I'll start anew. Sorry about that. Welcome to the fourth quarter presentation here at the Fornebuporten. Welcome to those of you who have selected to join us here. As I can see, most people are joining us on the web, so a special welcome to you, too. 2018 was a really good year for Aker BP. I think on every single parameter that we could think of, we had strong growth throughout 2018. I'll spend a little bit of this time to try to dig into some of these details and put the case why this growth is continuing also in 2019 and the years beyond. First of all, we had record high production in 2018. What makes me even prouder is that we had really high regularity despite a lot of modification activities ongoing on pretty much all our installations.
Second, we've seen industry-leading drilling performance that I'll come back to. We've seen all the field developments basically on track. Digitalization is gaining momentum. I'll share a couple of new examples with you here today. We see an expanding of the alliance model, and we see this alliance model gaining traction and producing real, tangible improvements on our cost base. We're continuing to apply new technology to our business. We'll share a couple of those examples today, too. Finally, the organic growth story is very strong. Even in 2018, when we did not deliver a new PDO, we had reserve replacement above 100%. We increased our continued resource base with 23%, both from M&A but also from organic growth opportunities. 2018 was a good exploration year. As you probably already noted, 2019 has not started too bad either.
Fourth quarter 2018 basically compounds the growth story of the entire year of 2018. Production stood at 155,700 BOE . We had a realized oil price of $ 64.3 and a gas price of about $ 0.30 / standard cubic meter. That left us with an EBITDA of $ 667 million, adjusted for an underlift that is impacted by the oil price change in the fourth quarter. We completed the acquisitions of King Lear and the portfolio we acquired from Total, and we finally got the Hess tax loss refunded and thereby reduced our net debt in the quarter. I cannot talk about 2018 without also mentioning a recent event after the quarter. We have just announced the discovery at Froskelår.
To me, this is a step on the road of a pretty long strategy of future field developments at the Alvheim area that started back in 2014. This is the result of a tangible strategy with data acquisition and continued field developments throughout the area where seismic activity, field development activity, and the subsea alliance has compounded to a great story. The preliminary results as they were reported is that we have discovered an oil and gas discovery. We are initially within the pre-drill range, and there's a chance that this discovery straddles the U.K. border. Currently, we are doing coring and data acquisition activities, and we are going to drill one or two horizontal sidetracks to reduce the uncertainty range prior to commencing field development studies. Next well in this area will be the Frosk test producer.
As you may recall from the Capital Market Day, we are also going to drill the Froskelår Northeast as an extension from the Frosk test well. After that, we'll drill the Tadpole or Rumpetroll exploration well, and following that, we'll make an assessment of the entire area. Moving back to production in the quarter. As you can see, we recovered production from third quarter 2014. As you can also see, the regularity is pretty high across our asset base. There are, of course, two assets that stand out. The first one is Ula. This is mainly due to well activity, but also to the fact that we are carrying out a lot of modification activities to prolong the lifetime at Ula, which impacts production across the Ula license.
On Valhall, the main culprit is stimulation activity, which means fracking, which means that we have to shut down neighboring wells to avoid the frack breaking through to the wells. This has been pretty high in 2018 due to the high number of wells drilled in the field over that year. Talking about drilling, we continue to lead the market in terms of drilling performance. This year, in 2018, we have delivered just above 200 m a day on average across our production drilling performance, and are hence leading the field on the Norwegian Continental Shelves in terms of drilling performance. This is the reason I'm talking about productivity every single time I'm talking about improvement, is that the underlying productivity needs to continue to trend upwards.
The difference is even more clear when you look at the exploration wells drilled in 2018, where we're quite a significant gap to number two on the Norwegian continental shelf. We've, for a long time now, talked about the subsea alliance and the effects of the subsea alliance. I thought I'd share with you today the effects that we're starting to see on the Valhall West Flank. First of all, the project is on track. It will be loaded out and installed in the summer of 2018. We've now run our first benchmark of the alliance effects across the portfolio, but also compared the Valhall West Flank project to the benchmark in terms of project on the Norwegian continental shelf. Of course, I'm happy to see facility cost reduced by 24% from the benchmark.
Even more importantly is probably that we've been able to increase productivity by reducing the number of engineering hours with 14% and reducing the duration of the project with almost 30%. This means high value creation for Aker BP and our partners. We continue to drive down cost throughout our portfolio. Another example of waste reduction is the activity we carry out to lower CO2 emissions in our operations. We recently announced the 2017 numbers, which stands at 7.2 kg / BOE, and the 2018 showed a further reduction from those 7.2 kg down to 7.0 kg / BOE in CO2 emissions.
The two main driver for this was increased energy efficiency and energy efficiency activities, but also that we, for the first time ever, electrified a jackup operating at Valhall using the power from shore cable from Valhall out to the Valhall PH and then further out to the Maersk Invincible. That's another little bit of a technology demonstration, but also something that actually creates real value. On the Valhall West Flank, the first ever electric propulsion lifeboat will be installed. The driver is actually very simple. On a normally not manned installation, you want to avoid as much preventive maintenance and condition-based maintenance as you possibly can. By using an electric engine and batteries, we could remotely control both the battery, the state of the engine, and we can remotely run tests and analytics across it without putting people on the installation.
It's of course fun to deliver a world's first even on this field. Digitalization is also gaining momentum, and we've talked a lot about the digital worker and how we connect the different data sources in our universe through the Cognite data platform and up the tablets and users in the field. Today, I thought I'd share with you another perspective on digitalization, where we use machine learning to increase production in our assets. I talked about the main culprit on the production efficiency in Valhall is the breakthrough of chalk into the wells. We've long searched for a solution on how to discover this chalk influx without it actually happening.
Now we've actually seen and demonstrated that by the use of artificial intelligence across that data set of data that are already gathered by sensors in the field, we're able to predict when this chalk influx is happening and mitigate without serious production impairment. This is another effect of actually using the data from many different systems, putting them into the Cognite data platform, and then putting, in this case, artificial intelligence or machine learning on top of that to create tangible information that are actionable in the field. A second example is very complex changes in flow requirements and processing requirements across the different installations. In this case, illustrated by an Alvheim case. When we test the multiphase flow meters, we have to change the parameters in the process.
In doing so, we introduce multiple variables to the process control, it's hard to understand what will be the optimum at any given point in time as you run through the sequence of wells to be tested. We've gathered all this data, we've compressed it into a simulated set. We put machine learning on top, now we're able to predict exactly the flow through and the maximum production for each and every multiphase flow meter test. If this is only implemented at Alvheim, it will save us around NOK 40 million a year on this project alone. As you can see, the digitalization agenda in Aker BP is gaining momentum, and we're focusing on tangible business cases that we can run out across the field to gain both experience, but most importantly, increase productivity and lower cost. Then finally, a word on alliances.
We've currently implemented seven alliances spanning from drilling and well all the way up to maintenance on our installations. From a pretty slow start back in 2016, when we had two projects ongoing in execution, we now have 10 projects ongoing in the subsea alliance alone. We have more than NOK 10 billion in the subsea and modification alliance within the scope, and we plan to execute about 1.2 million hours of work in the modification alliance. I'll put it to you that without the use of these alliances, we would not have seen the productivity and the increase in efficiency with the increase in scope that we've seen so far. To me, this is proof that this alliance model and the reorganization of the value chain is actually working. We have two more alliances to go.
The first one is the intervention alliance, which is currently being processed. We're discussing what to do with logistics and how to shape that value chain as well. Already now, we've pretty much completed a project of reorganizing the value chain into alliances in Aker BP's operation, and we continue to take out benefit of this work that has been going on since 2016. This is all well and good, but ultimately, oil and gas is about finding, realizing, and producing oil. This is probably what makes me the most proud in 2018, is that we've been able to replace every single barrel we produced in 2018. We went into the year with 914 million barrels in reserves, and we exited the year with 917 million barrels, having produced 56 million barrels and put back 59 million barrels.
We have also increased our resource base by a significant amount, and it's currently standing at 946 million barrels. Out of these, 174 million barrels are acquisitions. There is 44 millions that are matured to reserves, which you can find on the left-hand side of the slide. Of course, there are some discoveries and upward revisions basically coming from the Gekko appraisal well drilled last year. Which is a perfect segue over to the exploration year in 2018. 2018 was a quite good year in terms of exploration. We have generated value in the range of $120 million - $280 million on that exploration budget, dependent a bit on the parameter set, as you can see. The two key parameters is the Frosk discovery.
This is, of course, the start of the story that is now continuing with Frog Leg and then continuing with Frog Leg Northeast and then Tadpole ultimately. It's also an effect of a larger-than-expected appraisal well on Gekko. Ultimately, we have increased our number of licenses on the Norwegian Continental Shelf and are now the second-biggest license holder with 159 licenses, 21 out of which was acquired in the last licensing round. As you can see, they are pretty much spread around the Norwegian Continental Shelf. Recently, we've been focusing on near-field exploration close to our operated hubs. This is a strategy that will continue also in 2019. 2019, in terms of exploration, have started, I would say, quite well. There are lots of good wells to come.
The first one is going to be the Frog Leg Northeast, which we expect to see as an extension of one of the branches of the Frog test producer. Then the Tadpole next. Hod Deep well, the quest is ongoing. We are just above the reservoir right now, so I expect that to penetrate the reservoir within a week or so. Gjøkåsen is also ongoing. 2019 is going to be a really exciting exploration year for Aker BP. Oil and gas is mostly about numbers and oil volumes and improvement project, but it is also about great people.
It gives me great pleasure to welcome two new members to the Aker BP management team. Lene Landøy, who is now responsible for Strategy and Business Development, and David Tønne, which you will meet shortly, who is now the Chief Financial Officer in Aker BP. I think it is time for your debut, Alexander. Not Alexander, David. I have said this so many times now. It is going to take me a long time to actually get that right. But David, the floor is yours.
Thank you, Karl. Good morning, everyone. I have the pleasure of summarizing the financials for 2018 for Aker BP. With this, I will also take you through some of the key figures for the quarter. 2018 was, as Karl said, a record year for Aker BP. We increased revenues with 46%, and the key driver for this was an increase in production of around 12%, up to 155,700 b p d. At the same time, realized hydrocarbon prices increased in the period by 29% to approximately $65 / barrel. EBITDA for 2018 ended at $2.75 billion. This is up 54% from 2017. Net profit increased with 73% to $476 million. Deep diving into the last quarter of the year. The operational performance in the quarter was very good, with production ending the year at 163,400 b p d on average throughout December.
There were two specific non-cash accounting effects impacting the P&L this quarter. One was the reevaluation of the underlift balance due to falling oil prices, and the second was the strengthening of the U.S. dollar versus NOK, impacting the effective tax rate. I will come back to those two points a bit more in detail later on. Into the numbers. We recorded a revenue of $886 million on a production of 155,700 b p d, same as the average throughout the year. The decrease in revenues compared to Q3 is driven by mainly lower prices as we realized an average oil price of $64.3 / barrel in the quarter. Income during the quarter were also negatively impacted by a large net underlift balance reevaluation. In layman terms, these are the volumes that we have produced but not yet sold.
We value this inventory at the estimated sales price on the balance sheet date and book the related adjustment against revenue. At the end of Q3, we had a net underlift balance of 1.6 million barrels, which increased to about 2 million barrels at the end of Q4. This balance was valued at around $80 / barrel at the end of Q3 compared to around $50 / barrel at the end of Q4. The negative impact on income due to this revaluation of the underlift was therefore around $48 million, but this was a non-cash effect.
Moving to costs. Production expenses was around $ 187 million, an increase of $ 21 million from the previous quarter. If we look across our five hubs, absolute OpEx was relatively stable for Alvheim, Ivar Aasen, Skarv, and Ula-Tambar. The increase in production costs is mainly a result of increased planned maintenance at Valhall Hod.
On average, production cost per BOE was $13 during the quarter. For 2018, we ended at $12.1 / barrel, which is in line with our previous guidance. Other OpEx amounted to $8 million for the quarter, roughly $0.60 / barrel. Talking about exploration. Exploration cost this quarter was $ 72 million. The main components of exploration costs was field evaluation of $ 28 million, mainly related to NOAKA, and seismic cost of $ 21 million. In addition, we also expensed $4 million of dry well cost related to the Cassidy well. In addition, we also have the usual area fees and other exploration expenses that makes up the balance. EBITDA was $ 619 million for the quarter. Depreciation, $ 196 million or $13.7 / BOE, roughly in line with last quarter and $0.50 above the average of 2018.
We recorded impairment charges of $ 20 million, mainly related to [Gimle-Trogue] due to revised production and CapEx profiles. We had net financial expenses of $44 million during the quarter. The overall currency result is close to zero, as the currency gain from the strengthening of U.S. dollars versus NOK during the quarter has been offset by the currency loss on the NOK-denominated tax refund related to Hess Norge, which was settled in November. The currency impact from this tax refund has previously been presented as other comprehensive income, but has now been reclassified to P&L in Q4 as Hess Norge was liquidated during the quarter. Note that we recorded realized gains on derivatives of $ 72 million, mainly related to the currency hedging of the same tax refund. Other financial items such as interest income, net interest expense, and accretion were stable compared to the last quarter.
A more detailed breakdown of the various financial items is shown on note six. Profit before tax was $ 359 million and taxes amounted to $ 305 million. This represents an effective tax rate of 85% in the quarter. As we clearly illustrated in the Capital Markets Day a couple of weeks back, our P&L tax is impacted by the changes in the U.S. dollar to NOK exchange rate. A key reason is that we have the dollar as a functional currency while our undepreciated tax balances are denominated in NOK. This means that a strengthening of the U.S. dollar versus NOK increases the effective tax rate. Yes. The petroleum tax rate in Norway remains at 78%. Normally, our effective tax rate will be a bit lower due to the CapEx uplift, but from quarter- to- quarter, this may vary due to accounting effects due to currency movements.
Of the $ 305 million in taxes, $ 133 million was the current tax arising in the quarter, $ 151 million was changed in deferred tax, and $ 20 million was related to adjustments for prior periods. When analyzing the effect of the currency changes on the effective tax rate, we observed that approximately $ 50 million is driven directly by the change in currency, and these are also mainly non-cash effects as the same as the reevaluation of the uplift mentioned previously. Net profit then ended at $ 54 million for the quarter, or $ 0.50 / share. For 2018 in total, earnings per share ended at $ 1.32. Let's look at the balance sheet. On the asset side, there were three main movements in Q4.
Other intangible assets increased to $ 2.4 billion, that reflects the acquisitions of licenses from Total and the King Lear acquisition from Equinor, which was completed during the quarter. PP&E decreased in Q4, normally one would expect an increase as our investments exceed both depreciation and impairments. In Q4, the net CapEx amounted to $ 380 million, excluding capitalized interests, while depreciation and impairment amounted to $ 197 million. However, PP&E also includes the estimated future abandonment cost, which was reduced by $ 492 million in the quarter. Hence, the net effect on PP&E was a reduction of around $ 300 million to $ 5.7 billion. The tax receivable have been reduced to practically zero, that's as previously mentioned, due to the tax loss from Hess Norge being paid out in November. This contributed to a reduction in total assets to $10.8 billion at year-end.
When turning to the other side of the balance sheet, we note the following. Equity was reduced by $ 93 million. The $54 million in net income was partly offset by a negative effect of $ 34 million in other comprehensive income, we paid out $ 112.5 million in dividends in the quarter. Other provision for liabilities decreased by $ 442 million, mainly due to reduced estimates for future abandonment costs, which is mirroring the mentioned reduction in the PP&E on the asset side.
The book value of our interest-bearing debt consists of bonds and bank debt. This was reduced from $ 3 billion to $ 2 billion during Q4. The $1.5 billion bridge facility obtained in relations to the acquisition of Hess Norge, which we paid in November, when the tax losses were refunded. We increased our drawing on the RBL of $ 550 million during the quarter, mainly to finance the acquisitions from Total and Equinor.
Looking at tax payable, our accrual was $ 552 million at the end of Q4. This consists of $ 317 million in remaining taxes payable for 2018, which will be paid during the first half of 2019. The remaining $ 232 million represents accruals for various uncertain tax cases. While we're looking at the balance sheet, it's worth noting that the accounting standard IFRS 16 leases is effective from the 1st of January 2019, is therefore not reflected in the accounts for 2018. The main impact of the standard is that lease contracts should be recognized in the balance sheet as a lease asset and a lease obligation. The overall key message related to this for Aker BP is that the implementation of this standard will have limited impact in 2019, as it will only increase our total assets with around 4% or $ 400 million.
We also expect minor impact on the income statement, as most material leases are typically rigs and are mainly used for CapEx activity. Moving to cash flow. I think the cash flow for Q4 summarizes most of the items discussed so far, but I'll briefly walk you through them. The tax refund was used to repay the bridge loan. The acquisitions were fully financed by drawing on the RBL, and cash flow from operations was $ 717 million before the tax payments of $ 304 million.
Cash flow through investments, excluding the acquisitions, was $ 447 million, of which the main contributors were Valhall Hod with $ 208 million, Johan Sverdrup with $ 91 million, and Alvheim with $ 42 million. Dividends again amounted to $ 112.5 million, resulting in a total dividend for 2018 of $ 450 million. Then, at the end of the quarter, our cash balance was $ 45 million.
The book value of net interest-bearing debt was $ 2 billion. We had $ 3 billion of committed undrawn capacity on our $4 billion bank facility, and our leverage ratio, defined as net debt over the EBITDAX, was lowered again and now is around 100 and 0.65. I also would like to give some comments related to tax and tax payments. Under the Norwegian fiscal regime, taxes are paid in six installments. For each fiscal year, the installment starts in August the same year and ends in June the following year.
Hence, the three first installments are based on an estimate of the taxable income for the full year. After year-end, the last three installments can be adjusted to reflect the actual taxable income. Looking at the chart, Q1 and Q3 each have one installment, while Q2 and Q4 each have two installments. For 2018, we initially overestimated the taxes.
Hence, we have reduced the remaining installments accordingly. The two bars in magenta on the slide add up to the equivalent of $317 million that is included in the tax payable in the balance sheet. Then, also as an extra service to you who want to understand the cash flow implications further out in time, we have provided an outlook for the cash tax payments for 2019 under various oil price scenarios. We recognize that tax is very important, but also a bit complex. We typically receive quite a lot of questions related to tax. We are therefore planning to publish a tax information pack during the next couple of days on our investor pages on the web. Finally, for sake of good order and in good tradition, I will also revisit our guidance summary.
Key message here is that the only thing that has changed since the Capital Markets Day is that we now have the accurate 2018 figures. 2018 production ended within our guidance range, and for 2019, we expect to stay within the same bracket. The next step-change in production for Aker BP will be when Johan Sverdrup starts up, which is expected in November. Total cash spend on CapEx in 2018 ended at $ 1.2 billion, slightly below the last guidance. For 2019, we're planning to spend $ 1.6 billion, of which the main drivers are Valhall and Johan Sverdrup. Exploration spend came in at $ 359 million for the year, and this was quite in line with our original estimate at the Capital Markets Day last year. We increased the estimate during the year as we contracted the rig to drill more wells in the Frosk area.
However, this rig was delayed, which took us back to square one. For 2019, we plan to spend around $ 500 million. This is driven, of course, by the very exciting exploration program that Karl just presented. As you know, there are several wells already ongoing. Abandonment spend for 2018 ended at $ 243 million, in line with our latest guidance, but significantly lower than what we said at the Capital Markets Day last year. The main reason for this, of course, was that the Valhall P&A program were executed much more efficiently than originally planned.
Production cost per barrel $ 12.1, again, in line with our guidance of around $ 12. For 2019, we expect a slight increase to $ 12.5, which is mainly reflecting planned high-maintenance activity on Valhall and Ula. Of course, last but not least, we are very pleased to offer attractive dividends. For 2019, we plan to pay $ 750 million, equivalent to around $2.1 / share. Okay, thank you. That concludes my part of the presentation. I will hand back to Karl.
Thank you, David. Got that right. That is good. Finally, the priorities ahead. The strategy for Aker BP will remain the same also in next quarter and the quarters to come. We will keep focusing on the three main strategic pillars: to execute, to improve, and to grow. We will keep focus on safe and efficient operations throughout our five operated hubs, and we will keep driving excellent project execution, as I have shown you an example of here today. You can trust that Aker BP will continue to lead the digital transformation of the E&P industry, as we are completely convinced that this will be the main value driver in the years to come. We have talked about alliances.
We continue now to expand this across the next two value chains that are in process, but probably even more importantly, to deepen and improve the improvement programs going on within the alliances themselves. There is an extreme amount of activity and enthusiasm inside this alliance, which really makes me certain that this is the way to go. Finally, as new technology come to the market, as we have discussed in the Capital Market Day, we will be aggressive in applying that technology to reduce cost, increase quality, and increase productivity. In terms of exploration, we have demonstrated a high capacity to realize value, we continue to do so in 2019, while we are also maturing new in-field resources to reserves throughout the year.
Finally, in the Capital Markets Day, we were fortunate enough or happy to put out a new dividend guidance. I'll reiterate that because, to me, that's the most important thing we as a management team can do, and that's to increase value to our shareholders. As David said, this year we plan for $ 850 million, increasing $100 million each year up to 2023. With that, I think we'll conclude the quarterly presentation and then open for questions. I think we'll do it as normally. David, if you join me here, and we'll open here at Fornebuporten and then go to the web. There are no questions here at Fornebuporten. Are there any questions on the web, Kjetil?
Actually, there seems to be no questions on the web at the moment. There has been a technical hiccup during the presentation, parts of the presentation did not broadcast as expected. That's probably the reason.
Okay.
I guess we should invite those who have questions to pose them directly to us after the presentation.
Sure. That's great. If any of you have questions, you could either post it or you can send it directly to Investor Relations at Aker BP.
Actually, I got a question now.
Oh, fantastic.
From Alwyn Thomas of Exane BNP Paribas. He asks, "Is there a way that higher resources in the Alvheim Frosk area could help the commercialization of the north of Alvheim fields, particularly in the event Krafla Askja is developed using Equinor's concepts?"
First of all, the Frosk area is in the south, about 20-odd kilometers away from the Alvheim area, while the NOAKA area is, of course, in the north of Alvheim, some 30-odd kilometers north. You could, of course, imagine that there was some kind of shift in terms of resources that allowed Alvheim FPSO to expand its grid south, and thereby releasing reserves to the north. Currently, I must say that our main hypothesis is that these resources will be developed up to Alvheim, and that means that the NOAKA area will remain untouched from the exploration activity in the south.
The second question from Alwyn is, "How much does the Froskelår discovery de-risk the Rumpetroll and other prospects in that area?"
Yeah. I won't go into too much detail as the acquisition is ongoing, but there are indications that the Frosk system and the Froskelår system is not identical in terms of oil quality, but also in terms of oil-water contact. That means that there are at least two hydrocarbon systems in the area. With that kind of assessment in the background, I'll be quite cautious to go into talking about de-risking of Rumpetroll until we've actually made the final technical data acquisition and drilled the sidetracks to gather more data to get a better understanding of the system. At least it makes us more enthusiastic of the whole area, that's for sure.
Final question from Alwyn is, "How quickly could you produce Froskelår volumes, and what would be required to develop this area if Rumpetroll comes in as well?"
Well, if the Frosk test producer is the benchmark, it will take us roughly one year from discovery to putting the first producer in the ground. Remember, Alvheim is a very standardized area when it comes to subsea production systems, so we're basically using the same toolkit for every single well. We've got a lot of this toolkit already in stock, so we're not hampered by long lead items or other discussions. I think the key discussion as it comes to timing is basically the total volume and development solution in the area. This basically boils down to three different concepts. One, it's a relatively simple tieback using a manifold of bayonet-type of installation of all the top originally, tying it directly back to Alvheim and using the current infrastructure.
Second is to do some sort of partial processing if the volume is a bit higher, but also if there are more gas, as gas is a main constraint on Alvheim currently. Finally, of course, if there are significant volumes, then we end up in the upside case. There is a discussion around a standalone or redeployment of an existing FPSO, some sort of extra new processing capacity in the area. Those are the three main considerations, and we'll revisit that discussion when we have drilled Rumpetroll.
Good. We have a question also from Yoann Charenton in Société Générale on taxation. We are looking forward to the publication of the tax-focused leaflet, which I've promised him, so I'm sorry for that. How much of upcoming tax payments are hedged in U.S. dollar terms, is the first question.
Yeah. No, I don't expect to be able to answer that specifically, but I think mostly they are. More or less everything.
His second question on tax is, it appears that accrual for uncertain tax positions rose slightly in the quarter. Can you please provide further color on such items?
Could you repeat that question again?
Accruals for uncertain tax items-
Yes.
-increased slightly in the quarter.
Yes.
He asks for some color on that.
Accruals for uncertain tax items. Yes. Of course, we have several uncertain tax cases and discussions ongoing with the tax authorities, there are some pluses and minuses on those tax cases. Without going into too much detail on that, I think that's the clear answer.
One question on liquids pricing. Would you be able to disclose the premium or discount to Brent price that you assume across your production hubs throughout 2018?
Far, we have not disclosed these premiums. This is basically a commercial position that we take in the market, that they vary from cargo to cargo, depending on the market situation when we push this cargo into the market. It's both complicated to predict, but it also is an indication of our marketing position. Of course, this is a competitive market. At this point in time, we're not going to disclose that kind of information.
Okay, I guess that concludes the questions that we got from our web audience.
Great. Thank you, and have a great day, everybody, and safe travels for those of you who are traveling. Thank you so much.