility and $626 million relating to the two bonds that we have outstanding. Other current liabilities, this increased about $50 million during the quarter to $882 million. This reflects an increase in short-term abandonment provisions and other current liabilities. Finally, we had tax payables of $265 million, which about $180 million is expected short-term tax payments. Again, do keep in mind that this does not reflect any of the effects seen from the Hess transaction that Karl discussed a couple of minutes ago.
On the back of a continued strong production in the quarter and the one-off tax effects in the quarter, we generated cash flows from operation of $730 million. Cash flows from investing activities were $285 million. Of this, we had investments in fixed assets of $226 million, where Johan Sverdrup accounted for $75 million. Alvheim, and that's mainly the Boa infill wells, accounted for around $40 million. Ivar Aasen accounted for $21 million, Valhall/Hod $20 million, Ula/Tambar $19 million, and finally, we had some capitalized interest of $24 million. In addition to these investments in fixed assets, we had investments in intangible assets of $33 million, and we had decommissioning payments of $27 million. The latter mainly related to the Maersk Invincible drilling rig and its P&A activities at Valhall. Thus, we had a free cash flow in the quarter of $445 million.
Cash flow from financing activities includes the cash effects of the $400 million new bond issuance and the repayment of the DETNOR03 subordinated bond. In addition, we repaid around $410 million on the RBL during the quarter for cash management purposes, and we also paid out $62.5 million in dividends. The end of June cash balance of $81 million, and the book value of net interest-bearing debt was $1.94 billion, and that is down around $360 million from the previous quarter. We had net debt over EBITDAX. It decreased from 1.1 times to 1.0, and we had available liquidity of around $2.6 billion. As previously communicated, the $550 million RCF was canceled during the quarter. We also finalized the process of amending and simplifying the $4 billion reserve-based lending facility. The facility amount and tenor is unchanged, and the facility still has an uncommitted $1 billion accordion option.
The available amount is now determined annually based on a per-barrel multiple, and we have full access to the $4 billion amount. The interest rate is LIBOR plus a margin between 2% and 3% based on how much of the facility that is drawn. Year-to-date 2017, our free cash flow, and that is cash from operation, less cash spent on investments, has been $746 million, while we, in the same period, have paid out $188 million in dividends. This equates to a free cash flow cover of almost four times. Even if we adjust for the one-off tax effect we saw this quarter, free cash flow coverage in the first three quarters were about 2.5 times. In the past three quarters, we paid out a quarterly dividend of $62.5 million, and the board has resolved to also pay a dividend of $62.5 million in November.
With this strong cash flow generation in 2017, the robust balance sheet of the company, and the further strengthening of our earnings capacity following the Hess transaction, we announced last week an increase in annual dividends by $100 million to $350 million per year, with the first uplift from the fourth quarter now in 2017, meaning the dividend that is payable in February 2018 and onwards. When it comes to the 2017 full-year guidance, we are only making some minor changes to the guidance today. Again, note that we are not including any effects from the Hess transaction. With the planned maintenance in the third quarter behind us, we see that it is likely we will achieve the upper half of the full-year guidance on production in between 135,000 and 140,000 barrels per day.
Production cost has averaged $9.90 per barrel in the first nine months, and with sustained high production in the fourth quarter, we stick to the original guidance of $10 per barrel for the full year. CapEx for the first nine months amounted to $663 million, whereas we still expect a total spend for the year to lie between $900 million and $950 million. Cash spent on exploration was $196 million in the first nine months of this year. We make no changes to the full-year guidance of $280 million to $300 million. As for decommissioning costs, cash spent was $55 million in the first nine months of the year. Due to lower expected full-year spend and slight change to scope, we now see a total 2017 commissioning cost to be in the range of $80 million to $90 million.
Note that while the original guidance was based on a dollar NOK exchange rate of 8.5, we now adjust the point forward guidance to be based on an exchange rate of eight. When it comes to guidance for 2018 and effects of the Hess transaction, this is something we will cover in our capital markets day, which is planned for January next year. That concludes my financial section, and I will let Calle walk you through our operations.
Thank you, Alexander. While we have been busy on the M&A front, there is no less activity on the operations side. I'll spend a little time today walking you through the key highlights of this quarter. Alexander started out by saying that we hadn't included the effects of the Hess transaction. In this slide, I've cheated a little bit and for illustration purposes included the Hess volumes from effective date of 1st of January 2017 to illustrate the production development in Aker BP from early 2015 and onwards. As we've already discussed, we have achieved a production level of 132,000 barrels of oil equivalents in Q3. This is somewhat down from the levels that we've seen in the first half, mainly due to planned activities and some normal depletion as predicted earlier in the fields.
Last quarter, we increased our guidance from 128,000-135,000 up to 135,000-140,000 barrels of oil equivalents per day. On the back of better-than-expected production, especially from the Valhall area, the fact that we have maintenance behind us and the recent updates from the operation, we expect the production to end up in the upper half of this 135,000-140,000 barrels of oil equivalent range. On pricing, we achieved an average oil price of $55 per barrel in the quarter versus Brent at $52 per barrel. The premium of $3 is higher than normal and mostly driven by favorable timing of lifting activities in the quarter. I think it's only natural to start this asset review with Valhall, as we will be the 100% owner of the asset when the Hess transaction is completed.
Valhall started production already in 1982. The field center today consists of six separate steel platforms, including a process and accommodation platform that was put in place in 2013, preparing the field for decades of production. Production from the Valhall area was lower in Q3 than in Q2, mainly driven by plant maintenance and temporary shutdown of wells related to drilling and well operations that are ongoing at the field. The IP, that's the well drilling center program, is well underway. This will add seven new production wells in the central part of the field. The drilling performance has been excellent to date. This is exemplified by the last well, which was completed 20% below budget and 14 days ahead of schedule. In fact, this was the shortest completion time of any well ever recorded on Valhall IP.
The Valhall area contains massive in-place volumes, only just over a quarter of the in-place volumes have been produced to date. Our ambition is to produce at least another 500 million barrels in the coming years, I fully expect that we can increase this number over time as we continue to work the asset. Going forward, we are applying new technology to increase field recovery. This includes multilateral wells that we have a lot of experience with from the Alvheim area, new completion techniques to replace fracking in the Chalk reservoir, improved monitoring and modeling, which in turn leads to better production and better decisions and increased oil recovery. We are also applying new technology to radically reduce time per well in relation to our P&A activities. I will come back to some of these programs later.
In addition, we have initiated a series of projects where digital technologies are induced to reduce cost and increase productivity. As you know, we are working towards a PDO for the Valhall Flank West by year-end. This will be developed by an unmanned wellhead platform with 12 well slots tied back to the field center. We will revert to the market with more details on CapEx and reserves for the Valhall Flank West as the PDO is finished. What I can say at this stage is that we consider this a highly attractive project, both in terms of CapEx per barrel and in terms of break-even oil price. We also have a long list of additional projects in the Valhall area that are at different stages in terms of maturity and which we are working on in order to convert more resources to reserves and eventually production volumes going forward.
I think many of you will recognize that this is basically the same strategy that we have pursued successfully in the Alvheim area in the past few years. Speaking of Alvheim, our production in the Alvheim area was slightly down in Q3 compared to Q2. Production was impacted negatively by some outages in the SAGE gas export pipeline and a planned emergency shutdown test. Still, the production efficiency was 96%, underlying the strong operation performance of this asset. Two new Valhall wells were brought on stream in Q3 and have shown excellent production so far. The Viper-Kobra wells, which have contributed strongly to the Alvheim production this year, is also being produced through the Volund subsea manifold and have been choked down to make room for the new Volund wells.
The next infill drilling target is Boa, we have started drilling of the first of two infill wells at Boa. In parallel, we are planning to submit a PDO for Storklakken before year-end. Storklakken will be developed as a subsea tieback to Alvheim FPSO via the Vilje pipeline, we expect first oil in 2020. At Ivar Aasen, things are basically developing as planned. The facilities have been working flawlessly, the operational availability in Q3 was a staggering 97%. We did, however, experience some power issues also in Q3, which has brought the overall production efficiency down to 82%, resulting in a slight dip in production. The overall scope in the PDO has now been completed. That is all systems up and running, all wells drilled. In Q4, we expect to increase production from the Ivar Aasen field in line with the capacity agreement with Edvard Grieg.
In fact, the field has reached its projected plateau already one year ahead of plan. The next step for Ivar Aasen now is to drill another two water injectors in the east part of the field for pressure support. We also plan to drill an appraisal well at Hans, which is a tie-back to the Ivar Aasen. First oil of Hans is expected in 2020. In addition, as we normally do on all our fields, we have initiated an IOR program at Ivar Aasen aiming at increasing reserves and recovery over time. Basically, the same strategy. Production from Ula and Tambar is dominated by a few wells and is highly dependent on the effect of water alternating gas injection. Due to the cyclicity of this injection activity, production is also likely to fluctuate from quarter to quarter.
In Q3, we experienced a slight downtick in production while we in the previous quarter saw a significant increase. The Tambar redevelopment project is progressing on track, we have now commenced drilling of the first of two new wells. We are also installing a new gas lift module to facilitate the Tambar production. First oil from the new Tambar wells is expected early next year. This Tambar story demonstrates Aker BP capability, capacity, and willingness to invest to create value on the Norwegian Continental Shelf. It's a great example of what we are aiming for achieving on all our mature assets. Before we took over operatorship, Tambar was heading for decommissioning.
Only one year later, we have shot new seismic and now started drilling new wells to revitalize the field. This will create value for our shareholders and for the society, and it's a solid demonstration of our strategy in existing fields. The Ula field, which will be developed as a subsea tieback to Ula, is also moving forward. Even though Ula is a small part of our portfolio, it will have a positive impact on Ula for providing additional injection gas and reducing the unit cost when it starts production in 2019. Skarv, the production also dropped somewhat in Q3. This is mainly driven by plant maintenance, but it's also driven by two wells that are shut in due to technical issues. The Snadd test producer reached its annual production volume limit earlier in Q3 and is also shut in for this reason.
We are currently running a rig operation in order to re-complete the two shut-in wells, and if operations go smoothly, we'll bring the wells back on stream in Q4. The main growth initiative at Skarv is the development of the Snadd reservoir, we are on track to deliver a PDO for Snadd by year-end. Snadd will be a two-phase development, each phase will consist of three subsea wells and associated tieback. Phase one will commence next year with first gas in 2020, with a CapEx of roughly NOK 6 billion. Thereafter, we will do phase two, which is basically a repeat of phase one for the other half of Snadd. This will secure high utilization of the Alvheim FPSO for years to come. Snadd is also a technology project, where the first application of directly electrical heated pipe in pipe will allow for the long tieback.
We're really excited about participating in the development and utilization of new technology also on Snadd. On Johan Sverdrup, the story just keeps getting better. Statoil is still doing an excellent job as an operator of this giant oil field, and construction is now 70% complete. The first steel jacket has been installed offshore, as you can see in the picture, and there is good progress on the drilling site as well. The project is firmly on track for first oil in 2019, and the cost estimates for phase one has been further reduced since last quarter from NOK 97 billion down to NOK 92 billion. 3Q has been a quarter impacted by activities related to maintenance and modification on our installations.
This kind of activity is, for us, an integral part of how we run our operations and how we secure a long and prosperous lifetime for all our fields. As a part of our improvement strategy, we are investing heavily in maintenance and modification. In fact, we have currently about 70 active projects related to maintenance and modification ongoing. The industry has, for the last few years, been reducing the MMO scope on the Norwegian continental shelf. In Aker BP, we believe in pursuing a strategy where we aim to maximize productivity to ensure that we deliver as much scope as we possibly can for every input unit factor. The key reasons for this project is to pave the way for increased production, increased uptime, increased lifetime, facilitate tieback, and in general, reduce cost per barrel over time.
We're really proud of the activities that are currently ongoing on our assets. In the same manner, the improvement program is starting to show tangible results. We are building strategic partnerships and our efforts to rearrange the value chain, align incentives, and deliver projects more effectively is starting to show tangible results. One example is the Volund infill project, where we utilize the subsea alliance with Aker Solutions and Subsea 7 and deliver the project 30% below budget, where we've also reduced, as you can see on the graph, for market effects of another 30%. We will continue to work on this strategy and deliver more alliances in the time to come. Another good example of how we work on continuous improvement is the P&A campaign at Valhall.
BP started this P&A activity, as you can see, had really good results from 2014 to 2016. Aker BP commenced on a new campaign earlier this year with a new rig. By applying the learnings from the BP campaign, continuous improvement, and applying the latest and best technology available, we've been able to continue the positive development and increase the speed. The last two wells have in fact been plugged in less than 30 days. In addition, we are progressing our vision of a fully digitalized value chain. Following a process where we systematically assessed ongoing initiatives in the industry, as well as other opportunities in other industries, we decided to support the creation of a new company called Cognite, where we today own 10%.
The main objective behind the establishment of Cognite is to create a data platform based on open architecture, well-documented interfaces, and with a data architecture general enough to handle all our data. The mantra will be that all data should be available always on any platform. In Aker BP, we believe that the challenges posed to this industry cannot be solved alone, and that all solutions to be used by Aker BP in the future must support open architecture. Further, we firmly believe that sharing of data between the companies is a prerequisite for success, and that no one company can solve all these challenges alone. All these activities are aimed at increasing productivity and reducing cost, which will allow us to do more projects and add more projects to the portfolio with break even of less than $25 per barrel. Moving on to the exploration drilling activity.
The Hurokken and the Nordfjellet prospects were drilled during the quarter, both unfortunately dry. The Delta appraisal well provided us with valuable information about the Frigg Gamma Delta discovery, and we are now in the process of analyzing the data in order to confirm the reserve estimates for the field. Drilling on the Lundin-operated Hufsa prospect started earlier this month, and results are expected shortly. After drilling of this well is completed, we will move on to drill the Hurri prospect in the same license. While the results of the 2017 drilling campaign in the Barents Sea could have been better, we are still excited about our 2018 Barents Sea campaign. Next year, we plan to participate in four to six wells in the Barents Sea, including Stagnestinden well on the Fedinsky High and Svanefjell on the east side of the Loppa High.
We will revert to the 2018 drilling schedule in the capital market day in January, and this will include pre-drill estimates for the different wells we plan to drill. Before we round off and open for Q&A, let me summarize our main priorities ahead. Please note that this slide is basically unchanged since last quarter. On the execution side, we continue to work hard to deliver efficient and safe operations with focus on optimizing production and keeping cost at bay, and without any HSE incidents. We also remain firm in our ambition to submit three PDOs by year-end. As we are closing in on the deadline, we remain optimistic that we can achieve this. We continue our improvement program, which is not a traditional cost-cutting exercise as I've tried to demonstrate.
Instead, our ambition is to make radical changes to the way we work in order to achieve step changes in efficiency and cost. Three examples. New collaboration models with suppliers will allow us to increase productivity and reduce cost. Redesign the work processes will achieve better flow efficiency, higher productivity, and ultimately lower cost, as demonstrated in the Invincible P&A case. Finally, digitalization in order to increase value of data and speed up our decision processes will enforce the previous two mentioned projects. Our overarching threshold for new development is a break even below $35 per barrel. This is an ambitious target which instills a huge amount of discipline in the organization and which will, over time, translate into attractive returns for all our shareholders. On the growth side of our business, we have planned for increased exploration activity next year.
Alexander already alluded to the fact that we have increased seismic acquisition in Q3. While we're also working to mature the contingent resources in the vicinity of our field in parallel with the ongoing exploration activity. Finally, as illustrated by the Hess acquisition, we continue to pursue selective organic growth opportunities, where the aim is to enhance production and increase dividend capacity. That concludes our presentation of today. We will now open up for questions. Jonas and Tore, will you assist us?
Teodor Nilsen, SB1 Markets. First on Valhall, really exciting this project to convert resources into reserves. Should we expect any impact on year-end 2017 reserves by the current project, or should we look more into year-end 2019 to see any material impact on the 2P reserves?
When we get to the capital markets day update on the end of 2017, I think the expectation would be that if we manage to successfully sanction projects and deliver PDOs before we go on Christmas holiday, that would impact a conversion of those projects from resources into reserves.
Okay, that's clear. For third quarter, the P&L tax rate was very low. Could you provide some color on that? Should we expect the tax rate to stay that low? The P&L tax rate.
As you know, and you'll find it in the back of the financial statements, it's a very complex tax calculation. What impacts it is the change in FX rate. As you know, that is calculated in NOK when you do the taxes, then convert it. This quarter, it is low. FX materially impacts that. Lots of details in the tax note where you can see the changes and the temporary differences and how that rolls into the change in deferred taxes. I mentioned the payable tax, which is part of the P&L tax rate, and that is impacted by the tax payment we had this quarter.
Again, as you know, already in May of this year, we need to estimate what we think the payable tax will be, and there's three installments in the fall of this year, and then there's three installments in the beginning of next year. There was one installment during the quarter, which gave that element of the P&L tax. The change in deferred tax is of course the tricky one, which is made in NOK. Extrapolating how that will be going forward is somewhat difficult.
Yes, understood. Then finally on M&A. You say that you will continue to pursue M&A opportunities, which of course makes sense in this part of the cycle. Do you still see sufficient opportunities in Norway, or will you consider to also grow the portfolio outside Norway?
Leave that to Karl.
Thank you. We have this agreement, he'll do the hard one, and I'll do the easy ones. We are a Norwegian pure-play company. Aker BP will not pursue M&A activities outside of Norway. Maybe with the exception where there might be cross-border issues related to fields and operations that we have ongoing on the Norwegian continental shelf. We see lots of opportunities in Norway still. They may not be that easily transparent from outside.
Okay. Thank you.
Marius Lorentzen from E24. I have two questions for you. The first is on your decommissioning expenses, if you could elaborate on that increase and where it's coming from. The second question is about your power issues with Ivar Aasen towards Edvard Grieg. Are those resolved now, or do you expect further challenges throughout the year?
The first one, Marius, was about decommissioning.
Yeah, the decommissioning costs that you're-
It's decreased, not increased.
Oh, I'm sorry. My bad.
Yeah. That's okay.
Could you elaborate on where that's coming from?
The decrease in the decom expense, it's just a slight change of scope in 2017. Karl did talk about the operations of Maersk Invincible and how that rig who's doing the P&A activities has been better than expected. That rig is still on contract for the full year, we're not seeing any efficiencies as such going into that CapEx spend this year. That would be more in later year we'll see effects of that. It's not a big change, but it's predominantly on the timing and scope this year.
On the power issues with Edvard Grieg. First of all, we're working very well with Lundin to solve the power issues. The collaboration is extremely good. The work is ongoing to resolve the power issues, we are confident that we will resolve them shortly. In addition, we're taking compensating measures by running our essential generators and are also in the process of taking out diesel booster pumps in order to alleviate the spikes in the power claim as we boost up and down the main drivers on the Ivar Aasen field.
Hello. Iver Baatvik from ABN AMRO. Just a question on the Snadd technology development there and the heated pipe-in-pipe technology, how much that means for the breakeven on the project, the different suppliers of that solution and the technology risk associated to using that technology. If you could help us understand that a bit better.
Yeah, sure. Directly heated pipeline has been used in the industry for a number of years. This is the first time we've used or are going to use directly heated pipe-in-pipe, meaning you have an inner pipe and an outer pipe, and then you have the insulation and the heating within the annulus between these pipes. Both Subsea 7 and Technip are in the process of qualifying this technology. It has been used elsewhere with great success. In terms of application, this is mostly about extending tieback areas and reducing cost related to flow assurance. Otherwise, you would have to inject chemical engines] into the pipeline stream to reduce hydrate risk, et cetera. We firmly believe that this is a technology that not necessarily carry extra cost and extra risk on the execution, but it's still technology that needs to be qualified and brought forward.
It will also be technology that will allow further tiebacks for other operators on the Norwegian Continental Shelf.
On the economic impact for the field?
Well, of course it reduced cost in as much as we are reducing the need of utility equipment that we will otherwise use to guarantee flow assurance through the pipelines, such as MEG rotation, MEG regeneration on the FPSO, et cetera.
Okay, thank you.
Okay, we have a few questions from the web as well. Let's start off, I think this question was partially answered earlier from Marius's question. Rafael Gutierrez at Bank of America is asking whether the decom cost, the reduction there is a one-off, or if we can extrapolate that run right into 2018.
Okay. Yeah, it sounds a bit similar. Again, it's a slight change of scope this year. The stellar performance on the Maersk Invincible rig will not have an impact this year. That will be, hopefully, seen going forward. Also do keep in mind that the decommissioning guidance we had this year, it did not cater for a full year with the Maersk Invincible rig. We'll be updating that guidance for 2018 with a full year of Maersk Invincible operating.
Okay. We'll take a question from Alwyn Thomas at Exane. How long will the MPE allow you to keep 100% of Valhall?
Well, as we've already stated, our full intention is to sell down to a 67% roughly, either in terms of cash or in terms of a swap. We do expect that there will be a condition from the Ministry of Petroleum and Energy of a sell down. Our intention is to do this as expeditiously as we possibly can while still catering for the fact that we do intend to sanction a number of projects in the next few months.
Okay, we'll take a question from David Mirzai at Deutsche Bank. We had expected two weeks of planned maintenance on Greater Alvheim in the third quarter. Why was this not performed? Second question is, can you give us more color on the key risks of the Hurri and Hufsa wells?
Maybe I wasn't 100% clear. We did perform a maintenance stop on Alvheim this year, but we managed to short the duration from the prognosis to 14 days. The main activity in that Alvheim shutdown was a test of the emergency shutdown system that was initiated at the commencement of the maintenance stop. Now, the Hufsa and Hurri wells are in the same area as Filicudi. That means that these are structural traps in an extension basin. While I won't go into specific risks on these wells, the general risks in this area, meaning reservoir placement, reservoir quality, and cap rock and sealing are the key risks of those two wells.
Okay, a question from Ryan O'Sullivan at Citi. Could you provide more detail on the tax refund following the liquidation of BP Norge? Is there likely to be further refunds related to the liquidation?
Okay, the tax payment of NOK 264 million in the third quarter, that solely relates to the tax loss that was sitting in BP Norge when that was acquired. The tax refund that we are expecting to see in the fourth quarter for around NOK 140 million, that is related to the exploration activities that we had that will be reimbursed this year. That is happening because we had a tax loss in 2016. There's no further refunds expected from BP Norge. The tax effects of the Hess transaction, we talked about earlier in the week or last week, but that is not included in these figures that are accounted for this quarter.
Okay, we'll take a couple of questions from Nikolas Kuzmanov at Jefferies. First, related to the Hess acquisition. The working capital assumption upon completion, is that expected to reduce or increase the $2 billion headline consideration? The question, why do you raise $500 million equity if paid back within five years of increased dividends?
Okay, the first one first. The effective date of the Hess transaction is January 1st, 2017. That means we'll be going through all activities and operations in 2017, and there will be a pro forma settlement upon closing, which is expected before year-end. What that number will be based on all activities during the year, that is a bit too early to say.
That will be announced upon closing of the transaction. When it comes to the equity raise, we are in the fortunate position to have very supportive shareholders and raising equity as part of this transaction and making sure we have the robust balance sheet going forward we think is a great position to be in. Raising that equity, having that robust balance sheet and being able to do further organic or inorganic opportunities, we think is a great spot to be in.
Yeah. In addition, as Alexander already pointed out in the demonstration, the cash generation in Aker BP in the past quarters has more than supported the dividend policy that we've had. Looking forward with increased production, increased capacity, we thought it prudent to also cater for a bit higher dividend yield in the share.
Okay. The last question from Nicky is related to Storklakken. Can we expect any Vilje choke back due to the share infrastructure by that time in 2020 when Storklakken starts producing?
That, of course, remains a bit to be seen. Our assumption as of today is that there will be sufficient volume in the pipeline to cater for both projects.
That's all from the web.
I say thank you for coming here to the three-quarterly presentation, and have a safe journey home.