Okay. Transpiling now? Great. We'll start again. Okay. Thank you, Jonas, and good morning to you all, and welcome to this fourth quarter presentation for Aker BP here at Fornebuporten. The fourth quarter was in many ways yet another successful and eventful quarter for Aker BP. We delivered steady production in line with our plans and ended up with a full-year production volume of 139,000 barrels of oil equivalents per day, in line with our latest guidance. We've had good progress on our many drilling and maintenance and modification activities. However, we have also had a fatal accident on the Maersk Interceptor rig, something that we are following up extremely closely and expect the report to come out shortly. The strong operational performance translated into yet another quarter with strong financial results and solid cash flow. Alexander will revert to the numbers shortly.
I would like to add that this performance and our growth profile, we are planning to grow the dividend ahead, starting already in the current quarter. In 2017, we paid a dividend of $250 million. In 2018, we increased this to $450 million. The intention is to increase this by another $100 million per year until 2021. Fourth quarter was also a busy period when it came to business development. We developed three field development plans, and submitted those to the authorities for approval. We concluded the transactions with Hess and Pandion, which resulted in an increase in ownership on Valhall field from 36% to 90% at an extremely attractive net cost per barrel. When we hosted our annual Capital Markets Day just two and a half weeks ago, we gave a pretty detailed presentation of our status and plans on all assets.
This time, we will therefore keep it rather short. Let me start with a few comments to our production numbers. As previously announced, we achieved a production level of 136,000 barrels per day in Q4. This was marginally up from Q3 and in line with our guidance for the full year. The increased ownership share in Valhall provided some 20,000 barrels on top of these numbers. I would like to highlight three things in the Q4 production numbers. The first one is that Ivar Aasen reached plateau. This was achieved one year earlier than the original plan, which was enabled by high drilling efficiency, high plant uptime, and availability of processing capacity at the Edvard Grieg platform. Second, the Valhall production increased from Q3. This was partly because of maintenance in Q3, but also driven by new wells that are being drilled from the Valhall IP platform.
Thirdly, the Skarv production was weaker in Q4. At the start of the quarter, three wells were shut in due to Christmas tree issues. During the quarter, one of these wells was successfully repaired and restarted. I'm pleased to see that Skarv production is now more or less back on track. We are planning to repair at least one of the other Christmas trees this spring. We also carried out a pressure buildup test in one of the Alvheim test producers, which contributed to lower production in Q4. This producer has now been put back on production. Before I leave the floor to Alexander, I would also like to say a few words about the three PDOs we submitted just before Christmas. The three PDOs are, as discussed in the Capital Markets Day, Alvheim, Valhall Flank West, and Skogul.
These three fields are all going to be developed as satellites to our existing operated production hubs. The overall scale of these developments is significant, with gross reserves in the range of 350 million barrels of oil equivalents and with CapEx more than NOK 15 billion, or around $2 billion. There are, however, two key messages I would like you to remember from this slide. One, these are highly attractive projects, illustrated by the very low oil price breakevens. Aker BP's net share in these projects amount to around 125 million barrels of reserves with an average breakeven oil price of around $25 a barrel. Two, our consistent focus on improvement is generating tangible results. Compared to the estimates we had at Concept Select, we've been able to increase the volumes and reduce the CapEx. This has been achieved in close cooperation with our main suppliers through the alliance model.
The alliance model have helped us improve efficiency, optimize technical solutions, and compress time schedules. I would also like to emphasize that these improvements are purely driven by productivity gains. No change has been made to the scope. I will now hand the word over to Alexander, who will run you through the financial statements.
Thank you, Karl Johnny. Morning, everyone. I will, as usual, take you through the income statement, the balance sheets and the cash flow for the quarter. The acquisition of Hess Norge and the subsequent farm down to Pandion Energy were completed just before Christmas. For accounting purposes, you will therefore not see any material effects into the income statement, but you will see the purchase price allocation in the balance sheets at the end of this year. For more and a lot of details on these business combinations, you should turn to note three in the Q4 financial statements. We recorded a total operating income of $726 million this quarter. We had petroleum revenues of $737 million, based off the production on 135,600 barrels of oil equivalents per day.
Out of this $737 million, $625 million came from the sale of liquids, and that came at a realized oil price of $65 per barrel. We had $107 million in revenues from gas, and that came at a realized gas price of $0.26 per standard cubic meter. We had production costs of $147 million. This was compared to $134 million in the previous quarter. If we look across our five hubs, OpEx levels remain stable with the exception of Skarv, where we incurred additional costs due to the workover activities that Karl Johnny just mentioned. Due to this, the OpEx per barrel went from $12 up to $18 for the quarter. Other operating expenses, corporate overhead, G&A amounted to $14 million in the quarter, which brings the total for the year more in line with the expected level. We expensed exploration costs this quarter of $56 million.
The main items here were dry hole costs, predominantly on Hufsa and Hurri, for a total of $19 million, seismic costs of around $10 million, and other exploration expenses, including field evaluation costs and area fees of $27 million. We then had EBITDA of $509 million for the quarter, up around 30% from the previous quarter. After deducting the depreciation of $183 million in the quarter, or $14.70 per barrel, and the $21 million impairment charge related to Gina Krog, we get an EBIT of $305 million. Net financial items were a negative $57 million in the quarter, and this was much impacted by the weakening of the NOK against the US dollar during the quarter. Net interest expense were $15 million, down from $27 million in the previous quarter. This was mainly driven by lower debt outstanding and decreased amortization effects since we canceled the RCF during the third quarter.
We had financial income of $18 million. This came as an effect of realized gains on derivatives and some net currency gains. Financial expenses were $63 million. This includes a change in fair value of derivatives of $28 million and accretion expenses of $32 million. Profit before tax was $248 million. The tax expense for the period was $214 million, and this gives a fairly high tax rate of about 86%. This mainly comes as a result of the NOK weakening against the dollar from around 8.0 to 8.2 during the quarter. Included in this amount is a tax payable of around $125 million and changes in deferred taxes of approximately $90 million. Thus, the net profit for the quarter was $34 million or $0.10 per share. Our balance sheet is up around $2.9 billion in the quarter, ending at $12 billion at the end of the year.
This significant increase comes as a result of the change in our Valhall and Hod ownership. Goodwill increased by $43 million. Other intangible assets increased by $378 million and PP&E increased by $1 billion. We adjusted PP&E for the investments in our assets during the quarter. The change in abandonment liabilities and depreciation, which resulted in a net change of around $800 million. You can have a look at note six in the quarterly financial statements for lots of more detailed information about the fixed assets and the changes there. In addition, we then had a short-term tax receivable of $1.5 billion recognized. If you look at the other side of the balance sheet, the accounting for the Hess and Pandion transactions, they resulted in an increase to abandonment liabilities with about $850 million long-term and $150 million short-term.
This also caused deferred taxes to be increased by $67 million and interest-bearing debt increased with the new $1.5 billion bank bridge loan. Other changes in this balance sheet, apart from this change in the Valhall Hod share, we had receivables and other assets at $775 million at the end of the quarter. This was an increase of around $100 million. This increase was mainly related to higher crude sales and underlift, and this was partially offset by a reduction in working capital. Cash and cash equivalents were $233 million at the end of the quarter, and book equity was $3 billion at the end of the quarter. This was obviously up from the third quarter, as we have accounted for the equity issuance reduced with the dividends. Finally, we had tax payables of $351 million.
Of this, $140 million is expected to be paid during the first half of 2018. Cash flow from operations was $543 million in the quarter. Cash flows from investing activities were a total of $2.2 billion. This includes payments for the Hess Norge acquisition and proceeds from the sale of 10% stake to Pandion Energy for a net amount of $1.9 billion. In addition, we had investments in fixed assets of $248 million, where Johan Sverdrup accounted for $79 million. The Alvheim area, including Skogul, accounted for $39 million. Valhall Hod of $25 million and Ula-Tambar finally at $48 million. We also recorded decommissioning payments of $31 million, mainly related to the Maersk Invincible running P&A activities on Valhall. We had free cash flow of $235 million in the quarter. Cash flow from financing activities.
This includes net proceeds of the equity issue of $489 million and net proceeds from the issuance of bank debt of $1.5 billion, both related to the Hess transaction. In addition, we repaid $130 million on our RBL for cash management purposes. We paid out $62.5 million in dividends. At the end of 2017, we had a cash balance of $233 million. We had a book value of net interest-bearing debt of $3.2 billion. The main reason for this increase, of course, being the new $1.5 billion bank bridge loan we issued. Bear in mind that this loan will be repaid upon disbursement of the tax loss sitting in Hess Norge, which is expected in the second half of 2018. At the end of the quarter, we had net debt over EBITDAX move from 1.0 to 1.4. We had available liquidity of $2.9 billion.
Let's just quickly revisit our 2017 guidance and compare this to actuals. Again, note that we are not including any of the effects of the Hess transaction here. Total CapEx spend in 2017 was $888 million. This was slightly below our guidance of $900 million-$950 million. The main explanation for this is a lower spend on Johan Sverdrup. Cash spend on exploration was $262 million, also slightly below our guidance of $280 million-$300 million. Again, explained by fewer drilling days than planned. Total production for 2017 ended at 138,800 barrels of oil equivalents per day. This was towards the high end of our guidance. Production costs averaged $10.3 per barrel, in line with our guidance of around $10 per barrel for the full year. As for decommissioning costs, our cash spend was $86 million in 2017, in line with guidance.
We presented our 2018 guidance for production and CapEx and exploration spend and decommissioning costs at our Capital Markets Day on January 15th. Today, we are not making any changes to this guidance. This concludes my financial section. I think Carlo will provide some outlook on our activities, the operational side. Carlo?
Thank you, Alexander. At our Capital Markets Day some two weeks ago, we gave a rather thorough presentation of the status and plans on all our assets. I will not go through this in detail as it's obviously not been changed in the last two weeks. I'd like to assure you that we are doing our utmost to create value across our portfolio. As you can see on this slide, we have a lot of activity on our plate also in 2018. This includes, of course, the new PDO projects, but also continued drilling of development work, drilling and development work in several of our fields. We will have four to five drilling operations running in parallel throughout 2018. We will also continue maintaining and upgrading our assets in order to maximize lifetime and minimize the risk of unplanned downtime.
We are also stepping up exploration activity this year. A couple of the wells are mentioned on this slide, Frosk or Frog in the Alvheim area, and Kvitungen Tumler in the Skarv area. These are good examples of near-field exploration, which, if successful, would generate significant value and positive synergies with our existing hubs. In total, we plan approximately 12 exploration wells for 2018. In addition to the two wells just mentioned, we will participate in four more wells in the North Sea and six in the Barents Sea. In the Barents Sea, we are primarily looking for standalone potential. The potential hydrocarbon volumes in the prospects we plan to participate in and drill are significant. The risk is obviously also high, as has been demonstrated by the rather disappointing exploration result in the area last year.
However, Barents Sea still remains an underexplored region that holds a massive resource potential, and the significant improvement in drilling efficiency that we have achieved recently, combined with lower rates and a balanced tax system, means that these wells represent low-cost options that we think deserve to be drilled. In the North Sea, we are currently drilling the previously mentioned Frosk or Frog well near Alvheim. This will be followed by Rauosen, which is a prospect located near our Garantiana discovery and with several existing fields as potential hosts in the neighborhood. It's also worth mentioning the Hornet prospect, which is a potential standalone target in the Sleipner area, and Cassidy, which is located in the Ula license and a possible tieback candidate for Ula. We are, of course, very excited by this program, which we hope will generate discoveries that could add to our long-term growth stories.
We may actually add one more well to this program following the recently announced APA license awards. We are extremely pleased with the outcome of the APA 2017 licensing awards. Aker BP was awarded 23 new licenses, out of which 14 was operatorships, and this gives us a success rate of close to 100%. The awards gives us access to attractive exploration opportunities both around our existing production hubs and in new prospective areas. Two of the new licenses, both of which have significant volume potential, come with drilling commitments. One of these, production license 916, is located near Johan Sverdrup and contains a very interesting prospect that we hope to drill already in 2018. This is definitely one to watch. This concludes my outlook section, but before we open up for questions, let me just remind you of our main priorities, which are the same as last quarter.
We will continue to work hard to deliver safe and efficient operations. Needless to say, our HSE program has top priority, with continuous focus on optimizing production, both in terms of cost and uptime. The same goes for project execution. We have many important development projects going on in parallel, and we need to deliver these according to plans in order to secure long-term profitability. Our continued improvement program with the ambition to make radical changes to the way we conduct our business in order to achieve step changes in efficiency and cost is also ongoing. Among other things, this includes new ways of working with our suppliers through the alliance structures previously mentioned, and it includes taking advantage of digital technologies across our entire activity space in order to improve efficiency and increase value creation. We will also continue to mature new investment opportunities across our portfolio.
Even though the oil prices have recovered somewhat, we stick with our criteria of $35 per barrel as a break-even, which we think strikes a good balance between what is possible and what is necessary to create attractive shareholder returns. Finally, on the growth side, we continue to pursue both organic and inorganic growth opportunities, always with a view to apply our existing capabilities to maximize resource utilization and value creation to our shareholders. In sum, we think this can bring us closer to our vision, which is still to be the leading independent offshore E&P company. With that, we conclude today's presentation and open up for questions from the audience and from the web. Thank you so much.
Oliver from SEB. 2017 CapEx came in slightly lower than you have guided. You said that was due to lower spend on . Is that due to cost savings or is it phasing of CapEx?
It's a little bit of both. Predominantly it's due to higher efficiency, higher productivity, and therefore lower CapEx.
The 2018 CapEx, does that include the original estimate from Statoil as it sits today, or have you taken into account any further potential cost savings in that CapEx guidance?
The CapEx guidance for 2018 includes only on the operator's current forecast for CapEx in 2018.
All right. Last question, you sold 10% stake in Valhall to Pandion. Can you say something how the progress and the process is on the remaining 20%? How long have come in the negotiations or potential negotiations on that remaining part?
For the time being, there is no ongoing process on the remaining sale in Valhall. We are happy with our position. We believe that this is an extremely interesting asset with high upsides. We will continue to mature projects on the Valhall Hod area in order to increase the reserves. Our long-term goal is, of course, to get to around 67% ownership, but there's no rush.
You have a deadline for that?
Absolutely not.
Thank you.
Okay, we'll take questions from the web. Starting with Andy Owen at Handelsbanken Capital Markets. Related to Skarv, I assume that two shut-in wells will impact Q1 in most of the quarter. How much do they normally produce, and what is done to prevent the same well failures elsewhere?
Okay. Out of these wells, only one will actually have a minor production impact. The result is that the way the Skarv field is set up, we can distribute production between the wells in order to keep the production volumes basically the same for a short period of time. We will recomplete at least one of these wells in order to balance out again the drainage of the field long term. We don't believe that to be a significant production impact as such. When it comes to cost, I think we have to remember that we recompleted the previous well in the middle of the winter season, which is probably where you should expect most rig downtime. The next one will probably be towards the spring with, at least statistically, a lot better weather. We expect lower cost on the next recompletion.
We are currently carrying out an investigation of the cause of these failures. As far as we can see, there are different failure modes. We have, of course, expected every other Christmas tree on the fields. We don't see any reason that more of these wells should fail in the same manner going forward.
Okay, we have a question from Niki Kouzmanov at Jefferies. Is there any reason why average production should not go up from Q4 2017 with further two-step increases of allocated capacity at Edvard Grieg? This is related to Ivar Aasen, I suppose.
As far as I know, we are now at our maximum allocated commercial capacity across the Edvard Grieg field, which basically means that we are on the plateau. We have more well capacity, but we are at the plateau in terms of our current production capabilities across the Edvard Grieg field.
We have a question from Carl Fredrik Sjögren at ABG. Could you elaborate on the impairment of Gina Krog? What is the driver behind this?
I think on the Gina Krog, it's a smaller impairment, but it's basically just due to the long-term assumption that we have on oil price when we test this on a value in use basis. I think there's a bit of detail you can find back in the note disclosure. It's note five or six, I think it is.
The next question is from Alvin Thomas at Exane BNP Paribas. What will be the maintenance impact and its timing throughout 2018, and how much of this is factored into your production guidance? Second question, in your view, could there be upside from the further cost reductions at Aerfugl, Valhall Flank West, and Skogul? Lastly, assuming there are more acquisition opportunities available in Norway, what is the average leverage ratio you would be comfortable at?
Okay. When it comes to maintenance, all planned maintenance activities inclusive of some prediction of unplanned maintenance activities are included in the production forecast. There won't be any additional activities that will impact the production forecast as such. A further upside of cost reduction on Aerfugl, we still believe that it's possible to drive down cost by increasing productivity across the entire value chain, and that also goes for these projects. Of course, they are now maturing into an execution phase, and that means that a lot of the acquisitions in terms of bulk valves and packages have already been done. The remaining cost reduction will come from a more efficient installation and construction phase. I think the last one was leverage ratio. Do you want to say something about that?
The short answer is that we don't really have a specific target or a specific leverage ratio we need to be within. I think in the past, we've done transactions where we've had a higher leverage ratio than what we have today. I think that going forward, you should expect us to remain a robust balance sheet, but also a balance of being opportunistic again, if there are good M&A opportunities that we believe are value creative for the shareholders.
I think it's important to understand that we will continue to put value creation for our shareholders as the key ingredient, or key assessment, when we do M&A assessments. The criteria still remain the same. It's value creation. We're looking for oil, we're looking for operatorships, we're looking for assets with a high organic growth potential and possible tie-in areas. Those are basically unchanged, and we will remain disciplined in this area going forward.
Okay, we'll take a couple of questions from Teodor Sveen-Nilsen at SpareBank 1 Markets. When do you expect operator Statoil to update on Sverdrup Phase 2 production and CapEx? Secondly, what is the pre-drill resource estimate for the potential exploration well in PL 916?
Yeah. The operator does update the CapEx twice a year during the so-called CCE cost estimation updates. We expect the next one probably towards the, could come in as one of the announcements upcoming now with Statoil or towards the summer. We don't necessarily expect that there will be significant changes to the project in this time period as we are now well into execution. There could be some reduction in contingency as we see the project progressing pretty much according to plan. I think the last one was-
Pre-drill estimates.
Yeah. We haven't really released that number. We'll come back with more detailed information on this prospect as soon as the license work is finalized.
Okay, we'll take a couple of questions from David Mercer at Deutsche. Ivar Aasen has reached plateau ahead of the final contractual allocation increase in Q3 2018. Does your current guidance allow for increases above this plateau? Secondly, given your close relationship with your suppliers, have they indicated higher activity on the NCS following the recent recovery in commodity prices?
When it comes to Ivar Aasen, we have included the contractual capacity that we have access to in our guidance. We don't necessarily see an upside to this if things don't change from when we stayed today. Yes, we have a very close relationship to our suppliers. I think they, as many others, expect more activity on the Norwegian Continental Shelf, both as a result of the current improvement work that's been going on in the industry and the reduction in cost as a consequence of lower volumes of work being executed the last two, three years, but also due to the increase in oil price. How much that will be is difficult to say at this point in time, but it's also important to say we're still way below the activity levels that we saw in 2013 and 2014.
Neither Aker BP nor our suppliers expect a return to that activity level.
Okay, we'll take a question from Yoann Charenton at SocGen. Since reporting preliminary year-end 2P and 2C figures on 15th of January, what are the changes in estimates that you've been made aware of in addition to Lundin's revision of Filicudi resource estimates? Secondly, as part of the $170 million deal with Pandion, have you transferred historic tax balance and uplift balances associated with that sale of Valhall to your new partner?
First question, no changes. If I recall correctly, we did not have any resources from Filicudi on the 785 total was only on Gohta. No change there. Secondly, yes. It's normal standard sale, 10% share in Valhall Hod and the associated tax balances with that 10% goes with it. That concludes our Q&A session.
I think there's one back there.
Yes, sir.
Thanks. Sorry, one more. Victoria McCulloch at RBC. Just following on maybe from David's question, with the oil price now near $70 a barrel and for a slightly longer period and slightly more optimism, how do you think this impacts both your costs of existing operations and M&A and the wider sort of portfolio as an acquirer? Separately, looking at hedging, I know that you've used the US dollar, NOK to US dollar in your guidance. What hedging do you have in place for FX going into this year?
Okay. I can talk about your first points initially, you can talk about hedging. When we think about this, we see a slight cost recovery in terms of unit costs. We see this particularly probably in the drilling market coming up now initially. There's still lots of capacity left untapped. How this will actually impact the market is highly dependent on what kind of capacity gets contracted, and how the prices end up. They will also be impacted by the fact that we've, over the last couple of years, seen a significant improve in productivity.
Even if you're kind of going back to the number of wells drilled on the exploration side, as an example, to what we saw back in 2008 and 2009, we see that the productivity levels are higher, meaning that less drilling days will be necessary to drill out the same number of targets. That will keep a downward pressure on prices. In total, how this will pan out is a bit difficult to say from where I stand today. We are focusing almost solely on flow efficiency and productivity, because we think our ability to impact on unit prices is rather limited as a small E&P player in a pretty big market.
We think our execution model, particularly as it pertains to the alliance model, gives us higher productivity and therefore higher flow efficiency, and therefore lower cost per amount the work carried out in the end versus other normal execution strategies. When it comes to the M&A market, 2017 has been an incredibly active market on the Norwegian Continental Shelf with a lot of our transaction closed, both in terms of straight sales, mergers, and acquisitions, some of them with more inventive formats and schemes. It's not completely ruled out that this won't continue out in 2018 as prices increase and therefore also as the price ask merge. However, you could also find that the activity decrease as sellers get more optimistic on their outlooks from their existing assets. Again, it's a little bit hard to judge, but it's definitely going to be interesting.
On hedging, on FX hedging. We have in the past been hedging, I think it's around 40% or so that we've tried to hedge on the NOK exposure. We very much think of this company as a US dollar denominated company. It's the NOK OpEx, and it's the NOK CapEx predominantly on the Johan Sverdrup that we're trying to hedge. I think recently, and as we speak, we are more actively hedging the point estimates on taxes. When we're expecting to get a tax refund, we are hedging that exposure just by using forward contracts. It's a NOK 1.5 billion tax refund. We are, as we speak, trying to hedge a significant part of that, which is a NOK exposure.
Okay. I think that concludes the Q&A round and therefore also the Q4 presentation. Thank you both those in the room and those on the web. Thank you so much