On the financial side, there are no big surprises. The EBITDA amounted to $735 million, which is the highest result ever in a quarter for the company and was obviously positively impacted by higher oil and gas prices. Free cash flow was $211 million, which remained well above our dividend, which amounted to $112 million in the quarter. Looking forward, we have a lot of exciting opportunities and activities coming up, both on the exploration side, on the digitalization side, and on the further development of the Frosk discovery. I will come back to all of this in significant detail later on. First of all, I'll let our eminent CFO, Alexander Krane, take you through the financial statements. Alexander, the floor is yours.
Thank you, Karl. In quarter, based on production of 157,800 barrels of oil equivalents per day. We realized an oil price of $76.42 per barrel, which is up 11% this quarter. We had a pretty stable gas price. We realized $0.28 per square cubic meter, which is equal to the same price in Q1. We had production expenses of $164 million. This is a reduction of $10 million from the previous quarter. With the exception of Skarv, we saw a decrease in OpEx across all assets due to less well maintenance, less supply base cost, less shipping and handling, and also some reallocations and reclassifications to CapEx, including R&D. Overall, we had production costs per barrel of $11.40, which compares to $12.10 in the previous quarter. In the Alvheim area, we had costs of $30 million, or $5.40 per barrel.
On Ivar Aasen, we had costs of $17 million. This equals to $7.90 per barrel compared to $10 three months ago. Valhall Hod production cost amounted to $52 million, down $6 from the previous quarter. This is equivalent to a drop from $18.50 per barrel to $17 per barrel. Production costs on Ula Tambar amounted to $29 million. This is down from $34 million in the previous quarter. This cost reduction, combined with the increase in production seen from the Tambar wells, pushed OpEx per barrel down from $46 per barrel in the previous quarter to $29 this quarter. On Skarv, we spent $5 million more this quarter, ending at $31 million or $12.30 per barrel. Not surprisingly, this increase comes as a result of the well maintenance work undertaken in the quarter, and Karl will revert to this topic in a few minutes.
We had EBITDA of $810 million in the quarter. We had exploration expenses of $75 million. Here, we have expensed $30 million in seismic acquisition for new surveys in the Barents Sea. We also expensed the Svanefjell well for another $18 million. In addition, we have the usual field evaluation costs, area fees, and other exploration expenses that make up the balance of the total exploration expenses. We had EBIT come in at $735 million for the quarter. Depreciation was $182 million, or about $12.70 per barrel. We had net financial expenses of $22 million in the quarter versus an expense of $47 million in the previous quarter. The positive change here compared to Q1 is mainly explained by currency effects and unrealized gains on derivatives. As usual, we have note disclosures that shows the various items that make up the net financial items in the quarter.
Profit before taxes was NOK 530 million, and we had a tax expense of NOK 394 million. This gives us a tax rate of 74% compared to 62% in the previous quarter. Here, the higher tax rate is also explained by the currency effects of the U.S. dollar strengthening against NOK, going from 7.84 at the end of the first quarter to 8.2 during this quarter. We had net profit ending at NOK 136 million for the quarter. At the end of the second quarter, goodwill was unchanged at NOK 1.86 billion, while other intangible assets were slightly down, but still booked at NOK 1.99 billion. Net of depreciation, the total PP&E balance increased by NOK 170 million to NOK 5.8 billion at the end of the quarter. Here, we had additions of NOK 338 million and depreciations of NOK 167 million.
Receivables and other assets were NOK 820 million at the end of the quarter. That's an increase of about NOK 57 million in the quarter. The short-term tax receivable related to the tax loss in Hess Norge is valued at NOK 1.6 billion at the end of the quarter. The decrease in value of about NOK 70 million relates to revaluation of NOK balances, as this is a NOK-denominated tax loss sitting in the subsidiary Aker BP AS, previously known as Hess Norge AS. Cash and cash equivalents were NOK 49 million, thus bringing the total assets to NOK 12.1 billion at June 30th, which is approximately the same as the last quarter. If we move to the other side of the balance sheet, equity was NOK 3.064 billion at the end of the quarter.
This is a decrease of about NOK 47 million during the quarter, where the positive net result for the period of NOK 136 million was more than offset by a negative currency translation adjustment flowing through the OCI of NOK 70 million and the dividend payout of NOK 112.5 million. Other provisions for liabilities increased slightly as sitting at NOK 2.99 billion. We had deferred taxes amounting to around NOK 1.5 billion, and this reflects an increase of NOK 168 million during the quarter. This balance arises due to differences between tax and accounting. This quarter, the change can primarily be explained by higher tax depreciation than accounting depreciation, revaluation of tax balances due to FX, and capitalized exploration costs, interest, and actual decommissioning costs that were expensed for tax purposes.
Book value of interest-bearing debt, which consists of the bonds and the bank debt we have issued, were NOK 3 billion at the end of the quarter. We had an accrual for tax payable of NOK 687 million at the end of Q2. The most significant items here are the 2018 tax payable of NOK 439 million and an accrual for uncertain tax positions of NOK 205 million. Other liabilities decreased from NOK 923 million to NOK 861 million in the quarter. This is mainly driven by a reduction in trade creditors and short-term abandonment provisions. Cash flow from operations was NOK 613 million in the quarter. Cash flows from investing activities totaled NOK 403 million, of which around NOK 300 million related to investments in fixed assets. Here, Valhall and Hod accounted for NOK 98 million, Johan Sverdrup accounted for NOK 88 million, and Ula Tambar was around NOK 22 million.
We also recorded decommissioning payments of NOK 72 million, mainly related to the Maersk Invincible running P&A activities at Valhall. We also had capitalized interest of NOK 29 million included in this figure. Thus, free cash flow was NOK 210 million in the quarter. On the financing side, we repaid another NOK 65 million on the RBL, and we now have $3.6 billion of committed undrawn available capacity on our $4 billion bank facility. In addition, we paid out NOK 112.5 million in dividends during the quarter. At the end of the quarter, our cash balance was then NOK 49 million, and the book value of the net interest-bearing debt was NOK 3 billion.
Net debt over EBITDA was lowered again. It's now down to 1.1 times. We still have the NOK 1.5 billion bridge loan included in this net debt figure, whilst the NOK 1.6 billion tax receivable is not included here.
We are still expecting to see a disbursement of this tax loss in the second half of 2018. Finally, we are making some slight changes to our guidance for the full year of 2018. We still expect to see production average between 155,000 and 160,000 barrels of oil equivalents per day, and we expect production cost to remain at around $12 per barrel. The run rates on CapEx in the first six months of the year has been lower than the estimate for the average for the year. We expect spending to be higher in the second half of the year when some projects, like the Valhall projects, are going into a more capital-intensive phase. Therefore, we maintain our CapEx guidance of NOK 1.3 billion. When it comes to spending on abandonment, we are reducing our estimate here from NOK 350 million to NOK 250 million.
The Maersk Invincible rig is running ahead of schedule, and we now expect to finalize its current P&A scope by the end of September. This means that we can move the rig over to the Valhall Flank North project in the fourth quarter, and hence reduce spending on ABEX. This acceleration of scope on Valhall is now included in the CapEx guidance for the year. We're also upsizing our expected spending on exploration activities from NOK 350 million to NOK 425 million. There's three key reasons for this change. First, due to the success at the Frosk discovery, we've managed to secure a rig and commence drilling of another two wells in that area later this year. Secondly, we are investing more in seismic, mainly in acreage connected to the recent license awards.
Thirdly, we are still booking costs related to NOAKA as field evaluation costs and part of exploration until a concept is selected by the partnerships. Now, I will leave to Karl to talk more about these topics and more in his operational review.
On operations. This time, we will go through the assets by assets, and I will highlight the key elements and the key developments as we move along. As usual, first of all, we will start with the Alvheim. The Alvheim area continues to be a success story for Aker BP. The production efficiency is high. In fact, it is almost world-class with a high-performing FPSO. The production cost remains low in this quarter, averaging at $5.4 per barrel, and we have continued exploration success near existing infrastructure, which means every barrel has high value. When we took over Alvheim about four years ago, production was on the decline, and we have subsequently managed to arrest decline through a combination of relentless focus on operational efficiency and data gathering, as well as drilling out resources in the area. This has contributed to solid revenues and low production costs.
We continue to follow this strategy. We have a lot of activities going on at Alvheim at the moment. Earlier this year, two new wells at the Boa reservoir were put on stream. These wells are now giving good contribution to production, and we are currently drilling another infill well at the Kameleon reservoir, which we will put on stream later this year. In addition, we are drilling later this year an appraisal well at Gekko to prepare for further infill wells in the future. We have also embarked on the Skogul field development, which will be subsea well number 35 in the Alvheim area when it is put on production in early 2020. We are also ramping up exploration activity in the Alvheim area. In the first quarter this year, we drilled the Frosk exploration well near Bøyla. The Bøyla, which you may know, is a tie-back to Alvheim.
This well proved up 30-60 million barrels in resources, which was significantly larger than our pre-drill estimates. The reservoir was found in an injectite structure with a high angle, as shown on the picture in the illustration. These structures are hard to see on seismic. Following the Viper-Kobra wells last year, Aker BP has developed in conjunction with our collaboration partners, a seismic imaging tool allowing us to map such high-angle injectites. This Frosk discovery has paved the way for more exploration in the area, and we plan to drill two additional prospects later this year in the neighboring license, Production license 869, where we have a 60% interest following a recent transaction. These two new prospects are named Froskelår and Rumpetroll, both great Norwegian names, which probably can be translated to something like frog leg and tadpole.
The combined gross barrel resource estimates is not impacted by the choice of names and rest at around 60-200 million barrels, which even in the low end of the range, would represent a significant resource addition for the Alvheim area and compound to further success, low cost, and high value in the Alvheim area. For the next step, we plan to embark on early next year is to drill a new well in Frosk, which will be used for test production through the Bøyla template. I am actually extremely pleased that we are able to start production only one year after discovery was made. The learnings from the Frosk test producers and the results from the upcoming exploration well will help us define the best development strategy for this new play.
On Valhall, we are basically following the same playbook as we've used for a couple of years now on Alvheim. Shortly after we took over the field, we launched the IP drilling campaign, which is still ongoing. We immediately started on identifying and maturing new opportunities to create more value from this gigantic field. Through the Hess acquisition last year, we also increased our interest in this area from 36% to 90%. This work has resulted in the Flank West project, which was approved by the authorities in Q1 and are now in the execution phase. We are almost finished with the engineering and construction of the jacket and the topside structure has commenced at Kværner Arendal. We have also commenced on the related modification activities at the Valhall field center.
As Alexander alluded to, the early departure of the Maersk Invincible has allowed us to ramp up investment activity also on the other flanks. We have launched a project to revitalize the North flank of Valhall, where we will drill new water injectors to increase reservoir pressure in addition to a new producer. After the rig is done on the Flank North , the rig will move to the south flank, where it will likely drill two new producers before commencing the drilling campaign on the Flank Wes t. We expect drilling on the north flank to commence in the fourth quarter as previously announced, and these wells should be operational by Q2 next year. The plugging of the old Valhall well is a story of huge productivity gains. Keywords are continuous improvement, technology utilization, and excellent cooperation with our key suppliers.
The time it takes to plug a well has been significantly reduced, in turn, meaning lower cost and an ability to redeploy the asset to probably more exciting drilling activities earlier than previously expected. We are also moving forward with the Hod redevelopment in the Valhall area. The project aims to recover the remaining 64 million barrels gross resources in Hod. The contemplated development concept is very similar to the Flank West with a new unmanned wellhead platform. In preparation for this project, we will drill an appraisal well on Hod next year and aim for a concept select in Q3 2019. Let me remind you that the resource potential in the Valhall area remains enormous. Only 25% of the oil has been produced, and our ambition is to reach around 50% recovery.
We are also stepping on the accelerator to revitalize the Ula as an oil area hub for the future. Basically, again, following the same strategy as for Alvheim and Valhall. When we took over Ula and Tambar, the field seems destined for decommissioning in the mid-20s. Less than two years later, we have turned the trend on production with two new wells on Tambar, and the Ula project is also well underway. However, we think there are a lot more to be done and have established a strategy to revitalize the Ula as an area hub to 2040 and beyond. Through this work, we have identified a number of new drilling targets. In order to drill these targets, we have concluded that the existing fixed drilling rig on Ula is no longer fit for purpose.
We will therefore remove the rig and instead convert the drilling platform to be used in conjunction with a high-performance jackup rig of the generation we've had significant success with, both on Valhall and on Ivar Aasen. On the picture, you see a vessel placing rocks on the seabed in preparation for such a rig. We have also recently contracted a flotel to accommodate more personnel for the conversion work. With this conversion, we will be able to drill new wells longer, more efficiently, in less time and eliminate the maintenance of the aging existing drilling rig. We will continue to mature opportunities at both in Ula and Tambar, and we are continuing to mature new exploration targets which can be tied back to the Ula area. During the quarter, we completed the drilling of two new water injectors at Ivar Aasen.
The picture you can see is of the Maersk Interceptor sailing away from Ivar Aasen after yet another drilling job well done. One of the new injectors have been started up and are performing very well with high injection rates and extremely good connectivity. The second water injector, which is the first of its kind horizontal water injector of its kind at Ivar Aasen, will be started up next week. Based on the drilling results, we expect this well also to be a success. These injectors will contribute to maintaining pressure in the reservoir and hence support production level going forward. As you might recall, the PDO for Ivar Aasen also included the Hanz discovery. We are currently drilling an appraisal well on Hanz, which will give more answers on the resource potential prior to making the final investment decision.
The same well will also test Lengfeldhøgda, yet another excellent Norwegian name, as an exploration target. This could, if successful, provide a meaningful addition to the Hanz volumes. Finally, the Ivar Aasen platform is now probably the most digitalized oil platform in the world. Our digitalization efforts have continued at full speed through the second quarter. We are piloting digital operations in conjunction with Cognite's data platform and onshoring our offshore control room at Ivar Aasen to Trondheim. I will come back to our digitalization agenda very soon. Finally, at Skarv, we are able to keep up production in the second quarter despite several technical challenges on the asset. As you may recall, we have previously reported on some technical issues with the Christmas trees on three wells at Skarv. In Q2, we repaired the second of these wells and put it back on production.
Later in the quarter, a similar problem was discovered on yet another well, and hence we have currently two wells out of production at Skarv. We have also experienced several other technical hiccups in the quarter, but we're able to keep up production through resolute action by our employees and extremely good cooperation with our suppliers. In combination, they were able to quickly repair and replace the necessary components. The key element in our strategy for Skarv is the Alvheim development, which if I am allowed to remind, represents gross reserves of 275 million barrels. The project is moving ahead as planned. The main contracts have been awarded. The technology qualification is progressing well and fabrication activities have started. Alvheim will be developed in two phases, with production start in 2020 and for phase 2 in 2023.
We are now studying the potential for debottlenecking at Skarv, which could accelerate the second phase by up to two years, which would obviously have an extremely positive impact on the net present value of the project. It is also a pleasure to report that Johan Sverdrup remains on track. This picture was taken just after the second topside was installed little more than a month ago. The financial outlook for Johan Sverdrup remains extremely robust, with break-even oil prices for phase one below $15 per barrel. We really look forward to a production start, which remains on track for next fall. In the meantime, the PDO for phase 2 of Johan Sverdrup have been submitted to the Norwegian authorities and will be submitted this third quarter this year.
The project will increase production capacity from 440,000 to 660,000 barrels of oil equivalents per day gross when it's completed in 2022. When it comes to NOAKA, there are no big news to report today. We continue to work on refining the development concept, including offshore wind power, and we are in a constructive dialogue with our main partner, Equinor. We maintain our position that the most profitable concept is a central processing hub, which is also the best alternative to maintain value creation and resource utilization in the entire area. We remain very positive to the total resource potential in the area. Our goal, as previously stated, remains to reach a concept selection in the course of this year. Then on back to digitalization. I've been talking a lot about the potential for digital transformation for both Aker BP and for the industry previously.
It's therefore a pleasure to report that the rollout of Cognite's data platform combined with handheld tablets have commenced and are almost complete at Ivar Aasen. We now have a complete digital twin using Cognite's industrial data platform with live historical sensors instantly available on computers, tablets, and mobile phones. All operators at Ivar Aasen are now using these handheld devices instead of paper. The tablets also have computer vision to read tags, identify components, et cetera. I'm extremely impressed by the speedy rollout that we've seen so far, and we have many other digital projects ongoing at Aker BP. The improved access to data has already enabled new and improved ways of working, and new and improved business models with some of our vendors, and we see extremely high potential in this area going forward.
The main focus for the next 12 months is to continue to work and expand both capacity and capabilities of these digital tools, as well as rolling them out throughout the Aker BP portfolio. As Alexander has previously mentioned, we are increasing our exploration spend this year. This is mainly driven by the follow-up wells in the Frosk area and by two wells to be drilled in licenses that was awarded as late as January. We see exploration as a cost-effective way to increase our resource base, and our exploration strategy is basically following two main themes. The first one we call ILX, or Near Infrastructure Exploration. That means exploration near existing fields, targeting resources that can be produced through existing infrastructure. These opportunities can be developed quickly and at low cost, and may also contribute to extend asset life and hence increase value of existing fields.
The second exploration theme is focusing on finding new wells or new fields with potential for standalone field development. Our efforts would typically be distributed approximately 60/30 among these two, or between these two categories. When you look at this year's program, we can easily recognize this strategy with a number of ILX wells in the Alvheim and Utsira area, and wells with standalone potential both on Utsira High and in the Barents Sea. If we take the midpoints on the remaining wells in Aker BP's 12 well drilling program, this represents an unrisked potential of nearly 500 million barrels net to Aker BP. I think it's easy to see why we are increasing this activity, and we're definitely looking forward to exciting second half when it comes to exploration. Finally, the priorities remain unchanged also in this quarter.
In terms of execution, we maintain a relentless focus on safe and efficient operations. We will continue our work on excellent project delivery. We are continuing unchallenged the improvement work with the focus on cost reduction and productivity gains. Finally, we continue to mature project below the NOK 35 break-even threshold. Finally, we are seeking to maximize recovery from our existing resource base, exemplified by both the projects ongoing at Valhall and Yme that I've been through earlier in this presentation. We are pursuing both organic and inorganic growth opportunities in our portfolio. Thank you so much. We will now open up for questions.
Teodor Sveen-Nilsen, SpareBank 1 Markets. A couple questions from me. First, on Frosk development, is it possible to indicate any total development costs or cost per BOE?
On Frosk, I think that's a bit too early. The total development cost will depend on the total resources in the area and also the results from the Frosk test producer that will be drilled early next year. We'll come back to that as soon as we have more detailed information on the chosen development concept.
Okay. On exploration, you definitely have highlighted you increase exploration efforts this year compared to 2017. Firstly, is that a reflection of that it's not so cheap to buy assets anymore? Secondly, should we expect that activity increase to continue into 2019?
I think first of all, it's actually a reflection of an activity that we've carried out for a number of years. If you look back, we've probably been number 2 in every single round since 2015. That means we're actually the second biggest licensee on the Norwegian Continental Shelf, both in terms of number of licenses and in terms of net acreage. It's actually quite evident that at some point in time, we would have to step up our drilling budget to drill out such an acreage. Then it's also a reflection that the cost of the exploration wells has over time gone down. We're now able to drill exploration targets to mid 3,000 meters in the North Sea in about 14 days, which means it's actually a really cost-efficient way of looking for new resources.
Then as you are obviously aware, we have been agnostic in how we're adding resources to our portfolio with the only key measurement being value accretion to our shareholders. That will mean that at times when the M&A market is hot, we're focusing on organic opportunities and vice versa. That does not mean that we're not looking at inorganic growth opportunities. It means that at this point in time, we're actually just benefiting from the fact that we've been extremely successful in the licensing rounds in the previous quarters and years.
Okay, thank you. One specific question on Gjøkåsen. Also pretty wide resource range. How much do you need to find to make it commercially viable?
Well, that's also a bit of a discussion. We've seen break-even cost drop significantly of these areas, but this is one of the wells where we're looking for standalone potential. I think you need to see a significant resource potential in order to see a standalone potential in this area.
Does that mean 300 million barrels of oil?
So far, we've seen standalone potential as low as 200.
Okay. Thank you.
Okay. Questions on the web?
Yes, we have a few questions there as well. First from Halvor Strand Nygård of SEB. His first question is on tax payable. You have booked NOK 439 million in tax payable relating to first half 2018. Is it fair to assume that one third of this will be paid in Q3 and two thirds of this in Q4?
Yeah, let's just remind everyone that booking and the actual payments, excuse me, in the fall are two different topics such that when we book the tax payable, that is based on the actuals for the first six months. All oil and gas companies do estimate now on this time of the year how much the total tax payable for the 12 months will be. That said, I think the estimate of NOK 439 million is pretty close to what we would expect to pay for the first year. Again, to remind everyone, the first three installments, there is one in Q3, there are two in Q4, and then there is another three early next year. It would be one third of that in Q3 and two thirds of that amount. Yes, we believe that estimate is fair, the NOK 439 million.
Halvor has also one more question. Is it possible to be more specific on the timing of when the Hess tax losses will be disbursed? Q3 or Q4?
I wish I could be more specific, that is an event that we don't really control. We do still believe second half. If it's September or if it's as late as November we don't really know. Obviously we don't expect to see a payment this week or during vacation time now in July. It will be later in the fall. Specifically which month, it's hard to guide for us on that one.
There is one question from Rafal at Bank of America, Merrill Lynch. Regarding cash taxes, assuming $70 to $80 per barrel of Brent for the rest of the year-
Are you still expecting to pay $12 to $16 per barrel in cash taxes for the year as per your CMD guidance? If so, could you help guide on phasing between 3Q and 4Q, given the relatively low rate of cash tax year to date?
Yeah. Okay. Do keep in mind that the actual tax paid in the beginning of this year, that is related to the last three installments of the 2017 tax. What we need to estimate now, it's tax payable for the first six months, payable later this year, and any excess tax on 2017 when you compare those six installments to the actual. I think the latter was around NOK 200 million, that will be part of the tax payable later this quarter. The guidance, I think we said $12 per barrel in a $70 hydrocarbon price, not realized Brent, but a mixed hydrocarbon price. I think if you take that $12 and you use the midpoint of the production guidance, which is 157.5, times 365 days, you get to about 57, 58 million barrels times 12.
You see that you're not far off based on what we have booked already and how we see the forecast for the rest of the year. Long answer, but I think that guidance is still pretty good.
There is a question from Yoann Chardan in Societe Generale. There are three questions, actually. The first is, are you in position to prevent an escalation from the ongoing strike taking hold on the NCS that is led by the union SAFE? SAFE plans to have additional workers on strike from Sunday night. What could it mean for your drilling and production activity in the short term and over the summer?
The part of the first question, no, we are not in a position where we can restrict this kind of activity on the Norwegian Continental Shelf. This is a right that the employees, through their unions, have according to the agreements in the Norwegian system. Second, yes, if the plans to increase the strike goes on, that means that activity in Deepsea Stavanger, which is currently drilling the Kameleon infill and the Valhall DP and IP will have to stop. Right now, we are securing the wells and running liners on Deepsea Stavanger, so it's still not stopped the activity. On DP, it won't have any impact initially because we have a lot of backlog in terms of maintenance, but also in terms of stimulation activities that we can utilize the rig and the remaining crew, rather than continue drilling.
Of course, if the strike is prolonged, it will have, later in the year, an impact on when wells are put back in production. We hope that we won't see that kind of effect. If that's going to happen, the strike needs to be actually quite long. In that case, we're actually feeling quite robust right now.
Yoann had a question on power prices. Power prices have risen in Norway so far this year and are generally expected to remain high for the rest of the year due to unusually low rainfall. What does it mean for Valhall's operating costs going forward? Would you be able to provide some details on your power supply-related contracts?
Well, generally, we're using about 50 MW as a general drawdown, so that should be around 800 MWh or something in that range. If memory serves me right, I think we're spending about NOK 130 on average in power at Valhall each year. We are doing this in a split with long fixed price contracts and spot prices. Again, if memory serves me correct, it's a quite specific question. I think about 25% of the 2018 power has been fixed in low NOK 0.20 per kWh, and the rates remain floating on the spot. Now, if you look at the forward prices, my guess is that if you look at the existing, if NOK 130 is correct, let's say NOK 10 million-NOK 15 million increasing, which is maybe around half a million to a million dollars, something. Not really a big impact, probably.
Long answer to a short question. Sorry about that.
Final question from Yoann. Following the change in your debt structure since the start of the year, would you still guide for an average cost of debt of about 4% in 2018?
Yeah. Well, the funny thing with the higher oil price is that we've drawn less on the bank revolver, and we've had more of the unsecured bonds issuances. The average cost of debt will then trend upwards. It might be higher than the 4%, but given the debt structure, that's probably a figure that's very easy to calculate, just to look at the bond issuances that we have outstanding so.
What seems to be the last question comes from Alvin Thomas of Exane BNP. He actually has three questions. The first is on NOAKA. If the concept selection is delayed further, how much could this save you from your CapEx budget? If you're forced to go with Equinor's proposal, what would be your strategy to develop or monetize the North of Alvheim fields?
Well, we are obviously pushing for as rapid as possible concept selection. Not necessarily because you are saving cost on one budget item and then adding cost on another budget item, but certainly because we want to accelerate the project itself. That's our overriding ambition. On the second part of that question, we're actually quite confident that our proposal remains the most value creative, the best proposal to maximize resource utilization. As such, those are the issues that we're focusing on at the moment.
I think on the CapEx specifically, yes, within the NOK 1.3 billion CapEx guidance we had in the beginning of the year, we had catered for a bit of NOAKA CapEx as such, that goes down. If you recall, we did say that due to the performance on Maersk Invincible, we're able to take that rig, reduce CapEx, move that into an acceleration of the Valhall Flank North . That brings us a bit back up again. It's a bit of pluses and minuses in the CapEx budget there.
Alvin's second question is on production. Can you outline what you expect from your main fields for 3Q18, including any maintenance impact and the power issues at Ivar Aasen?
Well, again, if memory serves me correctly, I think we expect a pretty flat program on all the fields right now. There is work going on at Ula. We've recently had a slowdown to accommodate for the modifications in the hydrocarbon systems necessary to add Oda. Apart from that, I don't think there are any major changes in the next quarter. The power issues at Aasen is hard to plan for, as a result of variations in the power production plan, therefore very hard to guide on the effect of. We've seen a positive development in these cases in the last few months, and we hope that that performance is continued to improve also in Q3.
Okay, then the final question from Alvin, which is also the last question today. Do you think higher competition on the NCS will affect your ability or willingness to look for new acquisitions? Do you think this could also create cost inflationary pressures, and are you seeing any?
Well, we welcome the increased competition on the Norwegian Continental Shelf. We're firm believers in increased competition resulting in higher degree of innovation, better technical solutions and lower costs for the whole industry. In fact, we welcome and are looking forward to competing with the newcomers on the Norwegian Continental Shelf. When it comes to cost and cost inflation, I think that's not necessarily related to the change of structure on the Norwegian Continental Shelf, but probably more related to the, let's say, more optimistic view that the industry seemed to have been taking on the oil prices going forward. If I remind you on our improvement strategy, it's always been to increase productivity, not necessarily to focus solely on reduction of input cost in terms of unit cost.
Therefore, we believe that our improvement strategy is actually more valuable in a higher and more competitive environment, and one where you can see signs of cost inflation in terms of input factors. It means that as the productivity increases, the cost differential actually also increases, our competitive edge will also increase. Then the final question, I think, does it impact our ability and willingness to look for new targets? No, it does not. We will continue to be disciplined and only act when we can see value-accretive transactions. That means value accretive to our shareholders, and have proven that in the last years since 2014 with the first acquisition of Marathon in Norway. If that was the last question, I just want to close off the second quarter results by wishing you an excellent summer and an excellent holiday when you get that far.
Thank you so much.
Thank you