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. Thirdly, we continued expanding our resource base, with exploration success at Alvheim and accelerated infill development, and recently, a 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 quarter and first quarter 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 first quarter 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 all our assets, shown here on the right-hand side of this page. We're currently running stable and high-quality operations on all assets. And particularly pleased with the almost perfect performance of the Ivar Aasen asset and the great improvements at Ula and Valhall. 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. With that, let's go through the assets, and as usual, I'll start with Alvheim. Alvheim is a reliable top performer which has 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 two quarters after the Chameleon infill well was put on stream in the summer of 2018. Our mission on Alvheim continued 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 Frosk Nord 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 as a test producer in Frosk. These targets include the Frosk Nordøst. In the third quarter, we also plan to drill an exploration well in the so-called Pad Fold project. 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 have also drilled a sidetrack well at Ula, which now are in the completion phase at this well. With that, I'm moving over to Ivar Aasen, which has also been a top performer this quarter.
The production efficiency in the quarter was a stunning 98%. The 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 high regularity over quite some time. We have also been able to improve the water injection at the Ivar Aasen, which gives us now a high water 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, means that 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 better shape to withstand periods without pressure support. 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 re-established 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 very successfully using a new cost-saving in-situ repair method. 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 Ærfugl project is progressing according to plan.
The Ærfugl project is probably one of the most successful project in Norway right now, and probably also the most under-communicated one. 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 two 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 one of the three planned wells in our field phase II. In reality, this is the alliance model in operation. This demonstrates that the alliance model that we established is working and giving highly efficient project execution methods.
The improvements at the Ærfugl project, including the acceleration and the optimization of well locations, have also pushed down break-even price in current terms from roughly $18.50 down to $15 about. Remember, this is about 70% gas and 30% oil. If you look at it in gas terms, we're talking about roughly $1.50 per million BTU in gas price break even. These are really stunning numbers. A 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 all alliance partners. At Ula, the current priority is to establish stable and robust operations. We're focusing on three 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 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 Titan 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 are now preparing the platform for drilling with a highly efficient jackup rig of the kind that we are 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 Ula.
This work has been going on for several months and will be completed shortly. By mid-year, we will bring in the Maersk Intrepid rig and start a one-year drilling campaign, which will help stabilize production in Ula and make Ula ready for the next phase. While we're at Ula, it's also worth mentioning that the Oda satellite field was brought in 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 Q1, production reached its highest level since we took over the field in 2016, basically driven by two factors. The first one is to increase production efficiency. 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. Second, we also see the full impact of the new wells that were added towards the end of last year. We are planning for more growth at Valhall. The Valhall Flank West 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 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 campaign is about to be completed. We have now sanctioned a new seven-well program at the Valhall WP platform. 3rdly, we are also working on a project to redevelop the Hod field.
In Q1, 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. Things are also moving nicely ahead on non-operating side. By that, I am obviously referring to Johan Sverdrup. On this spectacular picture, you can see the living quarters being lifted in place using a single-lift technique.
On the agenda now is hookup, testing, commissioning of the two final topsides, that will be followed by testing and ensuring that all four platforms and the field center as a whole is functioning as a single unit. Completing the tieback of the pre-drilled eight wells or production wells on the drilling platform will also come as a separate activity in addition to this commissioning activity. 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 the 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 the PQ solution, which we believe is the best alternative not only for the whole area, but also for the Krafla license as such. 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.
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 three wells have been completed. With the Frosk discovery, this has clearly been a very good start to a very busy exploration year. We look forward to the continuation. Let me turn to one of my other favorite topics, improvements. Logistics and operational support remains a significant part of our cost. Roughly 10%-12% of the OpEx and drilling and well spend respectively.
There's 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 of transported volumes, and difficulties in right sizing 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 XChain 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 XChain 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. 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 already talked about at these two installations. 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. The yearly cost improvement only for Valhall and Ula asset is about $10 million. This is a wonderful example of how soft skills can drive hard results. We will continue this improvement journey at the other Aker BP-operated field centers. Second, smart maintenance has long been toted as one of the most promising abilities for machine learning. It's one of the promising opportunities that rise 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.
We have, on previous occasions, talked about the 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 multi-phase pump which are transferring gas and oil from Tumba to Ula. This pump has created repeated downtime due to unexpected technical failures. 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 $50 million over the next five years. With that, I'll give the room to David Tønne, who I think this is your second quarter, actually. David?
Thank you.
Enjoy.
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. Before I go into the details, it's worthwhile mentioning the two 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 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 reflect the cost of sold volumes. In note three, we have disclosed the production cost based on produced volumes and the adjustment separately. Comparable figures has also been restated. 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 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. In total, petroleum revenues ended at $858, which is a slight decline from Q4. If we 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. These gains have now been reversed in Q1 when the oil price have rebounded.
Production cost 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 three, the production cost 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. 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. If we look across our five hubs, OpEx was slightly down both for Alvheim and Ivar Aasen, and cost per barrel ended at six 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 at $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 reduced productivity from the Tambar wells and the planned shutdown related to the production start on the Ula field. On Valhall, absolute cost was stable versus Q4. 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. The increase of $18 million versus Q4 is mainly related to dry well cost on Jotun and Hod deep.
This is 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. The drilling program is front-end loaded. Hence, we expect exploration spend to be a bit higher in the first six 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. The latest update included a shift in timeline and also a slight cost increase on 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. Taxes amounted to $239 million. Of this, $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%. The relative high tax rate is mainly driven by two 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 sheets, in general, it has been fairly stable this quarter. 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.
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 NOK 208 million, and we had additions of NOK 360 million, where investment at Valhall and Johan Sverdrup made up 75%. We have depreciation of PP&E, which amounted to NOK 160 million. On the other side of the balance sheet, we can see that equity was reduced by NOK 177 million. 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. Total lease debt came in as a new class of debt amounting to NOK 369 million.
The difference between the lease debt on one side and the right of use asset on the other is related to the provision for fair value of contracts as specified in Notes 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 NOK 45 million in cash. During the quarter, we drew NOK 200 million on the RBL. Cash flow before tax from operations amounted to NOK 696 million. Tax payment, as mentioned, was NOK 106 million.
Cash flow to investment was NOK 511 million, of which the main contributors were NOK 364 million in investments in fixed assets, which includes NOK 42 million in capitalized interest, NOK 126 million in exploration, NOK 21 million in decom and P&A. Lease payment also amounted to NOK 21 million. 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 NOK 187.5 million. At the end of the quarter, our cash balance was NOK 114 million, up NOK 69 million. The book value of net interest-bearing debt was roughly NOK 2.5 billion. We had NOK 2.85 billion of committed undrawn capacity on our $4 billion bank facility. Excluding the effects of IFRS 16 leases, our leverage ratio, net debt to EBITDA, was roughly 0.7 at the end of the quarter.
While talking on financing, Aker BP is continuously working to optimize its capital structure. 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. 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 NOK 4 billion, which likely will be completed in Q2. With this new unsecured facility, we will achieve three main objectives. We extend the maturity of our bank debt and maintain full financial flexibility. The interest cost for the company will be reduced. All lenders to Aker BP will be pari passu , 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 and 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 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.
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. 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 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 Ula. We still expect the full-year average to come in at $12.5.
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.
Excellent. Thank you, David. Great. Before I conclude, you may have noticed that we have recently announced a couple of changes to our executive management team. Let me spend a couple of minutes just walking you through those. We have appointed Knut Sandvik as our new SVP of 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 our project execution capabilities. Knut is, of course, replacing Olav Henriksen, who will move on to Aker Energy. I wish to use this opportunity to thank Olav for his outstanding contribution to Aker BP over the years.
Marit as a new head of HSE. She comes from the position as Vice President within our drilling and well department, and has been with the company since 2017. 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. Also one year ago, we announced the appointment of Kjetil Digre as our new SVP of Operations, which seems like a long time ago, but time flies. We now look forward to welcoming on board next week on the 1st of May. Kjetil is replacing Svein Jakob 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 Jakob for his strong contribution, dedication, energy, and humor in this period. Finally, 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 an 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. 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. With that, I thank you. We close this part of the presentation, and we'll open up for questions. If memory serves me correctly, Kjetil, we'll open up with questions from this room first, and then move on to the conference call.
I think Thora has a mic, 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. Kjetil, are there any questions from the operator?
Thank you. If you would like to ask a question, please press star one on your telephone keypad at this time. Once again, press star one to ask a question. We will take our first question from the line of Daniel Brown from JP Morgan. Please go ahead.
Hello there. Hi, good morning. Obviously, you financed the RBL into the second quarter. Looking yesterday, which shows the growth we've seen, it's a bit less admin intensive versus the RBL, and also the funding effects. With drawings of NOK 1.1 billion at the end of the first quarter, do you think you will look to maybe refinance some of those drawings senior with bond market in the coming 12 months or so? I know it varies throughout the year, but it seems like there's sort of NOK 500 million drawn on this facility. Just like to hear your thoughts on the back of this finance. Thank you.
There seems to be some noise on the line, so it was a bit difficult to interpret the question. 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 into this new facility. There's NOK 1.1 billion of drawings at the end of the first quarter. There's always NOK 500 million drawn throughout the course of the year. That seems to be more permanent borrowing rather than something you would use a sort of RCF for typically. Yeah, 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 security package?
Yeah. The short answer to that is that the facility that we're putting in place is basically split in two. One part is a NOK 2 billion liquidity, what we call a backstop, and the other part is a NOK 2 billion working capital facility. Over time, we definitely see that as a bridge to bond facility where we would 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. Appreciate some of the color you gave on the coming quarters. Could I just ask for a little bit more detail on the reasons for the production coming lower in 2Q on maintenance? 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. Just to follow up on the new unsecured RCF, are you expecting interest charges to be less as a result, despite it being unsecured? That'll do for me. Thanks.
In the next quarter, there will be turnarounds on Valhall and Ula, both impacted by the turnarounds also on Ekofisk, which is the export facility for these installations. We have currently estimated that to be roughly 30,000 barrels lower than an impact, it will be 30,000 barrels lower than in Q1. 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. 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. The figures I just gave should be looked upon as very preliminary. In terms of CapEx phasing, there are basically two things that are impacting the in-quarter results.
The first one is a rollover from Q4 2018, and the second is the way the activities in Q1 2019 are being invoiced. 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. Related to the RCF, David?
Yes.
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. The RCF, as mentioned, is an unsecured facility, whereas the RBL was a secured facility. Although there's a difference there, we're still able to reduce the interest expense. That's obviously something that we're very happy about, and very happy about the ongoing work and the support from our banking group.
Okay, thanks. Could I just follow up quickly, Karl, on CapEx timing? Given the delays to NOAKA concept selection, is there possible room there that there could be some CapEx shifted into future years related to that, or would you expect to use it elsewhere? I guess whether there's any cost contingency left in Valhall Flank West as well, given the good progress on the project.
Well, thank you, Alwyn. When it comes to the CapEx program and the effect 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. 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 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 a rig, obviously CapEx will be reallocated also from ABEX, but that won't fill up the entire year. 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 the short horizon obviously positive, as it will drive higher cash flows in the quarters to come. I think the last part of the question was.
Valhall.
Remind me again, Alwyn. Yeah, Valhall Flank West. Okay. Remember that this is an alliance project, 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 contingency is not really the way we're working anymore. A lot of this is now basically run up against the so-called most likely cost estimate. 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. This usual discussion where you see a lot of release of contingency in project as you lead up to production is not really an applicable discussion when you talk about Alliance Valhall.
Okay, thanks very much.
We'll take our next question from Anders Holte from Kepler. Please go ahead.
Yeah. Good morning, guys. Thanks for taking my questions. Congrats on a decent quarter, at least on cash flow. Just a few questions from me this morning. Just wondering if you could elaborate a little bit more on the changes in working capital for the quarter. It seems to stand out a little bit. Also, if you could indulge me in the Frosk area. Now, based on the two 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 here. Are you thinking that this is a standalone, or is this more of a tie in back to the Alvheim project for you as it now stands? Thank you.
I can start with the working capital. The change in working capital is mainly related to change in accounts receivables, which is due to the lifting schedule. It's not a sort of underlying reduction in working capital.
When it comes to the Frosk area, we're currently assessing basically three different possibilities. Let me just remind you how we came about this area. We drilled the Frosk well first, which was the kind of the opening of the area, where we discovered both dikes and injectites, and so-called braccia, which is the interface between the sands and the chain that the sands are injected in. Following that, we made further data evaluations and subsequently drilled the Froskelår, and are now currently drilling the Frosk test producer with information gathering pilots also into the Froskelår Nordøst. That means that a lot of these discussions will be impacted by the results from the Frosk test producer. To give you some color, we have basically assessed three different options.
The first one is that this is a tieback utilizing the Bøyla infrastructure, 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 of them will, of course, have as a pro that they're 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 Frosk and the Froskelår area. Then finally, of course, it's some sort of standalone type of facility with or without processing capacity. I think there are two information elements that will impact the selection of development solution.
The first is the result from the Frosk test producer, and the second is the drilling of the Rumpetroll prospect towards the, I think it's Q3 this year. At that point in time, we'll be able to give more light on which concept we are likely to choose.
Just as a quick follow-up there, how much of whatever you see now in the Frosk area is already reflected in your guidance of 450,000 barrels per day by 2025?
Currently, none of this was included in the capital market presentation back in January. We will update those figures when we have an idea of the field development solution.
Okay. Thank you.
If you find that your question has been answered, you may remove yourself from the queue by pressing star two. We will take our next question from Michael Alsford from Citi. Please go ahead.
Good morning. Thanks for taking my questions. I have got two, please. Firstly, on Johan Sverdrup, I know you have 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. 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? What would be the layout of the plan to deliver that to earlier first oil? Just secondly, on the NOAKA, I know you make obviously a compelling case for your concept in terms of higher recovery and lower break-even. Obviously the significant delay we have seen clearly impacts economics in terms of the timing of first oil and the ultimate NPV of the project.
I'm just wondering how you think about that in the context of obviously your ongoing discussions with the other partner. Thank you.
Thanks, Michael. Let's start with the Johan Sverdrup. First of all, I think it's fair to say that even if the projects are going very well, and we're really, really happy about the performance of Equinor as the operator of this project, there's still quite a lot of work to be done in terms of testing, commissioning, and other activities. In addition, tie back all the eight producers back to pre-drilled 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 be 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 start-up, we're actually starting up this only once, and have a really high-quality operation.
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. Then of course, there is a discussion around starting up is one thing and ramping up is another. What we're probably more interested in seeing a rapid ramp-up following a high-quality start-up, than pushing for an early start-up and a subsequent slower ramp-up. 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.
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, four or five months at least, that we were able to start up. However, the NPV of the project are not directly driven as the resource utilization currently on NOAKA is relatively low. Again, this is an effect of how we're organizing the project in Aker BP, utilizing these alliance models, which allow us to scale up and scale down the engineering resources and other resources that are applicable per project, and thereby also control the burn rate and the negative cost effects of such delays that we are experiencing at the moment. Basically what we're doing here, Michael, is to reallocate these resources to other projects ongoing in the Aker BP portfolio.
Just to give you an idea, we currently have about 33 BG projects ongoing in the alliance, there's lots of engineering work to allocate these resources to. At the moment, we are not feeling that the timing is directly impacting the attractiveness of the PQ.
Answered. Thanks very much.
Operator, we have time for one more question.
Thank you, sir. We'll take our last question from Yoann Chaigneau from Société Générale. Your line is open. Please go ahead.
Yes, good morning. Yoann Chaigneau from Société Générale. I will ask two question on the financials. Will you be able to explain how the refinancing might impact your way of 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?
Yes. Obviously it's not Aker BP who sets the credit rating of the company. I think that moving into this corporate structure clearly indicates the strong support that the banking group has for our credit. That's also a strong signal, I guess, to the rating agencies.
Okay, 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 Kjetil Bakken in investor relations and he can give you a more detailed answer on that, Yoann. I apologize.
Okay. Thank you.
Thank you. With that, I think we close the Q1 presentation of 2019. 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.