Earnings Call: Q1 2019

Apr 26, 2019

To those of you who are joining us online or on the conference call, Let me just warm up by giving you a few operational highlights for the quarter, and we'll come back to all of these issues later. First of all, we had a very strong operational performance in the quarter, high production efficiency and excellent project execution of our field development projects. 2nd, our improvement program continues to deliver data driven innovations, and I'll touch upon a couple of these use cases later in the presentation. And thirdly, we continued expanding our resource base with exploration success at Alpine and accelerated Afrin development and recently, a new sanctioned infill campaign at Walhalla. On the right hand side of the current slide, we have given you some financial key figures of the quarter, including restated figures for the 4th and the 3rd Q4 and Q1 of 2018 due to new accounting standards. We'll, of course, come back to these different items in more detail later in the presentation, and I'll start by running through the production numbers. Production in the Q1 of 2019 stood at 159,000 barrels of oil equivalent. This was an increase of roughly 3,000 barrels compared to the previous quarter and more or less exactly in line with our plans. The Valhall production was particularly strong, and I'm happy to see that the Valhall strategy is working. More about that later on. I'm also pleased to see the increased production efficiency across our all our assets shown here on the right hand side of this page. We're currently running high and stable stable and high quality operations on all assets. I'm particularly pleased with the almost perfect performance of the Eurost asset and the great improvements at Ula and Walhall. They particularly stand out. However, all the assets have done a great job this quarter in keeping efficiency high and delivering on a stable operation. So with that, let's go through the assets. And as usual, I'll start with Alvheim. Alvheim is a reliable top performer with stable and high regularity. That's also the case in the Q1 of 2019. The total production decreased somewhat due to natural decline in the different vessels in the Alvheim area, though there's been very strong production numbers coming from Alvheim Main in the last two quarters after the chameleon infill well were put on stream in the summer of 2018. Our mission on Alvheim continues to be the same mission that we've catered for the last few years, and that's to increase oil recovery and add new resources. We've made the discovery at Foskulov in the quarter, which follows the Fosk discovery from last year, and we continue to explore in the area. We're currently drilling a multilateral well with several well targets and data collection pilots, which will later be completed as a test producer in Fosk. These targets include the Foskula northeast. And in the Q3, we also plan to drill an exploration well in the so called fog padfold projects. Production start from Skogrill is now planned for the Q1 next year, and the project is progressing according to plan. The drilling operation will commence in the Q3, and we will also drill or we have also drilled a sidetrack well at Wollum, which now are in the completion phase at this well. With that, I'm moving over to Iverossen, which has also been a top performer this quarter. The production efficiency in the quarter was a stunning 98 percent, and the improvement is primarily driven by the high regularity and availability of export capacity and adequate power supplies supported from Evotrig. The facility themselves at Eevaossen have had high regularity over quite some time. We have also been able to improve the water injection at the Osmond, which gives us now a high voltage replacement ratio and a higher gas oil ratio as you can see for the production chart. Oil is going up, and gas oil ratio is going down. It means that total production is going up. The improved reservoir pressure also mitigates the risk for negative impact on production should we experience more power issues in the future as we are now in a better shape to withstand periods without pressure support. And pressure support is an excellent segue over to Skalve. On Skalp, we had to shut down gas injection and oil production from late January to mid March due to failure of a gas injection compressor motor, however, compensated by strong operational performance of the gas production, which partially compensated for the shut in oil production. The compressor motor was replaced in a very efficient operation, and oil production was reestablished in late March. This is not an easy operation in the middle of the winter in the Norwegian Sea. The Christmas tree repairs are progressing using very successfully using a new cost saving in situ repair method, and we have now repaired 5 out of 14 Christmas trees, this time without production loss. I am also pleased to report that the offshore modification work that was carried out for the Afrin project is progressing according to plan. The Afrin project is probably one of the most successful project in Norway right now and probably also the most undercommunicated world. At this time, we have decided that it deserves its own slides. As I said, Phase 1 is moving on according to plan. The good news is that we've been able to accelerate the 2nd phase of the project by more than 2 years. This has been made possible by debottlenecking at the Skal facilities and by utilizing an existing well slot on an existing subsea template for 1 of the 3 planned wells in our field Phase 2. In reality, this is the alliance model in operation. This demonstrates that the alliance model that we reestablished is working and giving highly efficient project execution methods. The improvements at the Alfred project, including the acceleration and the optimization of well locations, have also pushed down breakeven price in plant terms from roughly 18.5 dollars down to $15 a barrel. And remember, this is about 70% gas and 70% oil. So if you look at it in gas terms, we're talking about roughly $1.5 per 1,000,000 btu in gas price breakeven. These are really stunning numbers. A significant improvement, and I'm really, really proud of the whole Afro team and a big thank you to all the people who have been working on this project, both inside Aker BP and with all our alliance partners. At Ula, the current priority is to establish stable and robust operations. We're focusing on 3 main areas. The first one is to improve the HFC performance in a very highly active offshore environment, to strengthen the integrity of the infrastructure to cater for a long lifetime and thirdly, to establish efficient drilling of new wells. The work is well underway. And on this picture, you can see the Saipem 7,000 removing the old derrick from the drilling platform at Ula. The fixed drilling rig at Ula was no longer fit for purpose, and we are now preparing the platform for drilling with a highly efficient jackup rig of the kind that we used to drill with in our other operations. In the background of the picture, you will also see the flotel, which has been used to host all the additional people currently working on the various maintenance and upgrade activities on Ulan. This work has been going on for several months and will be completed shortly. By midyear, we will bring in the Maask integrated rig and start a 1 year drilling campaign, which will help stabilize production in Ula and make Ula ready for the next phase. And while we're at Ula, it's also worth mentioning that the Oda satellite feed was brought in production during March, and this obviously also has a very positive effect for capacity utilization at Lula. At Varlau, we now start to see the effects of the growth strategy we embarked on a couple of years ago. In the Q1, production reached its highest level since we took over the field in 2016, basically driven by 2 factors. The first one is to increase production efficiency, and this is a result of a lot of hard work and continuous focus on improvement and stable operations. It's truly remarkable to see production efficiency increase by almost 10% from Q1 2018 to Q1 2019. And second, we also see the full impact of the new wells that were added towards the end of last year. But we are planning for more growth at Valhall. The Valhall Lesserne project are progressing as planned. And on the picture, you can see the jacket or substructure of the Valhall wellhead platform. This is now completed and scheduled to sail away tomorrow. The top side is also nearly completed, and the drilling operations are scheduled to start in Q3, and we're targeting first oil before year end. On the Varal field center, the IP drilling campaign is about to be completed. We have now sanctioned a new 7 well program at the RalalWP platform. And thirdly, we are also working to on a project to redevelop the Hod field. In the Q1, we drilled a combined exploration and appraisal well on Hod, which unfortunately turned out to be dry. However, this new information will be used to optimize the development solution on the fleet. Overall, I must say, I'm extremely pleased by the progress across our operated assets, and things are also moving nicely ahead on non operating side. And by that, I'm obviously referring to Johan Sverdrup. On this spectacular picture, you can see the living quarters being lifted in space using a single lift technique. Now on the agenda now is hookup, testing, commissioning of the 2 final top sites, and that will be followed by Completing the tieback of the predrilled 8 wells or production wells on the drilling platform will also come as a separate activity in addition to this commissioning activity. So while there's still a lot of work remaining, the project remains on track to start production in November, and we're extremely pleased with the work that the operator is doing on Johan Sverdrup. Moving on to Norka. We are still pushing for an area development, and we remain firm that the PQ is the best alternative for the development in the area, both in terms of highest value creation and robustness. It also secures maximum resource utilization and finally, has a capacity for further discoveries in the future. Aker BP has, therefore, rejected the proposed Carfla UPT development. And due to the voting rules in the license, this means that the UPP solution is currently ruled out. As a prudent partner in the Kaffa license, Aker BP has instead proposed the PQ solution, which we believe is the best alternative not only for the whole area, but also for the kafla license as such. And our partner is currently undertaking technical reviews of the PQ concept. It's, of course, well known that the interest in the Norge area are not fully aligned between the different license holders. Our ambition is to unlock the full value of the area to the benefit of all stakeholders, And we have matured the PQ concept to a level where we are confident that this is the best solution and are eager to move ahead. Let me also spend a few words on exploration. On this slide, we show exploration program for 2019, and we have this time included spud time estimates for each well. Otherwise, the lift is pretty much as before, apart from the fact that the first three wells have been completed. And with the Foskula discovery, this has clearly been a very good start to a very busy exploration year. We look forward to the continuation. Now let me turn to one of my other favorite topics, improvements. Logistics and operational support remains a significant part of our cost, roughly 10% to 12% of the OpEx and drilling and well spend, respectively. And there's still a lot of waste to be removed, both in our company but also on the Norwegian company level shelf as a whole. Too often, we see separate vessels for separate needs, low predictability for transported volumes and difficulties in rightsizing the PSV fleet. During this quarter, we have ramped up our efforts to cut logistical waste using digital tools and leaner sailing patterns. We have recently started to build the X Chain system, which is a blockchain based open source information sharing platform that will enable just in time delivery, increase efficiency and reduce unit costs. Our ambition for X Chain is that this will become the industry solution also for NPS. We have also signed a frame agreement in Q1 with suppliers of Platform Supply Vessels, or PSVs. This is the first step in establishing yet another strategic alliance with the aim of driving improvements through the value chain to become even more efficient. And finally, one of the latest examples of how lean thinking in the logistics department reduces waste is from Ruhle and Varhall. There's a lot of activity going on, as we've already talked about, at these two informations, with both production, projects and drilling operations going on at the same point in time. The traditional way of supply vessels planning has resulted in low utilization of the vessels making round trips to the field centers. After working on this problem with cooperation and organizational effort as the only input factors, in addition to availability of data, both on logistics and on sailing patterns, we've been able to optimize the sailing pattern. The results are better service at a reduced cost and the yearly cost improvement only for Walla and Lira asset is about USD 10,000,000. This is a wonderful example of how soft skills can drive hard results, and we will continue this improvement journey at the other Aker BP operated field centers. 2nd, smart maintenance has long been touted as one of the most promising abilities for machine learning, and it's one of the promising opportunities that lies from the digitalization and data liberation platform that Aker BP has developed in conjunction with Cognite. It's now recently named Data Fusion. With the implementation of this platform, we have created an ecosystem that invites to innovative ways to analyze what is really going on with our equipment. And we have, on previous occasions, talked about the Framo frame agreement and management of water pumps as well as production optimization initiatives on several of our fields. This quarter, our team has come up with related to the multiphase pump, which are transferring gas oil from Tamba to Ula. This pump has created repeated downtime due to unexpected technical failures, and we're now using predictive analytics on the live data from this pump to be able to predict failures before they happen and, hence, take necessary action in due time to avoid losses. The estimated gross volume of this initiative alone is around USD 50,000,000 over the next 5 years. And with that, I'll give the room to David Turner, who I think this is your 2nd quarter actually. David? Thank you, and Joe. Good morning, everyone. As normal, I will walk you through the financials of the quarter, focusing on the statement of income, changes in the balance sheet and the cash flow. However, before I go into the details, it's worthwhile mentioning the two changes in accounting principles that has occurred this quarter. 1st, the new leasing standard became effective from the 1st January, and the impact on the accounts are in line with what was described in our annual report. The impact on the profit and loss is immaterial as most of our leased assets are used for activities that are capitalized. I will cover this change in principle a bit more in detail when we talk through the balance sheet. The other accounting principle change is related to the method for revenue recognition. Prior to 2019, we booked revenues based on produced volumes, commonly referred to as the entitlement method. As of Q1 2019, we have changed the revenue recognition to the sales method. This means that we recognize the income of actual sold volumes. The difference between the produced and sold volumes will be valued at cost, including depreciation in the balance sheet and booked as an adjustment to production cost when the barrels are subsequently sold. The production cost on the face of the income statement, therefore, reflects the cost of sold volumes. And in Note 3, we have disclosed the production cost based on produced volumes and the adjustment separately. Comparable figures has also been restated. So if we look at our revenues. In Q1, as you can see behind me, Aker BP produced 158,700 barrels per day. The sold volume for the quarter ended at 162, up from 151.5 in Q4. This represents an increase of nearly 7%. Although oil prices increased throughout the quarter, the realized hydrocarbon prices was on average 8% lower in Q1 than in Q4. And in total, petroleum revenues ended at NOK 858, which is a slight decline in Q4. If we then move on to the income statement. We recorded a total income of SEK 836 1,000,000 in the quarter. And here, you can see that the SEK858 1,000,000 from the sale of petroleum has been slightly offset by a reduction in the market value of hedging positions of roughly SEK 26,000,000. The hedging positions consist of put options, which saw a significant value increase in Q4 as the oil price dropped, and then these gains have now been reversed in Q1 when the oil price had rebounded. Production costs in the quarter was 200,000,000. Similarly, as for revenues, this line item has been impacted by the change in accounting principle. If we exclude the adjustment for over lift as disclosed in Note 3, the production cost related to produced barrels in the quarter amounted to NOK 191,000,000, which is a slight increase of NOK4,400,000 versus Q4. The production cost per produced barrel was SEK13.4 million. This is a slightly above our average full year guidance, but in line with our plan for the Q1. And the main driver for this is the high maintenance activity at Bolholl and Yulav conducted while we have the extra accommodation units at the fields, as previously also shown by Karl. Now if we look across our 5 hubs, OpEx was slightly down both for Alpehm and Imorossen, and cost per barrel ended at 6,000,000 and 8,800,000, respectively. At Skalik, as Karl mentioned, production was impacted by the period of shut in of gas injection. As a result, cost per barrel increased roughly with $1 versus Q4 and ended at $13 per barrel. Some technical difficulties, but I think we're okay. At Ula Sandberg, cost per barrel was €56,000,000 In addition to the high maintenance activity as already mentioned, the production cost was negatively impacted by a reduced productivity from the Hamburg wells and the planned shutdown related to the production start on the Oda field. On Var der Halle, absolute costs were stable versus Q4. However, the strong production performance drove down cost per barrel with more than $2 and ended at roughly 17. Moving on to exploration expenses. This quarter, it amounted to NOK 90,000,000 and the increase of NOK 18,000,000 versus Q4 is mainly related to drybulk cost on Njokossen and Hobbip. This was somewhat offset by the lower seismic spend in the quarter. Our cash spend on exploration was NOK 159,000,000 in the quarter. This is in line with our plan and the full year guidance of NOK 500,000,000, but the drilling program is front end loaded. Hence, we expect exploration spend to be a bit higher in the 1st 6 months versus the second half of the year. If we summarize these lines, we get an EBITDA of €539,000,000 in Q1. Depreciation was €183,000,000 or $12.8 per barrel. This is a decrease versus Q4 and is mainly driven by the changes in abandonment provisions at the end of 2018, which was booked as a negative addition to fixed assets. This quarter, we also recorded an impairment of technical goodwill of 69,000,000 at BRLHAN Hamburg. As we continue to mature the opportunity set in the area, we update assumptions on production and cost profiles, and the latest update included a shift in time line and also a slight cost increase in some of the future subprojects. This had a corresponding negative impact on the fair value estimation. Deducting depreciation and impairment from EBITDA, we get an operating profit of SEK287,000,000. Net financial expenses in the quarter were SEK 37,000,000 as the dollar to Norwegian kroner exchange rate was very stable from January to March. Currency fluctuations had limited impact on our expenses this quarter. Profit before tax was NOK249,000,000 and taxes amounted to NOK 239,000,000 Of these, NOK 129,000,000 was the current tax arising in the quarter, and approximately NOK111,000,000 was related to the change in deferred tax. The effective tax rate for the quarter was 96%, and the relative high tax rate is mainly driven by 2 of the elements already discussed. It's the impairment of technical goodwill with no associated tax and the loss related to hedging positions, which is subject to corporate tax only. The actual tax payment in the quarter amounted to NOK 106,000,000 and is in line with the guidance we provided at the Q4 presentation. Thus, net profit in the Q1 ended at NOK10 1,000,000. If we move over to the balance sheet, in general, it has been fairly stable this quarter and the most visible change is perhaps related to the implementation of the new leasing standard. We have shown the impact on separate line items where the right of used assets arise from the recognition of long term and short term leasing debt. And it's also worth noting that we have used the so called modified retrospective approach with regards to this transition, meaning that no comparable numbers have been restated. PP and E increased by NOK 208,000,000 and we had additions of €360,000,000 where investment at Van Hollen Johan Sverdrup made up 75%. And then we have depreciation of PP and E, which amounted to €160,000,000 On the other side of the balance sheet, we can see that equity was reduced by NOK177 1,000,000. This is mainly representing the net of dividend and net income for the quarter. Bonds and bank debt increased as we drew on the RBL and then total lease debt came in as a new class of debt amounting to SEK 369,000,000. The difference between the lease debt on the one side and the right of use assets on the other is related to the provision for fair value of contracts as specified in Note 10 and 14. These have previously been presented separately, but are now netted against the right of use assets. Total equity and liabilities amounted to $11,100,000,000 at the end of the first quarter. The cash flow summarizes most of the items discussed so far. We started Q1 with NOK 45,000,000 in cash. During the quarter, we grew NOK 200,000,000 on the RBM. Cash flow before tax from operations amounted to SEK 696,000,000 and then tax payment, as mentioned, was SEK 106,000,000. And then cash flow to investments was NOK 511,000,000, of which the main contributors were €364,000,000 in investments in fixed assets, which includes €42,000,000 in capitalized interest NOK126 1,000,000 in exploration, NOK21 1,000,000 in Dcom and P and A. And then lease payment also amounted to €21,000,000 And in this chart, we have deliberately stacked leasing on top of the CapEx to illustrate that these costs are mainly related to the CapEx activity. Dividends amounted to SEK 187,500,000. Then at the end of the quarter, our cash balance was EUR 114,000,000, up 65. The book value of net interest bearing debt was roughly NOK2.5 billion. We had NOK2.85 billion of committed undrawn capacity on our SEK4 billion bank facility. And excluding the effects of IFRS 16 leases, our leverage ratio, net debt to EBITDAX, was roughly 0.7 at the end of the quarter. While talking on financing, Aker BP is continuously working to optimize its capital structure. And we have currently a mix of secured and unsecured debt with a $4,000,000,000 RBL as a major part of the structure. The RBL matures in 2021, and we are therefore working with our bank syndicates to refinance this facility. As of now, yesterday, we are now in the process of establishing a new unsecured credit facility of SEK4 1,000,000,000, which likely will be completed in Q2. With this new unsecured facility, we will achieve 3 main objectives. We extend the maturity of our bank's debt and maintain full financial flexibility. The interest cost for the company will be reduced. And all lenders to Aker GP will be party pursuit, which should also be positive for our credit quality in the bond market. It's safe to say that we're very happy with getting this facility in place and with the support from our banking group. To round off my section, I would like to revisit our guidance for 2019. We have guided production between 155,000,160,000 barrels per day. Q1 came in a bit above the midpoint, which was in line with our plan, and we maintain our full year guidance between SEK155,000,000 SEK160,000,000. There will, however, be some variations in the coming quarters. In Q2, we expect production to be around 30,000 barrels lower than in Q1 due to planned maintenance stop at Vallhalla and Lotte. In Q3, we should be back at roughly the same level as in Q1. And then in Q4, we should see a significant uptick also in the proximity of 30,000 barrels per day, then also driven by Johan Sverdrup and to some extent also the Ball Hall Flank Westfield. As mentioned, the full year production guidance is therefore kept as is. We have guided 2019 CapEx at SEK1.6 billion, assuming a dollar to Norwegian kroner exchange rate of 8.5. Key drivers for this spend level is Ballahol and Johan Sverdrup. And Q1 was a bit below the average for the full year, but this is mainly phasing and we still expect to end up around SEK 1,600,000,000. Exploration spend, as already mentioned, was guided at NOK 500,000,000, and we keep that guidance as is. Abandonment expenditure for 2019 is guided at NOK 150,000,000. The spend in Q1 was more or less as expected €21,000,000 However, the plans for P and A activities at Vallal and Hod in 2019 are currently being reviewed. Given the flexibility in our business model, we might choose to utilize the rig for production drilling instead if that creates more value and is more optimal from an operational planning perspective. If we end up doing this, some of the spending will then be reclassified from abandonment expenditure to CapEx. However, the overall spend is not expected to be influenced by such an optimization exercise. Production cost per produced barrel came in at 13.4% in Q1. We expected Q1 to be higher, as already mentioned, than the yearly average due to the planned maintenance activity at Valhall and Eula. And we still expect the full year average to come in at 12.5. And last but not least, we paid the SEK 187,500,000 in dividend in Q1, and we still plan to pay SEK750,000,000 for the full year 2019. That concludes my part of the presentation, and I'll leave the word back to Karl for some concluding remarks before the Q and A. Excellent. Thank you, David. Great. So before I conclude, you may have noticed that we have recently announced a couple of changes to our Excessive Management team. So let me spend a couple of minutes just walking you through those. We have appointed Knut Sandvik as our new SVP of projects. Klut comes from Market Solutions, where he's been a member of the executive team for a long time and most recently had a responsibility for GreenTree Projects. I believe Klute will make a great addition to the management team in Aker BP. His long and dedicated experience from our industry will be invaluable to contributing to further improvement our product our project execution capabilities. And then the clear this, of course, replacing Olav Henriksen, who will move on to Aker Energy. And I wish to use this opportunity to thank Olaf for his outstanding contribution to Aker BP over the years. Or as a new Head of HSE. She comes from the position as Vice President within our Drilling and Well department and have been with the company since 2017. Jurgen is she is based in Jurgen Koller, who is joining the Valhall management team. And Jurgen has been instrumental in lifting the HSE agenda during her tenure. I'm really pleased to see that she is bringing strategic management capacity into the further development of the extremely important Valhalla area. And then also 1 year ago, we announced the appointment of Kjetil Dijk as our new SVP of Operations. It seems like a long time ago, but time flies. And we now look forward to welcoming on board next week on the 1st May. And Kjetil is replacing Sain Jacob Blicknes, who has done a great job SVP of Operations in the interim period. I would also like to extend my gratitude to Sven Jakob for his strong contribution, dedication, energy and humor in this period. Then finally, I don't as I've talked about previously, we feel that the strategy we are pursuing is demonstrating tangible results. Production is strong, regularity is trending up, improvement capacities are improving, and our project execution skills are getting even better. We see no reason, therefore, to change our strategy and are continuing along the same lines and with the current priorities. On the execute scale, we will continue to focus on safe and efficient operations. We will continue to execute excellently on productions on projects and have a large scope of future projects to deal with. On the improvement, I think we've demonstrated that ability to go beyond the hype in the so called digital transformation and are now moving into an area where digital is actually having a direct impact on our operations. We will continue our quest to reorganize the value chain and build further and deeper alliances to further improve our project execution skills. And we'll continue to apply new technology to drive value creation. On the growth side, you have seen a high exploration activity and a high willingness to mature resources to reserves. That will also be the priority in the next periods. So with that, I thank you. We close this part of the presentation, and we'll open up for questions. And if memory serves me correctly, Jethil, we'll open up with questions from this room first and then move on to the conference call. So I think Tore has a mic. So if anybody has a question, raise your arm or shout out or do something to get his attention, and you'll get the mic. And let's get the ball rolling. Everything seems to be clear as ink. That was fantastic. So, Gettel, are there any questions from the operator? Thank you. We'll take our first question from the line of Daniel Brown from JPMorgan. Please go ahead. Hello there. Hi, good morning. It's a bit less admin incentive versus the RBL and also something that we're drawing of €1,100,000,000 at the end of the Q1, do you think you will look to maybe refinance some of those drawings, the senior bond market in the sort of coming 12 months or so. I know it varies throughout the year, but it seems like there's $500,000,000 drawn on this facility. But I'd just like to hear your thoughts on the back of this financing. Thank you. So there seems to be some noise on the line, so it was a bit difficult to interpret the I think I've heard a question around if it's likely for us to go into the bond market in the near future. Is that the question? Well, I think the rationale is you've obviously just refinanced this new facility. There's €1,100,000,000 of drawings at the end of the Q1. There's always €500,000,000 drawn throughout the course of the year. Therefore, would you look that seems to be more permanent borrowing rather than something you would use a sort of RCF for typically. So yes, in the next sort of 12 to 24 months, would you look to refinance some of those drawings into the bond market given the same purity package? Yes. So the short answer to that is that the facility that we're putting in place is basically split in 2. So one part is the SEK 2,000,000,000 liquidity, we'll call, backstop, and the other part is a SEK 2,000,000,000 working capital facility. And over time, we definitely see that as a bridge to bond facility where we will move into the bond market. Okay. Super. Thank you. We'll take our next question from the line of Alwyn Thomas from Exane BNP. Please go ahead. Hi, good morning team. Just wanted to clarify a few points. I appreciate some of the color you gave on the coming quarters. Could I just ask, given maybe just ask for a little bit more detail on the reasons for the production coming lower in 2Q on maintenance? And would you expect that to do to OpEx during the quarter? As well as perhaps a little bit more detail on the CapEx phasing throughout the rest of the year, particularly as Johan Sverdrup comes to an end. And just to follow-up on the new unsecured RCF. Are you expecting interest charges to be less as a result despite it being unsecured? And that will do for me. Okay. So Henrik can start up. In the next quarter, there will be turnarounds on Valhall and Ula, both impacted both impacted by the turnarounds also at EcoFisk, which is the export facility for these installations. We have currently estimated that to be roughly 30,000 barrels lower than the impact to be 30,000 barrels lower than in Q1. And there is, of course, a certain impact from the OpEx per barrel. Remember that some of this activity is also CapEx activity, so it won't be a direct read across in terms of OpEx per barrel. Now as always, in this period of time, we're working to optimize the turnaround work scope and minimize it as much as we possibly can. So the figures I just gave should be looked upon as very preliminary. Now in terms of CapEx phasing, there are basically 2 things that are impacting the in quarter results. So the first one is the rollover from Q4 2018. And the second is the way the activities in Q1 2019 are being invoiced. So despite Johan Sverdrup coming to an end in terms of CapEx, we expect the in year total to be very close to the guided 1.6. That obviously means that you should see some higher CapEx figures in the next few quarters. And then related to the RCS, David? Yes. So the RBL was established when Aker BP was a different company. And we're very happy to say that the company has grown and matured, and we're also able to mature the capital structure. And the RCF, as mentioned, is an unsecured facility, whereas the RBL was a secured facility. And although there's a difference there, we're still able to reduce the interest expense. So that's obviously something that we're very happy about and very about the ongoing work and the support from our banking group. Okay. Can I just follow-up quickly, Carla, on CapEx timing? Given the delays to Noaca concept selection, is there possible room there that there could be some, I guess, CapEx shifted into futures related to that? Or will you expect to use it elsewhere? And I guess whether there's any cost contingency left in Valhall West Flank as well, given the good progress on the project? Thank you, Amit. So when it comes to the complex program and the effect of that Nuocco discussion, I think the main discussion that we're having right now is how to utilize P and A capability or rig capacity allocated to P and A in 2018. And recent results from the production drilling from Valhall has at least indicated that there might be possibilities of reallocating rig hours from the removal of the OpEx or P and A activity into more value creative activities in drilling on new wells. If we do decide that, that is a good use of the rig, then obviously, CapEx will be reallocated also from OpEx, but that will fill up the entire year. So you may also see some of the CapEx that should have been consumed by the Norka project also being allocated to production drilling. From an Naka Bipi perspective, this is in the short horizon of obviously positive as it will drive higher cash flows in the quarters to come. And then I think the last part of the question was Balmainer, Jan Alevit. Yes, one of last time. Okay. Remember that this is an alliance project. So the normal way of actually doing these kind of assessments where you build up a base cost estimate and then you add allowance and on top of that, continues. It's not really the way we're working anymore. So a lot of this is now basically run up against the so called most likely cost estimates. And I think we've already predicted that when it comes to these most likely cost estimates, we're a bit on the low side, but that's also reflected in the current prognosis that has led up to our guiding. So this usual discussion where you see a lot of release of contingency and project as you lead up to production is not really an applicable discussion when you talk about the lives well. Okay. Thanks very much. We'll take our next question from Anders Holte from Kepler. Please go ahead. Good morning, guys. Thanks for taking my questions and congrats on a decent quarter at least from cash flow. Just a few questions for me this morning. Just wondering if you could elaborate a little bit more on the changes in working capital for the quarter since it's down out a little bit. And also, if you can indulge me on in the Frog area. Now based on the 2 wells that you now have drilled and the well that you are currently drilling, I wonder if you could at least give some color on what you see as a potential development there. Are you still are you thinking that this is a stand alone? Or is this more of a tie in back to Alvheim project for you as it now stands? I can start with the working capital. So the change in working capital is mainly related to change in accounts receivables, which is due to the lifting schedule. So it's not a sort of underlying reduction in working capital. And when it comes to the Frog area, we're currently assessing basically 3 different possibilities. And let me just remind you how we came about this area. So we did the Frog Well first, which was the kind of the opening of the area where we discovered both dikes and injectites and so called bracacia, which is the interface between the sands and the shale that the sands are injected in. And following that, we made further data evaluations and subsequently drilled the Frog Leg and are now currently drilling the Frog Test Producer with information gathering pilots also into the Frog Northeast the fogly northeast. So that means that a lot of these discussions will be impacted test producer. However, to give you some color, we have basically assessed 3 different options. The first one is that this is a tieback utilizing the Vela infrastructure and therefore have basically fill up the capacity on Vera, going up to Allem. The second one is to install a new manifold and a new set of subsea templates and tie that directly back to the Altair field. Both of them will, of course, have as a pro that they are very quick to do. They will give a rapid cash flow and low CapEx solutions, but they won't necessarily maximize peak production from the fog and the fog lag area. And then finally, of course, it's some sort of stand alone type of facility with or without processing capacity. I think there are 2 information elements that will impact the selection of development solution. The first is the result from the Frog Pest Producer and the second is the drilling of the Tadpole prospect towards the I think it's Q3 this year. So at that point in time, we'll be able to give more light on which concept we are likely to choose. And just as a quick follow-up there. How much of whatever you see now in the 4 gs era is already reflected in your guidance of £450,000 per day by 2025? So currently, none of this was included in the Capital Market Day presentation back in January. So we will update those figures when we have an idea of the field development solution. Okay. Thank We'll take our next question from Michael Astrapp from Citi. I've got 2, please. So firstly, on Johan Sverdrup. I know you've obviously reiterated the base case for first oil in November. However, if I remember rightly, the stretch target was to see production perhaps earlier in 4Q. And so I was wondering whether given the operations so far year to date, do you see a greater chance of the stretch target being reached, I. E, production earlier in 4Q? And then what would be the sort of the layout of the plan to deliver that earlier first oil? And then just secondly, on Nuwaka, I know you make, obviously, a compelling case for your pure concept in terms of higher recovery and lower breakeven. But obviously, the significant delay we've seen clearly impacts economics in terms of the timing of first oil and the ultimate NPV of the project. So I'm just wondering how you think about that in the context of, obviously, ongoing discussions with the other partner. Thank you. Okay. So thanks, Michael. So let's start with Johan Sava. So first of all, I think it's sad to say that even if the projects are going very well and we're really, really happy about the performance of Equinor as operator of this project, there's still quite a lot of work to be done in terms of testing, commissioning and other activities and, in addition, tie back all the 8 producers back to prudent producers back to the production infrastructure. There has been some discussion about an earlier start up, and we continue to see progress going pretty much into a direction where that may or may be a possibility. However, I think it's fair to say also that from an Aker BP perspective, the key value driver is to ensure that once we execute the start up, we're actually starting up this only once and have a really high quality operation. So from our perspective, we're happy to see the progress that are being made, and we're more focused on ensuring that there is a high quality start up once we start up production. And then, of course, there is a discussion around starting up is one thing and ramping up is another. So what we're probably more we'll be more interested in seeing a rapid ramp up, following a high quality start up, then pushing for an early start up and a subsequent slower ramp up. So at this point in time, I don't see any reason that we should predict or postulate an earlier start up and quite contrary, basically support the operator on the excellent work they're doing on the testing and commissioning ongoing at this moment. Now moving on to Norka. And of course, we would be very interested in moving ahead as swiftly as possible. I have been in that the position now for, I don't know, 4 or 5 months at least, that we were able to start up. However, we're not directly driven. The MPV or the projects are not directly driven as the resource utilization currently on Aka is relatively low. And again, this is an effect of how we're organizing the project in Aka BP, utilizing these alliance models, which allow us to scale up and scale down the engineering resources and other resources that are applicable for project and thereby also control the burn rate and the negative cost effects on such delays that we are experiencing at the moment. So basically, what we're doing here, Michael, is to reallocate these resources to other projects ongoing in the Aker BP portfolio. And just to give you an idea, we currently have about 33 BT projects ongoing in the Alliance, so there's lots of engineering work to allocate these resources to. So at the moment, we are not feeling that the timing is directly impacting the attractiveness of the BQ. PQ. Operator, we have time for one more question. Thank you, sir. We'll take our last question from Johan Charlton from Societe Generale. Your line is open. Please go ahead. Yes, good morning. Johan Chantal from Societe Generale. I will ask 2 questions on the financials. Would you be able to explain all the refinancing might impact your way of thinking in terms of managing the balance sheet in relation to credit rating? In other words, irrelevant is your credit rating on the back of this change in the structure of your funding pool? Yes. So obviously, it's not Aker BP who sets the credit rating of the company. But I think that moving into this corporate structure clearly indicates the strong support that the banking group has for our credit. And that's also a strong signal, I guess, to the rating agencies. Okay. And on taxation, could you please list the main items making up the tax payables book at the end of the quarter and comment on all accruals for uncertain tax positions have potentially moved during the quarter? I would actually not be able to answer that such in detail here based on my head. But I recommend you to call Jatin Bakken in Investor Relations, and he can give you a more detailed answer on that, Jaam. I apologize. Okay. Thank you. Thank you. And with that, I think we closed Q1 presentation of 2019. And thank you so much, and an excellent weekend to all of you when you get that far. That concludes today's conference call. Thank you everyone for your participation. You may now disconnect.