Aker BP ASA

OSE:AKRBP

Earnings Call Transcript 2019-Q1

[Karl Johnny Hersvik, Chief Executive Officer]

[Audio Gap] 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. Second, 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 Alvheim and accelerated Ærfugl development, and recently, new sanctioned infill campaign at Valhall.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 fourth and the third -- fourth quarter and first quarter 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 first quarter of 2019 stood at 159,000 barrels of oil equivalents. 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 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 Ivar Aasen asset and a great improvement at Ula and Valhall. They particularly standout. 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 first quarter of 2019. The total production decreased somewhat due to natural decline in the different reservoirs in the Alvheim area. Though there's been very strong production numbers coming from Alvheim main in the last 2 quarters after the Kameleon Infill well was put on stream in the summer of 2018. Our mission in 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 Froskelår in the quarter, which follows the Frosk 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 at the test producer in Frosk. These targets include the Froskelår Northeast. And in the third quarter, we also plan to drill an exploration well in so-called frog -- tadpole projects.Production start from Skogul is now planned for the first quarter next year, and the project is progressing according to plan. The drilling operation will commence in the third quarter, and we will also drill a -- we have also drilled a sidetrack well at Volund, which now are in the completion phase at this well. With that, and moving over to Ivar Aasen, which has also been a top performer this quarter. The production efficiency in the quarter was a stunning 98%. And improvement is primarily driven by the high regularity and availability of export capacity and adequate power supply, supported from Edvard Grieg. The facility, themselves, at Ivar Aasen, have had higher regularity over quite some time. We have also been able to improve the water injection at Ivar Aasen, which gives us now a high voidage replacement ratio and a higher gas/oil ratio as you can see from the production chart. Oil is going up and gas/oil ratio is going down, that means the total production is going up. The improved reservoir pressure also mitigates the risk from 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 Skarv. On Skarv, 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 Xmas 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 Xmas trees, this time without production loss. I'm also pleased to report that the offshore modification work that was carried on for the Ærfugl project is progressing according to plan. The Ærfugl project is probably one of the most successful projects in Norway, right now, and probably also the most undercommunicated one. So this time, we have decided that it deserves its own slide. As I said, Phase I is moving on according to plan. The good news is that we've been able to accelerate the second phase of the project by more than 2 years. This has been made possible by debottlenecking at the Skarv facilities and by utilizing an existing well slot on an existing subsea template for 1 of the 3 planned wells in Ærfugl Phase 2. In reality, this is the alliance model in operation. This demonstrate that the alliance model that we reestablished is working and giving high -- highly efficient project execution methods. The improvements at Ærfugl project, including the acceleration and the optimization of well locations have also pushed down breakeven price in Brent terms from roughly $18.5 down to $15 a barrel. And remember, this is about 70% gas and 30% oil. So if you look at in gas terms, we're talking about roughly $1.5 per million Btu in gas price breakeven. These are really stunning numbers. The significant improvement and I'm really, really proud of the whole Ærfugl team and a big thank you, to all the people who have been working on this project, both inside Aker BP and with our alliance partners. At Ula, the current priority is to establish a stable and robust operations. We're focusing on 3 main areas. The first one is to improve the HSE performance in a very highly active offshore environment, to strengthen the integrity of the infrastructure, to cater for 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 7000 removing the old derrick from the drilling platform at Ula. The fixed drilling rig at Ula was no longer fit for purpose, and we're now preparing the platform for drilling with a highly efficient jack-up rig of the kind that we used to drill with in our other operations. In the background, on 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 Ula. This work has been going on for several months and will be completed shortly. By midyear, we will bring in the Maersk Integrator 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 theUla satellite feed was put on production during March. And this obviously also has a very positive effect for capacity utilization at Ula. At Valhall, we now start to see the effects of the growth strategy we embarked on a couple of years ago. In the first quarter, 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 end of last year. But we are planning for more growth at Valhall. The Valhall West Flank project are progressing as planned and on the picture, you can see the jacket or substructure of Valhall wellhead platform. This is now completed and scheduled to sail away tomorrow. The topside 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 Valhall field center, the IP drilling is about to be completed. We have now sanctioned a new 7-well program at the Valhall WP platform. And thirdly, we are also working on a project to redevelop the Hod field. In the first quarter, we drilled a combined exploration and appraisal well in Hod, which unfortunately turned out to be dry. However, this new information will be used to optimize the development solution on the field. Overall, I must say I'm extremely pleased by the progress across our operated assets. And things are also moving nicely ahead on the nonoperated 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 hook up, testing, commissioning of the 2 final topsides, and that will be followed by testing and ensuring that all 4 platforms and the field center, as a whole, is functioning as a single unit. Completing the tieback of the pre-drilled 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 NOAKA, 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 Krafla UPP 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 Krafla license, Aker BP has instead proposed a PQ solution, which we believe is the best alternative, not only for the whole area but also for the Krafla 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 NOAKA 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're 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 our exploration program for 2019, and we have this time included spud time estimates for each well. Otherwise, the list is pretty much as before, apart from the fact that the first 3 wells have been completed. And with the Froskelår 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 costs. Roughly 10% to 12% of the OpEx and drilling and well spend respectively. And there is still a lot of waste to be removed, both in our company but also on the Norwegian Continental 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 exChain 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 exChain is that this will become the industry solution also for NCS. 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 logistic department reduces waste is from Ula and Valhall. There's a lot of activity going on as we've already talked about at these 2 installation with both production, project 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 from logistics and on sailing patterns, we've been able to optimize the sailing pattern. The results are better service at a reduced cost and yearly cost improvement only for Valhall and Ula asset is about USD 10 million. 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.Second, smart maintenance has long been touted as one of the most promising abilities for machine learning. And it's one of the promising of opportunities that arise from 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 [ far more ] 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 a new initiative related to the multiphase pump, which are transferring gas/oil from Tambar 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 value of this initiative alone is around USD 50 million over the next 5 years. And with that, I'll give the room to David Tønne, who -- I think, this is your second quarter, actually. David, thank you.

[David Torvik Tønne, Chief Financial Officer]

Thank you. 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 2 changes in accounting principles that has occurred this quarter. First, the new leasing standard became effective from the 1st of 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 costs 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 have also been restated. So if you 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 up 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 an average 8% lower in Q1 than in Q4. And in total, petroleum revenues ended at $858 million, which is a slight decline from Q4. If we then move on to the income statement. We recorded a total income of $836 million in the quarter. And here, you can see that the $858 million from the sale of petroleum has been slightly offset by a reduction in the market value of hedging positions of roughly $26 million. 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 has rebounded. Production costs in the quarter was $200 million. Similarly, as for revenues, this line item has been impacted by the change in accounting principle. If we exclude the adjustment for overlift as disclosed in note 3, the production costs related to produced barrels in the quarter amounted to $191 million, which is a slight increase of $4.4 million versus Q4. The production cost per produced barrel was $13.4. This is a slightly above our average full year guidance but in line with our plan for the first quarter. And the main driver for this is the high maintenance activity at Valhall and Ula 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 Alvheim and Ivar Aasen and cost per barrels ended at $6 and $8.8 respectively. At Skarv 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 up $13 per barrel. Some technical difficulties but I think we're okay. At Ula/Tambar cost per barrel was $56. In addition to the high maintenance activity as already mentioned, the production cost was negatively impacted by a reduction -- reduced productivity from the Tambar wells and the planned shutdown related to the production start on the Ula field. On Valhall, 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 $90 million and the increase of $18 million versus Q4 is mainly related to dry well cost on Gjøkåsen and Hod Deep. This was somewhat offset by lower seismic spend in the quarter. Our cash spend on exploration was $159 million in the quarter. This is in line with our plan and the full year guidance of $500 million, but the drilling program is front end loaded, hence we expect exploration expense to be a bit higher in the first 6 months versus the second half of the year. If we summarize these lines, we get an EBITDA of $539 million in Q1. Depreciation was $183 million 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 million at Ula and Tambar. 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 sub-projects. This had a corresponding negative impact on the fair value estimation. Deducting depreciation and impairment from EBITDA, we get an operating profit of $287 million. Net financial expenses in the quarter were $37 million 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 $249 million and taxes amounted to $239 million. Of these, $129 million was the current tax arising in the quarter and approximately $111 million 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 $106 million and is in line with the guidance we provided at the Q4 presentation. Thus, net profit in the first quarter ended at $10 million. 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-use 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&E increased by $208 million, and we have additions of $360 million where investment at Valhall and Johan Sverdrup made up 75%. And then, we have depreciation of PP&E, which amounted to $160 million.On the other side of the balance sheet, we can see that equity was reduced by $177 million. This is mainly representing the net of dividend and net income for the quarter. Bonds and bank debt increased as we're due on the RBL. And then total lease debt came in as a new class of debt amounting to $369 million. 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 $11.1 billion at the end of the first quarter. The cash flow summarizes most of the items discussed so far. We started Q1 with $45 million in cash. During the quarter, we drew $200 million on the RBL. Cash flow before tax from operations amounted to $696 million. And then tax payment, as mentioned, was $106 million. And then cash flow to investment was $511 million, of which the main contributors were: $364 million in investments in fixed assets, which includes $42 million in capitalized interests, $126 million in exploration, $21 million in decomm and P&A, and then lease payments also amounted to $21 million. 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 $187.5 million. Then, at the end of the quarter, our cash balance was $114 million, up $69 million. The book value of net interest-bearing debt was roughly $2.5 billion. We had $2.85 billion of committed undrawn capacity on our $4 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 the $4 billion 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 announced yesterday, we are now in the process of establishing a new unsecured credit facility of $4 billion, 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 debt and maintain full financial flexibility, the interest cost for the company will be reduced and all lenders to Aker BP will be pari-passu, which should also be positive for our credit quality in the bond market. And 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 and 160,000 barrels per day. Q1 came in a bit above the midpoint, which was in line with our plan. And we maintained our full year guidance between 155,000 and 160,000. 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 Valhall and Ula. 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 Valhall Flank West Field. As mentioned, the full year production guidance is therefore kept as is. We have guided 2019 CapEx at $1.6 billion, assuming a dollar to Norwegian kroner exchange rate of 8.5. Key drivers for this spend level is Valhall 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 $1.6 billion. Exploration spend, as already mentioned, was guided at $500 million, and we keep that guidance as is. Abandonment expenditure for 2019 is guided at $150 million.The spend in Q1 was more or less as expected, $21 million. However, the plans for P&A activities at Valhall 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 it's more optimal from an operational planning perspective. If we end up doing this, some of the spending would then be reclassified from abandonment expenditure to CapEx. However, the overall spend is not expected to be influenced by such an optimization exercise. Production costs per produced barrel came in at $13.4 in Q1. We expected Q1 to be higher, as already mentioned than the -- our yearly average due to the planned maintenance activity at Valhall and Ula. And we still expect the full year average to come in at $12.5. And last, but not least, we paid $187.5 million in dividend in Q1, and we still plan to pay $750 million 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&A.

[Karl Johnny Hersvik, Chief Executive Officer]

Excellent. Thank you, David. Great. So before I conclude, you may have noticed that we have recently announced a couple of changes to our executive management team, so let me spend a couple of minutes just walking you through those. We have appointed Knut Sandvik as our new SVP on projects. Knut comes from Aker Solutions where he's been a member of the executive team for a long time and most recently, had a responsibility for greenfield projects. I believe Knut 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 of project execution capabilities. And then Knut is, of course, replacing Olav Henriksen who will move on to Aker Energy. And I wish to use this opportunity to thank Olav for his outstanding contribution to Aker BP over the years [Audio Gap] As the 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. Jorunn is -- she -- Marit is replacing Jorunn Kvåle who is joining the Valhall management team, and Jorunn 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 Valhall area. And then also 1 year ago, we announced the appointment of Kjetel Digre as our new SVP of Operations. Seems like a long time ago, but time flies. And we now look forward to welcome him on board, next week, on the 1st of May. And Kjetel is replacing Svein Jacob Liknes who has done a great job as acting SVP of Operations in the interim period. I would also like to extend my gratitude to Svein Jacob 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, employment 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 production -- on projects and have a large scope of future projects to deal with. On the improvement, I think we've demonstrated our 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 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, Kjetil will open up with questions from this room, first and then move on to the conference call. So I think [ Tura ] has a mic. So if anybody has a question, raise your arm or shout out. Do something to get his attention and you'll get the mic, and let's get the ball rolling. Everything seems to be clear, I think. That was fantastic. SoKjetil, are there any questions from the operator?

[Operator]

[Operator Instructions] We'll take our first question from the line of Daniel Won from JPMorgan.

[Jung Won, Analyst]

Obviously, you have refinanced the RBL [indiscernible] yesterday which I guess makes some of the growth you've seen, it's a bit less [ abdomen sensitive but ] the RBL, but also something [ less. ] So withdrawing the $1.1 billion at the end of the first quarter, do you think you will look to maybe refinance some of those drawings in the senior unsecured bond market in the sort of coming 12 months or so? I know it varies throughout the year, but it seems like there's sort of $500 million drawn on this facility. So I'd just like to hear your thoughts on the back of this financing.

[Karl Johnny Hersvik, Chief Executive Officer]

So there seems to be some noise on the line, so it was a bit difficult to interpret the question. I think I've heard the question around if it's likely for us to go into the bond market in the near future. Was that the question?

[Jung Won, Analyst]

Well, I think the rationale is you've obviously just refinanced this new facility, this $1.1 billion of drawings at the end of the first quarter. There is always $500 million 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 [ maturity ] package?

[Karl Johnny Hersvik, Chief Executive Officer]

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 $2 billion liquidity, what we call, backstop, and the other part is a $2 billion working capital facility. And over time, we definitely see that as a bridge to bond facility where we will move into the bond market.

[Operator]

We'll take our next question from the line of Alwyn Thomas from Exane BNP.

[Alwyn Thomas, Analyst of Oil and Gas]

Just wanted to clarify a few points. 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 what 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 it for me.

[Karl Johnny Hersvik, Chief Executive Officer]

Okay. So maybe I can start out. In the next quarter, there will be turnarounds on Valhall and Ula, both impacted by the turnarounds also at Ekofisk 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, and 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 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 RCF, David?

[David Torvik Tønne, Chief Financial Officer]

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 happy about the ongoing work and the support from our banking group.

[Alwyn Thomas, Analyst of Oil and Gas]

Okay. Can I just follow-up quickly, Karl, on CapEx timing. And given the delays to NOAKA concept selection, is it possible reading there that it could be some, I guess, CapEx shifted into future years 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?

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you, Alwyn. So when it comes to the CapEx program and the effects of that NOAKA discussion, I think the main discussion that we're having right now is how to utilize P&A capability or rig capacity allocated to P&A in 2018. And recent results from the production drilling in Alvheim -- no, from Valhall has at least indicated that there might be possibilities of reallocating rig hours from the removal of -- or the Abex or P&A activity into more value-creative activities in drilling of new wells. If we do decide that, that is a good use of the rig, then obviously, CapEx will be reallocated also from Abex but that won't fill up the entire year, so you may also see some of the CapEx that should have been consumed by the NOAKA project, also being allocated to production drilling. From an Aker BP perspective, this is in short horizon 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 -- remind me again, Alwyn.

[Alwyn Thomas, Analyst of Oil and Gas]

Valhall West Flank.

[Karl Johnny Hersvik, Chief Executive Officer]

Yes. Valhall West Flank. 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 you add contingencies is 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 estimate. And I think we're already predicted that when it comes to these most likely cost estimates, so we're a bit on the low side. But that's also reflected in the current prognosis that has let us 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 alliance model.

[Operator]

We'll take our next question from Anders Holte from Kepler.

[Anders Torgrim Holte, Equity Research Analyst]

And congrats on a decent quarter, at least on cash flow. Just a few questions for me this morning. I was wondering if you could elaborate a little bit more on the changes in working capital for the quarter since it standouts 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, wonder if you could, at least give some color on what you see as a potential development there? Are you still -- are you seeing that this is a stand-alone? Or is this more of a tying back to all-in projects for you as it now stands?

[David Torvik Tønne, Chief Financial Officer]

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 sort of an underlying reduction in working capital.

[Karl Johnny Hersvik, Chief Executive Officer]

And when it comes to the frog area, we're currently assessing basically 3 different possibilities. And let me just remind you how it came about this area. So we drilled the frog well first, which was kind of the opening of the area where we discovered [ both dikes ] and injectites and so-called [indiscernible] 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 now are currently drilling the frog test producer with information gathering pilots also into the frog northeast or frog leg northeast. So that means that a lot of these discussions will be impacted by the results from the frog 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 Bøyla infrastructure and therefore, have basically fill up the capacity on Bøyla going up to Alvheim. The second one is to install a new manifold and a new set of subsea templates and tie that directly back to the Alvheim field. Both plans will of course, have as a pro that they are very quick to do. They will give rapid cash flow and low CapEx solutions. But they won't necessarily maximize peak production from the frog and the frog leg area. And then finally, of course, it's some sort of stand-alone type facility with or without processing capacity. I think the 2 information elements that will impact the selection of development solution. The first is the result from the frog test 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.

[Anders Torgrim Holte, Equity Research Analyst]

And just to say, a quick follow-up there. How much of whatever you see now in the frog area is already reflected in your guidance of 450,000 barrels per day by 2025?

[Karl Johnny Hersvik, Chief Executive Officer]

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 developments solutions.

[Operator]

[Operator Instructions] We'll take our next question from Michael Alsford from Citi.

[Michael J Alsford, Director]

I've got 2, please. So firstly, on Johan Sverdrup,I know you've obviously reiterated the base case of 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 this stretch target being reached i.e. production earlier in 4Q? And what will be the sort of the layer of the plan to deliver that earlier first oil? And then just secondly on NOAKA. Yes, I know you make obviously, a compelling case for your -- to your concept in terms of higher recovery and lower breakeven but obviously, the significant delay we have seen clearly impacts economics in terms of the timing of first oil and the ultimate NPV of the projects. So I'm just wondering how you think about that in the context of obviously the ongoing discussions with the other partner.

[Karl Johnny Hersvik, Chief Executive Officer]

Okay. So thanks, Michael. So let's start with Johan Sverdrup. There was -- first of all, I think it's fair to say that even with projects going very well and we're really, really happy about the performance of Equinor at -- as operator of this project -- there's still a quite a lot of work to be done in terms of testing, commissioning and other activities. And in addition, tie back of the 8 producers back to premium producers back to the production infrastructure. There has been some discussion about an earlier startup, and we continue to see progress going pretty much into our direction where that may or maybe a possibility. However, I think it's fair to also say that from an Aker BP perspective, the key value driver is to ensure that once we execute the startup, we were 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 startup 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'll probably more -- will be more interested in seeing a rapid ramp up followed -- following a high quality start up than 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 NOAKA and, of course, we would be very interested in moving ahead as swiftly as possible. And have been in that 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 NPV on a project are not directly [ driven ] as the resource utilization currently on NOAKA is relatively low. And again, this is an effect of how we're organizing the project in Aker BP, utilizing this alliance model, which allow us to scale up and scale down the engineering resources and other resources that are applicable for the project and thereby, also, control the burn rate and the negative cost effects of such delays that we are experiencing at the moment. So that 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 BP projects ongoing in the alliance, so there's lots of engineering works to allocate these resources to. So at the moment, we are not feeling that the timing is directly impacting the attractiveness of the PQ.

[Kjetil Bakken, Vice President of Investor Relations]

So operator, we have time for one more question.

[Operator]

We'll take our last question from Yoann Charenton from Societe Generale.

[Yoann Charenton, Equity Analyst]

Yoann Charenton from Societe Generale. I will ask 2 question on the financials. Would you be able to explain how the refinancing might impact your well thinking in terms of managing the balance sheet in relation to credit rating? In other words, how relevant is your credit rating on the back of this change in the structure of your funding pool?

[David Torvik Tønne, Chief Financial Officer]

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.

[Yoann Charenton, Equity Analyst]

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 [ as ] potentially moves during the quarter?

[David Torvik Tønne, Chief Financial Officer]

I would actually not be able to answer that such in detail here based on my head. But I recommend you to call Kjetil Bakken in Investor Relations, and he can give you a more detailed answer on that one, Yoann. I apologize.

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you. And with that, I think we close the Q1 presentation of 2019. And thank you so much and an excellent weekend to all of you when you get [ back for. ]

[Operator]

That concludes today's conference call. Thank you, everyone, for your participation. You may now disconnect.