Good morning, everybody, welcome to Aker BP's third quarter presentation in 2018. I'm used to saying this has been another eventful quarter for Aker BP. As we announced a couple of weeks ago, we have ended up with a production of 151,000 barrels of oil equivalents in the quarter. This was somewhat below expectations, and I'll come back to the main reasons for this later in the presentation. In the exploration area, the quarter was characterized by quite high activity, as we see exploration activity both in Aker BP and on the Norwegian Continental Shelf picking up. We had three dry well cat wells in the quarter, but the appraisal wells on Hans was encouraging. Gekko, which I'll come back to in a little while, was very encouraging.
I'm also pleased to report that all the development project, the many development project that are progressing in Aker BP is going according to plan. As Alexander will revert to, we now expect CapEx for 2018 to end up lower than previously assumed. On the financials, I guess the numbers are largely where they should have been, given the production volume, the oil and gas prices that we've seen in the quarter. Just to remind you, EBITDA was $736 million, up $1 million from Q2 and at an all-time high for the company. Free cash flow ended up at a solid $240 million or $0.67 per share, more than two times the $0.31 per share in dividends in the quarter.
When it comes to dividends, when we have paid out the last dividend in 2018, we would have delivered on our $450 million dividend payment in 2018. As I am sure you are aware, we intend to increase this by $100 million each year going forward until 2021. We have also made two acquisitions recently, which we will cover in more depth a little bit further in the presentation. Finally, we will give you a glimpse for the first time of the Ula redevelopment plan, which all the development project in Ula is tied into, inclusive of the new acquisition of King Lear. Now I will give the floor to Alexander, who will walk you through the financials.
Thank you. Good morning, everyone. This quarter, we recorded income of $1 billion on a production of 151,000 barrels of oil equivalents per day. We realized an average oil price of $77.88 per barrel in the quarter, which is up 2% from the previous quarter. We had a gas price of $0.30 per square cubic meter, which represent an increase of 8% from Q2. We also booked a one-off tariff compensation at Ula of $23 million this quarter, and this is included in other operating income. Production expense was $165 million, in line with the previous quarter. Overall, we had a production cost per barrel of $11.90, a small increase from $11.40 in Q2. In the Alvheim area, we had production cost of $30 million, or $5.60 per barrel. On Ivar Aasen, we had costs of $19 million.
This equals $8.80 per barrel and is slightly below the average year to date, which is $8.90. Valhall and Hod production costs amounted to $57 million, slightly up from Q2 when we had some non-recurring credits. Production cost per BOE for the quarter was unchanged at $17 at Valhall. Despite the lower production we've seen on Skarv in the quarter, production cost per BOE for the quarter was actually down $1 to $11.30. This equals a cost of $24 million, and the reduction here is mainly driven by less work over in the quarter. Finally, production costs at Ula Tambar increased by $4 million this quarter, ended at $32 million, and this is equivalent cost of $34 per barrel. This gives us an EBITDAX of $830 million. The exploration cost for third quarter was $94 million. This is an increase of $18 million.
The increase is mainly driven by the fact that we had three dry exploration wells this quarter, compared to only one dry exploration well in the previous quarter. We had booked additional costs relating to the Nuara field evaluation this quarter. We've also expensed $30 million in seismic acquisitions for new surveys this quarter. This is the same level as in Q2, and most of the seismic acquisitions in the third quarter is around existing hubs in the North Sea. We've also acquired some new seismic up in the Norwegian Sea. We had the usual area fees and other exploration costs that make up the balance of the $94 million. EBITDA was then $736 million. Depreciation this quarter was $189 million, or $13.60 per barrel. We had net financial expenses of $58 million.
This is higher than in Q2, when we had some positive FX changes then, and we also had some realized and unrealized losses on derivatives this quarter. Profits before taxes was $490 million. Taxes amounted to $365 million. This gives us a more or less unchanged tax rate of 74.5%. With the positive development in oil prices, our tax rate levitates towards a marginal 78% tax rate. The tax effect of uplift reduces the tax rate for Q3 down from 78%, but the tax effect of financial and other items taxable at 23% drives the tax rate up. The tax expense here is made up of payable taxes of $219 million, and a change in deferred taxes of $146 million. Net profit then ended at $125 million for the quarter.
We turn to our balance sheet, we see that there are no significant changes in goodwill or other intangible assets. Net of depreciation, the total PP&E balance increased by $204 million to $6 billion in the quarter. Receivables and other assets were $752 million at the end of the quarter, a decrease from the previous quarter of $68 million. The $1.6 billion tax loss that we acquired from Hess Norge is sitting as a short-term tax receivable, and we are still expecting to see a disbursement of this tax loss in the fourth quarter. Cash and cash equivalents were $127 million at quarter end. Our assets amounted to $12.4 billion at September 30th, which is approximately the same as we had last quarter. Equity was $3.1 billion at the end of the quarter.
This is an increase of $19 million during the quarter, where the positive net results for the period of $125 million and the positive currency translation adjustment through OCI of $6.5 million was partially offset by the $112.5 million dividend payment. Other provisions for liabilities increased slightly to $3 billion. Deferred tax amounted to $1.67 billion. This reflects an increase of $146 million from the previous quarter. This quarter, the change can be primarily explained by capitalized exploration cost, interest, and actual decommissioning costs that are expensed for tax purposes, and a higher tax depreciation versus accounting depreciation. Book value of interest-bearing debt, consisting of bonds and bank debts, was $3 billion at quarter end, while other liabilities were relatively unchanged at $857 million. Our accrual for tax payable was $754 million at the end of Q3. The most significant items here are the 2018 tax payable of $508 million.
We had a remaining tax payable for 2017 of $42 million that we expect to pay in the fourth quarter, and we had an accrual for uncertain tax positions of $202 million. Cash flows from operations were $697 million in the quarter. Cash flows from investing activities totaled $457 million, of which around $340 million are investments in fixed assets. Johan Sverdrup was the largest contributor with $97 million. We had Valhall Hodd, which accounted for $90 million, and Alvheim, which saw $61 million of investments. We also recorded decommissioning payments of $72 million, mainly related to the Maersk Invincible rig doing P&A work at Valhall, and we also capitalized exploration expenses here of $45 million. Free cash flow was $240 million in the quarter. This free cash flow for the quarter more than covered the $112.5 million dividends payments and a $50 million repayment on the RBL.
At the end of the quarter, our cash balance was $127 million. Book value of net interest-bearing debt was $2.85 billion, and we now have $3.6 billion of committed undrawn capacity on our $4 billion bank facility. Net debt over EBITDA was lowered again and is now just under one times. With 9 months of the year behind us, we are making some slight adjustments to our full year guidance. We are still expecting production to average between 155,000 and 160,000 barrels per day. However, we see the risk skewed to the downside of this range and into the lower half. Production cost is expected still to be around $12 per barrel. The run rate on CapEx so far this year has been slightly below our estimates.
We anticipate spending to be higher coming into the fourth quarter, due to a mix of strong performance and phasing of projects, we reduce our CapEx guidance to approximately $1.25 billion. When it comes to spending on abandonment, we reduced our estimate from $350 million to $250 million the last time we met in July. The Maersk Invincible rig has completed its current P&A scope by the end of this quarter, with spending so far this year at $226 million. There is not much abandonment scope in the fourth quarter. Therefore, we expect spending here to come within the $250 million mark.
When it comes to exploration activities, we increased our estimate from NOK 350 million to NOK 425 million earlier this year on the back of the success that we had seen in the Frosk area and the fact that we secured a rig that would drill additional wells in the area. Due to late arrival of said rig, we anticipate that one of the wells here will likely slip into next year, therefore decreasing the spending in the current year. Our revised guidance is therefore set at NOK 400 million. In totality, we are then at a total spending of NOK 1.9 billion versus our initial guidance of NOK 2 billion. Before I turn it over to Karl, just a couple of words on the recently announced transaction. Since mid-July, we have announced two asset acquisitions.
They both represent attractive opportunities for Aker BP, and they strengthen our position in strategic areas around our existing production hubs. All licenses acquired have tie-in potentials to our own hubs. In July, we announced an acquisition of 11 operated licenses from Total for a consideration of $205 million. This acquisition adds more than 80 million BOE of resources net to Aker BP. Trell and Trine are two discoveries that we plan to tie back to the Alvheim FPSO, while Rind is a discovery that is part of our NOAKA development scope. The Alvheim Nord discovery represents an opportunity for a tie-back to Skarv FPSO in the Norwegian Sea. Earlier this week, we announced the acquisition of 77.8% of the King Lear discovery in the southern North Sea.
Total consideration was $250 million, and we expect that the total resource potential from this transaction to be in excess of 100 million BOE net to Aker BP. Our plan is to tie this discovery back to Ula, thus providing injection gas to the Ula field, and this will increase oil recovery from Ula. I will turn it back to Karl to walk you through some of the operational highlights.
Thank you, Alexander. I think I'll start doing my usual tour of the assets and licenses. I will this time spend some more time on a few exciting topics First of all, let's move to Alvheim. Alvheim continues to be a significant success story for Aker BP. When it comes to operational performance in the quarter, this was a very solid quarter, despite the very high activity level across the license. We delivered a production efficiency of 96%. There are, of course, lots of things to say about Alvheim, but I think that this time I'll draw your attention to a recently drilled well, the Chameleon infill south well, which we are about to tie back to Alvheim and expect production to commence shortly.
This was the first well drilled by the Floater Alliance, which you may remember consists of Aker BP, Odfjell, and Halliburton, and it is a significant step change in performance and technology over the wells delivered on Alvheim in the past. This is the first well drilled with wired pipe, which meant that we could increase the drilling velocity and drilling speed in the reservoir section, and this well was drilled with up to 90 meters an hour in the reservoir section, which is approximately three times the 30-meter-an-hour limit that we have on usual technologies. This is the first use of gas tracers to get better control over the gas flow in a multilateral well, and it's two of the longest branches ever drilled on Alvheim. More than 10,000 meters of reservoir section was actually drilled in this well, and 7,920 meters of lower completion was installed.
The well was completed 11 days below our initial estimates, and more importantly, as work was carried out with the Deepsea Stavanger, which is a sixth-generation rig, we have saved approximately 30-40 days over the usual third- or fourth-generation rig that we usually have used on Alvheim. In my mind, this actually proves that the strategy we have chosen with an alliance to drill these wells, shorten well planning time, and to choose high-end sixth-generation rigs is really successful. We are working to develop Trell and Trine that we recently bought and Alexander walk you through as a tieback to the Alvheim FPSO. This will most likely be carried out as a fast-track project. However, the development needs to be seen in conjunction with the Gekko appraisal that we just drilled.
This, of course, is a brilliant segue into the next generation of Alvheim successes. Approximately a year ago, we drilled the Frosk exploration well, or the Frosk exploration well, if you want, which was significantly more volumes than we expected and being currently in the range of 30-60. We have also, in the second quarter, talked about a test well in this discovery, and we are now announcing that this has been approved and will be drilled in the upcoming drilling campaign. We will drill a bilateral test producer into Frosk Main and drill two, possibly three, pilots with exploration potential in addition to the test producer. In addition, we will shortly commence on a drilling campaign in the other prospects in the area, the Frosk Leg and Tadpole.
Just to reiterate the numbers, Frosk Leg will have a pre-drilled range of 44-153 million barrels of oil equivalents, and Tadpole 45-147. The chances of discovery are in range of 40%-60%. The Frosk Leg will commence in 2018, whereas the commencement of the Frosk test producer is determined by the arrival of the long-lead items in the lower completion. As I said, one bilateral producer and two, possibly three, pilots into Frosk Leg Northeast and Frosk North all delivered within one year and again demonstrating the power of the subsea alliance ability to turn around and deliver these projects quickly. Moving on to Gekko. Gekko is an old oil discovery near Alvheim. We have recently completed an appraisal well on Gekko, and the results, I must say, is extremely encouraging.
Very good reservoir qualities, a thicker oil column than we predicted, around six and a half to seven meters of true vertical depth, and good reservoir properties. We see the resource potential as being in the range of 40 million barrels, it's very likely that this will be tied back to the Alvheim field. Just to put it into context, this is approximately twice the size of Ula and four times the size of Skrugard that was sanctioned last year. The most likely development solution will be two multilateral wells tied back to a manifold, we see break even of this project below $30 per barrel. At Valhall, the operational performance has been decent in Q3, with a production efficiency of 88%, production increased to 36,000 barrels, up approximately 7% from Q2.
Most of the reduction in production efficiency was related to well work, the plant itself has performed very well in the quarter. However, the production is slightly below our plans, the reason was delayed startup of new wells. This delay was caused by technical problems during testing of a new well stimulation method, where the new equipment got stuck in the well. The problems have now been solved, we are back on track to deliver more production growth at Valhall. I would also like to take the chance to explain to you why we are testing out this new stimulation method. Valhall is, as you all know, a chalk reservoir, which need fracking or fracturing to produce oil. The well cost is distributed approximately 60% towards drilling of the well and approximately 40% towards the fracking of the well.
The traditional method is very time-consuming, each frack stage needs to be done separately using coiled tubing. We have been looking for ways of accelerating this significantly in order to increase the number of wells drillable on Valhall, increase the resources, and increase the economic performance. We have taken inspiration from the U.S. Shale. The single-trip multi-frac method is designed to perform multiple fracking stages in one operation, which means shorter time to production, lower cost per well, allow for more fracking stages per well and hence higher well productivity. Theoretically, we see an opportunity to reduce time consumption of fracking operation with approximately 90% or down to one-tenth of the time, which, when you account for the fact that this is 40% of the total well time, is a significant saving, a step change.
The step one is to get the single-trip multi-frac to work, step two, that allows for optimization and de-bottlenecking of logistics and other parts of the value chain. In total, we're really excited about this technology and will continue to develop it in order to increase production and resources and reserves on the Valhall field. Now, talking about continuous improvement. We have now completed the P&A campaign at Valhall, the results are on the chart that you can see right now. You can see a very visible continuous improvement strategy at Valhall. This program, as previously announced, was concluded earlier this month, the rig is now back to drilling on Valhall Flank North. The average time on the left side of the chart here is 62 days.
The average on the right-hand side of the slide is 29, which basically means a doubling of the efficiency. This takes into account that the gray bar accounts for the most complex P&A wells on Valhall, which we obviously left for last to maximize learning effects. As I said, the rig has moved on to Valhall Flank North, where it's drilling a water injection well as a part of a project to increase oil recovery by approximately 8 million barrels. The water injection is planned to start in Q2 next year after pipelines and risers have been installed. Of course, the Valhall Flank North injection project is organized and executed according to Aker BP's alliance model. Moving on to the last development project on Valhall, the so-called Valhall Flank West. It's progressing as planned with excellent performance, excellent HSE results, and well within budget.
The current engineering and construction activities is focused on supporting the topside construction of the wellhead platform at Valhall, Norway. The project remains on track for installation in the summer of 2019 and production start in the fourth quarter next year. Moving on to Ula. We will give you a first glimpse of the Ula redevelopment plan, and we'll come back with more detail in the capital market day in January. The ambition is to expand the Ula lifetime to beyond 2040, by a combination of IOR measures, tie-ins, exploration, and lifetime extension, significantly increase remaining potential. We see a potential to more than double the existing resources by this new program. As you can see, there are many activities in this program. Some have already commenced.
We have already tied a new flotel into Ula to accelerate maintenance and construction activities to allow for lifetime extension. We have already placed gravel packs near Ula to tie a jackup rig into Ula in 2019. There are also other activities ongoing. We are planning for new wells on Ula between 5 to 6. It's a combination of IOR wells and a redistribution of the WAG scheme. In addition, there is a Triassic horizon at Ula, which currently have only one producer in it. We plan to expand that, and we plan to tie existing discoveries in the area, particularly the Kark and the Ula Nord back to Ula. Finally, we plan to tie King Lear back to Ula, both to utilize capacity, but also to utilize the gas for water alternating gas injection.
Of course, as we've done on every single other asset, we also plan to explore, having completed our assessment of the region. Moving on to King Lear. The key issue with King Lear is the perfect synergies it has with Ula. First of all, Ula consists of an excellent tie-in opportunity with sufficient lifetime, sufficient export capacity, and more than enough infrastructure capacity to carry out the King Lear production. The resource range we are reporting in the range of 60 to 170 gross volumes that is, NPD is reporting it roughly like 100. The gas-to-liquid ratio is 60 to 40, and we have, as Alexander already talked about, acquired 77.8% interest from Equinor, inclusive of the operated stake. The reason that we are so engaged in getting this tied back to Ula consists of the fact that this is a rich gas.
The rich gas will have significantly better properties when it comes to water alternating gas injection schemes than the dry gas that are currently used on Ula for this purpose. In fact, the efficiency is more than double of the rich gas versus the dry gas that we're currently using. As previously announced, we actually see this as a significant uptick in the resource potential connected to the King Lear acquisition. All of this will be explained in detail in the Capital Market Day, but I think the highlights is very clear. Long life duration at Ula, more than two times the existing resources as potential for the new expansion program, and a significant activity level is needed to deliver this expansion program. This is exactly the same recipe as we've used on Valhall previously, and is currently ongoing at Valhall. Moving on to Ivar Aasen.
The production has been relatively stable in the quarter. The platform itself has an excellent uptime of 98%, and production efficiency ended up at 92%. The discrepancies are negatively impacted production efficiency by power generation issues at the Edvard Grieg host. We have also completed drilling of two new water injectors in Ivar Aasen, which have increased mass balance, and we're now at a positive mass balance at Ivar Aasen which have reduced GOR and increased production somewhat. During the quarter, we have also drilled an appraisal well at Hans. The well basically confirmed the pre-drill estimates and Hans will be developed as a tie-back to Ivar Aasen. The investment decision is planned for next year, and we currently anticipate production start in 2021. Moving on to Skarv. Production was down roughly 15% from Q2 to Q3, and this was mainly driven by gas volumes.
The liquids volumes were far more stable. In Q2, we experienced some technical issues with the gas injection system, particularly related to the gas injection motor, and this led to temporarily higher gas exports in Q2 than in Q3. However, in Q3, we have injected more gas than normal to reestablish reservoir pressure, and hence gas exports were slightly down in Q3. The Alvheim development is progressing as planned. The first phase, currently in execution, includes three new wells in the southern part of the field, tied back to the Skarv FPSO using a trace heated pipe-in-pipe flow line. Actually, the first and the longest one of its kind. In addition to the existing A1 test producer in Alvheim. Production from these new wells are planned to begin late 2020, where the second phase of the development is now being matured towards the concept select in first quarter 2019.
Alexander previously talked about Alvheim Nord, which is among the discoveries that we recently bought from Total. Alvheim Nord is located north of Skarv or Alvheim, and we see this as an obvious tie-back candidate to Skarv to be matured following the Alvheim project. Johan Sverdrup is continuing steadily. Phase one facilities are now at 93% complete. The operator, Equinor, announced in August at ONS that the phase one CapEx was reduced by 2 billion NOK and are now standing at 86 billion NOK. The Johan Sverdrup reserve estimate was increased by approximately 0.1 billion BOE, and the most likely estimate now stands at 2.7 billion BOE. We're also finally seeing a one-month acceleration of expected production start. The production start is expected in November 2019.
Moving on to phase two, we expect CapEx for phase two to be estimated at NOK 41 billion and phase two start up in the fourth quarter of 2022. Moving on to NOAKA. As also discussed previously, we have increased our interest in the Rind discovery from 30%-92% through the Total transaction. This is roughly in line with our ownership in the other licenses in the South of the NOAKA area. We continue to prepare for a concept selection by the end of 2018. It is, however, fair to say that alignment of interest between the different licenses in the NOAKA area is less than optimal and this has slowed down the decision process.
We remain convinced that our proposed development solution with a central processing hub is the best solution with regards to resource utilization and value creation in the area and will continue to work with our partners, suppliers and authorities to realize this concept. Now moving on to exploration. It has already been a good year with the Frosk discovery and the Gekko upgrade. We still have some very interesting wells left for the final quarter of the year. Hopefully within the next month, we will start drilling the Frosk follow-up wells on the prospects, Frog Leg and Tadpole. We see this as very interesting targets with relatively high probability of success and significant volume estimates. These wells will all be drilled with rig Scarabeo 8. Scarabeo 8 will move on to drill the JK prospect in the neighborhood of Johan Sverdrup and Ivar Aasen.
This is another very interesting well, although the chance of success is not as high as in the Frosk area. The spud date of JK may move into 2019, depending on rig arrival and the time it takes to complete, particularly the Frog Leg and Tadpole wells. We also have two non-operated wells coming up in Q4, including the large Jøkåsen prospects near the Russian border, operated by Equinor, and the Cassidy project, which is located in the Oda license in the Ula area operated by Spirit. In total, it seems like a very interesting exploration year. Of course, one more thing. We have not forgotten our digitalization efforts. During the end of Q2, beginning of Q3, we have reorganized our digitalization effort into a new digital lab that we have called Eureka.
That consists of five main crews focusing on production optimization, digital work, which basically means our ability to use digital tools in the yards and the front end of the business, smart maintenance, subsurface and drilling data architecture, and improved HSSE performance. The digital lab in Stavanger is currently manned with approximately 60 professionals from Aker BP, Cognite, and vendors and startups and other partners. In addition, there is significant digitalization work going on within drilling and wells, particularly related to autonomous drilling and automatic well planning and in projects related to the field of the future. All these crews work after the new so-called agile method and develop continuously. A lot of interesting projects is already seeing the light of day.
We continue to be extremely optimistic when it comes to the effect that these digitalization programs will have on Aker BP, our vendor space, and the industry as large. With that, I think the Q2 presentation is completed and we'll open for questions first here in Oslo and then on the web. I'll invite Alexander back on stage with me.
Halvor Nygaard from SEB. A question on the OpEx guiding. I know you're not changing your guidance today, is there any reason why we shouldn't see OpEx come below $250 million when it's no or low activity on the decom in Q4?
Yeah. Spending thus far has been $226 million. In the fourth quarter, the rig was a couple of days into, and there are some other planning activities, et cetera, we say it's going to be within $250 million. If it's slightly below or it's hard to see it go above the $250 million. Somewhere in between $226 million and $250 million would be my estimate. Yeah.
All right. A question on capital structure as well. With the current gearing leverage ratio below one, getting the tax loss and the cash from the Hess transaction in Q4, that will take down leverage even further. Maybe you will have a too solid and maybe too robust balance sheet in someone's eyes. Any reflections on the gearing level and an optimal capital structure and optimal leverage?
Yeah, sure. That could be a lengthy discussion. The problem, if you will, of having a too low leverage ratio, I think we'll manage and we'll deal with it. As you said, there's the rather significant NOK 1.5 billion bridge loan to finance that, the tax part of the acquisition, which we hope to have resolved before Christmas. Future and how that capital structure will look will. Well, you've seen what we've done in the past. You've seen how we have developed that balance sheet and how we've managed it and how we've addressed different sources of capital in order to diversify. For now, I think you should just expect us to continue on that path and keep developing that balance sheet. No concrete thoughts on future issuances at this point in time.
If you remember back in the capital market in 2016, we also stated that we will work to get the gearing down and get the company as financially robust as we possibly could. This is exactly what we've done. This is a good problem to have.
All right. One last question maybe on the M&A market. You've done the King Lear deal earlier this week and the Total deal this summer. With the price environment now in a more healthier environment and also new entrants maybe bringing up competition, is it harder for you to do the smarter and good deals? Or have you become a pure consolidator on the shelf, meaning you have access to other transactions or other deals that no one else has?
Well, I think there are many answers to that question, right? One way of actually looking at these transactions at least, is that we're building on the access to infrastructure and the operated strategy that we've had around our hubs for quite a few years now. That, of course, gives access to other ways of developing these fields and other upsides that you wouldn't normally see in an M&A market. Secondly, we've always tried to be value driven when we think about these transactions. That means that we will not go into transactions where we do not see industrial value, regardless of whether that price environment is going up or going down. We've kept that very simple view now through the down cycle, and we'll keep that view also in the upcycle.
There's a lot of activity in the M&A space, but as the last two transactions have proven, we have also demonstrated our ability to find value-accretive transactions even in a high-competitive environment.
All right. Thank you.
Teodor Nilsen, SB1 Markets. First question on King Lear. Could you be more specific of expectations for potential first oil and development costs?
Yes, I could, I choose not to at this point in time as we've just announced the acquisition. As I said, we'll come back with more details in the capital market day when we've put all these plans together.
Okay. Could you, assuming that you will take a decision during next year, could you indicate how long time we should expect from this decision is taken until you will have first oil?
That's basically the same question, but I think a generic answer when you look at the field development process that we've done elsewhere is that from the time we make a decision to a concept selection decision to first oil is somewhere in the range of 36 months.
Okay. Thank you. That's fair. Looking into 2019, as you highlighted, the remaining part of 2019 exploration program is exciting. For 2019, should we expect even more wells than what you have drilled in 2018?
We haven't concluded on the drilling program in 2018, and that's largely because some of this will depend on the discoveries in the last part of 2018. As a planning assumption, we are planning basically a flat activity program when it comes to wells from 2018 to 2019.
Finally, just a minor question on the slight change you had on production guiding. Is that mainly related to the weak Skarv production in Q3 or other factors that goes into that equation?
We expect the Skarv issue to level out over time. We don't expect that to have a significant impact on the overall production in 2018. Most of the discussion around the risk is now related to delays of getting new wells on stream related to the testing of the single-trip multi-frac on Valhall.
Okay. Thank you.
Yes. We have quite a number of questions from our web audience. First one is from Yoann Charenton in Societe Generale. He has three questions. The first one is on CapEx. At this stage, would you be able to say what are the implications of both NOAKA-related developments so far this year, and recently announced deals with Total and Equinor for your 2019 CapEx and ExpEx budgets?
I think it's a bit early to say. We will come back, as Karl alluded to, when we've had a bit of time to incorporate our thinking in bit more detail on the newly acquired assets. I think we are in the somewhat fortunate position to have lots of robust projects that we think are going to meet the $35 break-even thresholds that we have. There's good internal competition for capital. We are in the midst of going through that process, and we'll revert with more details when we get to the Capital Markets Day in January.
Next question from Yoann is on tax payable. Could you please provide some granularity on the $754 million tax payable as of end of Q3? How much of this amount is related to uncertain tax positions? I guess that was already answered in your talk, Alexander.
Reiterate. $754 million that is sitting as booked as a tax payable in the balance sheet, $508 million of this is related to the production and the account so far in 2018. $42 million is a tax payable related to 2017. The difference between what we paid and what is now due, and that is expecting to be paid during the fourth quarter. We have booked $202 million. That's an estimate for uncertain future tax cases. The timing of those may not necessarily be within 12 months, but that is the estimate. Of that estimate, those are legacy cases from BP Norge, from Hess Norge, and there are other typical you have uncertain tax cases. I think around 130 of those are related to Hess, and then some from BP where there's a recourse against the seller in that case.
That's the mix that makes up that tax balance.
Yeah, the third question from Yoann is on changes in other current balance sheet items. Can you please tell us what items impacted 3Q's $81 million positive contribution from changes in current balance sheet items other than inventories, payables, and receivables? Furthermore, would you mind putting this into context with the past?
I wouldn't mind. I'll give it a shot. Working capital changes between each quarter, it's somewhat challenging to estimate and give guidance on, because there's lots of variables going into this, and it's us on behalf of partnerships and how we do the cash calls and how we plan for that and vice versa on the other side of the balance sheet. In this quarter, we also had adjustments for overlift and underlift balances that go into this accrued income. There will be prepayments that varies between each of the quarters. Very hard to pinpoint how that is going to play out in future quarters. Those are typically the items that goes into the working capital column in a company like Aker BP.
Next question is from Alwyn Thomas of Exane BNP Paribas. Is there any risk to you receiving the $1.6 billion tax rebate, or is it purely a matter of timing?
Okay, let's just remind everyone, the $1.6 billion tax loss from Hess, that is historical tax losses. That could either be monetized through normal course of business offsetting taxable income, or in this case, we are asking that you can have that paid out in one go. Either way, that is the tax loss that we will be able to utilize in Aker BP. The timing is not necessarily given, but we still believe that through the normal course of how you do the tax returns in Norway and coming up to November and December, that we do not have any indication that we shouldn't see a payout of that tax loss.
Yes. There is also a tax related question from James Hosie of Barclays. On cash taxes, can you provide any guidance on what the cash tax payment will be for 4Q and for 2019 at current commodity prices?
Yes, lots of interest about tax. That is good. Tax is important. Yes. Back in May, June, we have to estimate what the next six tax installments are going to be. We make an estimate then, saying for 2018, our estimate was that the six installments would be NOK 1.25 billion. On today's FX, that is around $160 million. There are three installments now in the second half of 2018, one in Q3, two in Q4, and then there are another three in the beginning of next year, every other month. Those will be the tax installments if we just follow that estimate. There is an opening that in January, based on your experience and how you have seen this play out in 2018, in January, you can adjust the last three tax installments that you were paying in the beginning of next year. Those are the estimates.
In addition, in 2019, we will go again. Based on 2019, you make three estimates for the latter part of 2019, and then three more into the beginning of 2020, and on and on. That is the guidance on the tax. I also mentioned on the last tax question that there was $42 million that we are expecting to pay now in the fourth quarter for 2017, just like we all do when you get your tax returns, and there is a plus or a minus.
Yes. There are actually a long list of questions. Many of them are related to guidance for 2019. I guess it is a bit early to be precise on that, but do you have any general comments on your outlook for 2019 at this point?
I guess at this point in time, there's so much happening, both in terms of activity level, in terms of acquisitions that have recently been announced, and in terms of our planning for 2019 and onwards, that I think we'll come back when it comes to guiding, as we usually do in the capital market day presentation in January, and prepare more details around activity plans and the impact it has on guiding in terms of CapEx, OpEx, and CapEx for 2019, as we usually do.
Yes. Thank you. I think we'll draw the line there. To those on the web who have not got their questions answered, please contact us in the IR department after the presentation, and we'll do our best to follow up.
Thank you. An excellent day to everybody, both here in Oslo and also those viewing from the web. Thank you.