Second quarter and first half presentation of 2019 here at Fornebuporten. Also a warm welcome to all of those who follow us online or on our conference call. Let me warm up by giving you a quick overview over the highlights of this exciting second quarter. Production volumes were low, mainly due to maintenance activities and mostly in line with our previously communicated plans. All our development projects are continuing on track, and we look forward to the startup of production from both Johan Sverdrup and the Valhall West Flank later this year. We also continue to deliver strong exploration performance, and today we are announcing a new significant discovery in the NOAKA area. I will come back to all of this in detail later in the presentation, but before we dive into the details, I would like to share some reflections on the activity level in Aker BP.
As I'm used to saying on these quarterly presentation, it's been yet another exciting quarter at Aker BP. It's really amazing to see the massive amount of work going on in the organization, and I'd like to take a little bit of an opportunity to basically walk you through the activity levels that we have. Today, we have six simultaneous ongoing drilling operations in Aker BP. We are planning to drill 17 exploration wells in 2019, two more than previously announced, due to better performance on drilling than we anticipated at the beginning of the year. There are four new greenfield projects that are currently in the installation phase and more than 10 that are in the planning phase.
On the production side, we have currently executed in this quarter two month-long turnarounds where more than 55,000 hours of offshore maintenance work supported by roughly 20,000 hours of planning work in the quarter. In the decommissioning, we have executed two projects this quarter, the removal of QP, which I'll get back to, and also the decommissioning and P&A of the Jette wells. Now I'd like to give the word to our Head of Exploration, Evy Glørstad-Clark, who talk about our recent exploration successes. Evy, the floor is yours.
Thank you, Karl. I'm very pleased to present the exploration success that we've had in 2019. I presented the exploration program in the capital market day earlier this year, and now I'm giving you an update. Karl has given you a little bit of a taste of what's coming now. We've drilled nine wells so far, and we have three discoveries. That is a high success rate in exploration. We have also industry-leading drilling performance, and that's very important as well for us to drill efficiently and also more inexpensive so we can drill more wells. When we're looking at the rig that's drilled the last few exploration wells for us, the DSS, we actually are demonstrating very high drilling performance and placing in a Rushmore Reviews statistics at the first place, third place, and fourth place drilling performance. That's very good.
We have also added two more exploration wells to the exploration program. I presented 16 wells earlier this year, and now we're going to drill 17 wells. We have added the Nipa well. I did not change this. I'm sorry about that. The Nipa well in license PL 986 in the NOAKA area, and we're adding the Nidhøgg well, license PL 1008 in the Skarv area in the Norwegian Sea. They all represent wells that are important to us to help building infrastructure-led exploration in the Skarv area. For the Nipa well, it's important for our NOAKA hopefully future development. I'm also here today to present the Liatårnet discovery. We sent out a press release this morning. This is a significant oil discovery both for Aker BP and on the Norwegian Shelf for this year.
It has a volume in place of about 500 million bbl of oil equivalent-700 million bbl of oil equivalent. We still need to work a little bit further to figure out how much of that oil we can get out of the ground. We need to look into recovery factors, and we need to look at drainage strategies. So far we have press released a recoverable volume preliminary estimated to 80 million bbl-200 million bbl. It is very significant. It's located in the PL 442 license, where Aker BP is the operator with 90%. It's adjacent to the Frigg Delta discovery, it will add significant value and robustness to an area development. This well is a well that we haven't presented externally before. On the capital market day, it was actually just listed as a NOAKA well. We haven't gone out with any pre-drill estimates.
We're now presenting this for the first time. It is a part of the long-term strategy in the area to really unlock the potential in the NOAKA area. It does not have a standalone potential and will also require that we get an area development. It also shows how exciting it still is to do exploration on the Norwegian Continental Shelf. This is for us, a success story today. I also spent some time externally just presenting the Alvheim area. I talked about how we've done a lot of data acquisition, and we really tried to unlock the injectite play in the Alvheim area. In the first quarter, we presented the Froskelår discovery, which is also a significant discovery this year. It has an estimate of 60 million bbl of oil equivalent-130 million bbl of oil equivalent discovered.
In the second quarter, we followed up with the Froskelår North East well, which is a minor discovery. It was also one of the appraiser wells linked to the whole Frosk test producer drilling campaign. We've done a lot of drilling activity in this area. We haven't gotten any of the results yet from the Frosk test production. It's all a part of evaluating this injectite play and trying to figure out how much that play can produce. We can also see the Gekko appraisal. That was one of the discoveries from last year. We're currently drilling the Rumpetroll well, which is ongoing operations. We're not sharing any of that information still. A lot of focus in the Alvheim area, spending quite a bit of exploration money in that area and very successful so far the last year and a half.
As I also mentioned, we have done really good drilling performance. What this DSS rig has done for us, it's the world's first dual drilling operations done. That's very exciting. It's drilling faster and faster, and we now completed dual drilling on three wells, the JK prospect, the Hornet, and Freke and Garm. All the three prospects were unfortunately dry, just showing what the dual drilling can do, it's very exciting. It has the potential of time savings and also significant cost savings for us when we move forward. The Deepsea Stavanger is a rig with world-class capabilities. It has two top drives, it has two circulating systems, and it has two drill crews. While you're drilling the top hole, the primary can still run the whole BOP operation. That's why this becomes very efficient.
Just looking at the exploration program for 2019, where we have added two new wells. You can see that we have the Nidhøgg well in here, which was the Skarv ILX well, and then we have the Nipa well here, which is the NOAKA well. Other than that, we have the same list as we presented externally before, now also listed with the discoveries. We have two ongoing operations. We have no press release or ongoing drillings though, that's Klaff and Rumpetroll. With that, I'm giving back the word to Karl.
Thank you, Evy. It's great to see that the exploration is really thriving in Aker BP. As I said on the capital market day, we are actually the second-biggest license holder on the Norwegian Continental Shelf. That strategy is now paying off. That's great to see. Now moving into the operational update, and starting with a production overview. As previously said, the production was 127,000 bbl in the first quarter, representing a decrease of roughly 31,000 bpd compared to the previous quarter. This was more or less in line with our plans and also previously communicated estimates. The main driver was planned maintenance on Valhall and Ula, which each carried out a month-long turnaround. That's been planned for one and a half year.
That also of course reflects the low production efficiency as these month-long turnarounds are included in the production efficiency numbers on Valhall and Ula. It also be worth mentioning the very strong production efficiency number for Skarv which is the star of this quarter, where the uptime was an impressive 98%. It also performed very well, was unfortunately impacted by reduced power supply from Edvard Grieg. I will now go on, as I usually do, to share the highlights of each of the hubs, and I will start with Alvheim. As always, there's been a high activity on Alvheim in this quarter. Evy has taken you through the exciting exploration activities in the area, and there are also several wells that are drilled and completed. The Volund sidetrack well was drilled and completed within 23 days, 12 days ahead of plan. Quite ambitious plan, I must say.
Again, kudos to the drilling department. It's already been put on stream. We have completed drilling of the Frosk test producer. The test producer is soon to come on production during the third quarter following subsea installation processes. The test producer will contribute with important results of the Frosk information, supporting later the drainage strategy in the area. The subsea installation campaign of Skogul is successfully completed in June, and drilling operations are scheduled to start in the third quarter. The reduction in production in this quarter was driven by natural decline and shut-in of a few wells due to damage on the riser support system. The damage was discovered during the annual RV inspection of the riser support system and anchoring systems.
Pending repairs, we have shut in production from a few wells at Aldan and Vilje, have been able to mitigate most of the production effect by increasing outputs from other wells in the area. Moving on to an asset with even more activity in the quarter. At Valhall, we have executed a month-long turnaround in June, executing about 34,000 offshore hours supported by 10,000 onshore hours. Of course, production was affected negatively by this. During the shutdown period, we have also removed the QP topside, which is one of the old topsides, I'll come back to that shortly. First, the most exciting news on Valhall during the quarter, we have successfully installed the Valhall West Tank topsides, only 14 months after first steel was cut at Verdal.
This is probably the most complete offshore platform that has gone into the sea on the Norwegian continental shelf. Ahead of schedule, under budget, with no serious injuries. There are no carryover work, testing and commissioning was 93% complete on installation, meaning only the systems that require live hardware gardens were yet to be tested and completed. The Maersk Invincible rig is now in place, will drill wells and function as an accommodation rig for the remainder of the hookup and commissioning work. Start-up is planned in the fourth quarter of 2019. The safe and efficient removal operations at Valhall is an important milestone, both for the Valhall asset and for Aker BP. The QP topside is the first of the three original structures that will be removed from the field center.
The single lift operation using Pioneering Spirit took two hours to complete, following about two years of engineering, planning, pre-lift operations. I'd like to extend a big thank you to the entire decommissioning team. It's a truly impressive feat. We have also plugged wells at the Oda field and successfully recovered the Christmas trees. We will consider using these trees in future projects as they are in really good condition. At Ivar Aasen, both production and production efficiency was down in the second quarter, mainly related to turbine challenges at Edvard Grieg, which led to approximately one week of no production and no water injection. Apart from this, it's been the usual smooth operations. Maersk Interceptor is now drilling at the field again, one well is successfully started up in June.
This well was completed with Fishbone technology, which is an enhancement technology for reservoir performance, and the performance so far has been really excellent. This is yet another example of aggressive technology deployment by Aker BP. A second well is currently being drilled and should be ready for start production by the end of third quarter. Moving on to Skarv. At Skarv, production was steady and production efficiency was outstanding at 98% on average for the quarter. We have increased gas injection and thus accelerated oil production in the quarter, and this is why the total production is not up as an effect of the increased production efficiency. This is a part of our revised drainage strategy. The Ærfugl project is progressing according to plan, and offshore modification work is ongoing. The picture shows the first Ærfugl SBS flow base being loaded out from the yard in May.
The new generation of our vertical Christmas trees is close to completed and subsea installation and drilling will start in the second half of this year. Phase two of the project is also progressing as planned, and final investment decision is planned by the end of this year. At Ula, production was affected by one-month maintenance shutdown. This was in part mitigated by ramp-up of production from Oda, which is a tie-back to the Ula field. Following the removal of the Ula drilling derrick, the Maersk Integrator is now located at the Ula B platform and drilling operations will commence shortly as we're now out of the turnaround window. We're really looking forward to commencing drilling at Ula again. At Johan Sverdrup, we are pleased to see the continued progress of the project, and we are looking forward to the production start.
In the second quarter, the main activities have included offshore hookup, commissioning, and completion of the four platforms, as well as tieback operations for the pre-drilled production wells. During the second quarter, the partnership also got the government approval for the Johan Sverdrup phase two, which will increase the field's production capacity from 440,000 BOE per day to 660,000 BOE per day when it's completed in 2022. Moving on from the giant Johan Sverdrup project. Over to another project that is now the largest project remaining on the Norwegian continental shelf, namely the NOAKA project. Following the Liatårnet discovery, the total recoverable resources in the area are now in the order of 700 million BOE. As we mentioned, we're also planning to drill another exploration well shortly on the Nipa prospect.
The resources in the NOAKA area are significant, but they are spread across many accumulations and many various hydrocarbon types, and the area currently lacks infrastructure. Aker BP's answer to these challenges is to develop the entire area with a so-called PQ concept, consisting of a central processing hub roughly in the middle of the area. The objective is to maximize resource utilization and value creation. Our proposed solution also provides sufficient capacity to tie in additional discoveries in the future. As should be well-known by now, discussions are currently ongoing between the partners on how to develop the area. With that, I'll leave the floor to David and his walkthrough of the financial results. David?
Thank you, Karl. 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 do that, let me start with the big picture. In the second quarter, as Karl has already mentioned, we produced 127,300 bpd . Similarly to the last quarter, we sold more volumes than we produced, and the total sold volumes ended at 140,700 bbl. Liquid prices increased throughout the quarter, but this was offset by a further reduction in gas prices, and the realized average hydrocarbon price ended at $60.60 per BOE, which is 3% higher than in the first quarter. In total, petroleum revenues was $780 million, which is approximately 9% down from the first quarter.
If we move on to the income statement, adjusting petroleum revenues for other income, we get a total income of $785 million. Production costs in the quarter were $198 million. Remember, this line item is impacted by the change in accounting principle from the entitlement method to the sales method, and this now refers to the cost of sold volumes. If we exclude the adjustment for overlift, as disclosed in note number three, the production cost related to the produced barrels amounted to $178 million, which is a decrease of $13 million from the first quarter. This change is mainly driven by the reduced production due to the turnarounds at Valhall and Ula, which Karl has diligently talked about. At Alvheim, Ivar Aasen, and Skarv, production cost per barrel were stable in the quarter with the average cost across the fields at $8.10.
This is exactly the same as in the first quarter. At Valhall and Ula, the reduction in production is relatively higher than the reduction in costs due to the maintenance conducted during the turnarounds. The cost per produced barrel this quarter was therefore, as expected, relatively high for those fields. This drive the average cost for the portfolio up to $15.40. Exploration expenses amounted to $60 million in the second quarter. Roughly $29 million is related to the dry costs on JK, Freke-Garm, and Hornet. In addition, we spent roughly $30 million on seismic, G&G, and field evaluation combined. As planned, the exploration activity was high this quarter, and the cash spend ended at $119 million. If we summarize the items discussed so far, this gives us an EBITDA of $522 million. Depreciation in the quarter was $168 million, or $14.50 per barrel.
The reduction from Q1 is driven by the lower production volumes, while the increase per barrel is driven mainly by the change in relative share of production from the various fields. Deducting depreciation, we get an operating profit of $354 million. Net financial expenses in the quarter were $86 million. This is higher than normal due to the one-off cost of $35 million that was triggered by the expense of the remaining unadvertised fees related to the termination of the RBL, when this was refinanced into a new RCF. Profit before tax were $268 million, and taxes amounted to $206 million. Of these $206 million, $78 million was the current tax arising in the quarter, $123 million was the changes in the surtax, and $5 million was related to prior period adjustments.
The effective tax rates for the quarter were 77%. The tax rate can in broad terms be explained by uplift on CapEx driving the tax rate down, while the financial expenses related to the termination of the RBL and reevaluation of dollar-denominated loans drove it slightly up again. The actual tax payment in the quarter amounted to $208 million, which is in line with the guidance that we provided in our Q4 presentation. Net profit in the second quarter ended at $62 million. We move on to the balance sheets, which were fairly stable this quarter. You can see that PP&E increased by $346 million. We had additions of $490 million, where investment at Valhall and Froskelår made up roughly 70%. We have depreciation of PP&E amounting to $144 million.
We had additions of $32 million in right-of-use assets as we added the Maersk Integrator rig to be used at Ula to the balance sheet. Net of depreciation and use, the increase in the balance sheet was $14 million in right-of-use assets. On the other side of the balance sheet, we can see that equity was reduced by $136 million, representing the netting of net income, dividends, and the purchase of treasury shares for the employee share program. Deferred tax increased by $124 million, which was mainly made up of an increase of $81 million related to different in accounting and tax depreciation. An increase of $102 million related to capitalized exploration interest and actual decommissioning costs, which is expensed for tax purposes. Reevaluation of tax balances decreasing the deferred tax with $24 million, and accretion reducing the deferred tax with another $24 million.
Bonds and bank debt increased in the quarter with $409 million. Tax payables decreased by roughly $128 million, giving a balance of $439 million. This can be divided into $207 million related to the income year 2019, $4 million related to 2018, and $229 million related to accrual for uncertain tax positions. In sum, total equity and liabilities amounted to $11.5 billion at the end of the quarter. Aker BP is always working to optimize its capital structure, and we made a couple of improvements the last couple of months that I'll quickly run you through. As already touched briefly upon, we have now established a new unsecured credit facility of $4 billion. This replaces the old secured RBL. With this, we have achieved the three main objectives, which I mentioned in my first quarter presentation. One, we have extended the maturity of our bank debt.
Two, we have reduced interest costs significantly. Three, we have made all lenders to Aker BP pari passu. In the second quarter, all the three main credit rating agencies also issued new reports on Aker BP. Fitch took up coverage for the first time and issued an investment-grade company rating of BBB-. Moody's and S&P confirmed their company ratings. In addition, Moody's rated up our existing bonds as they are no longer subordinated to our bank debt. In June, capitalizing on the tailwind from the new bank facility and the updated credit ratings, we decided to issue a new bond. Due to the strong interest and favorable terms, the issue was upscaled from the original planned $500 million to $750 million. This new bond matures in 2024 and has a coupon of 4.75%.
The proceeds of the bond issue was used to reduce drawings on the new RCF. With these activities in the second quarter, Aker BP has increased its financial capacity and flexibility, while at the same time reduced funding costs. Moving on to how the activities in the second quarter has impacted cash flows. We started the second quarter with cash of $114 million, and during the quarter, we drew net debt of $365 million. Cash flows from operations amounted to $595 million, and tax payment was, as already mentioned, $208 million. Cash flows to investments was $541 million, of which the main contributors were $414 million in investment in fixed assets, and that includes $44 million in capitalized interests, $87 million in exploration, and $40 million in the common P&A. Lease payments amounted to $26 million, and $21 million of these were related to CapEx activities. Lastly, dividends amounted to $187.5 million.
At the end of the quarter, our cash balance was $102 million. The book value of net interest-bearing debt, including lease debt, was roughly $2.9 billion, and we had $3.2 billion of committed undrawn capacity on the new $4 billion bank facility. Excluding the effects of IFRS 16, our leverage ratio, net debt over EBITDA, was 0.9 at the end of the quarter. In our Q4 presentation, we provided some guidance on cash tax payments for the coming quarters. In June, we set the actual amount for the three tax installments for the second half of 2019. The estimated amounts for the three installments for the first half of 2020. The installments are very much aligned with the forecast that we provided, and we expect to pay an installment of $106 million in Q3, and then two installments of the same amount in Q4.
To round off my section, I would like to revisit our guidance for 2019 as normal. We guided 2019 production between 155,000 bpd and 160,000 bpd . Q1 came in a bit above the midpoint and in line with plan. The second quarter also came in as expected, roughly 30,000 bbl lower than in the first quarter due to the planned maintenance of Valhall and Ula. With the turnarounds behind us and the startup of Valhall West Flank and the Johan Sverdrup in the second half of the year, we expect production to increase accordingly. Consequently, we maintain the full-year guidance of 155,000 bpd to 160,000 bpd . If we jump down to abandonment, the spend for 2019 was guided at $150 million. Spend year-to-date has been roughly $62 million, and this is below our plan and is driven by the strong performance that Karl has already talked about.
During my first quarter presentation, I mentioned that we were looking into postponing planned P&A activities at Valhall and Hod in order to utilize the rig for production drilling at Valhall instead. I'm happy to say that this has now been confirmed, and we therefore expect abandonment spend to end roughly around $100 million for the full year, and the remaining budget of $50 million is then moved to CapEx. On CapEx, we originally guided at $1.6 billion for the full year. Both the first and second quarter have seen spend a bit below average, but we believe this is mainly due to phasing. Now that we have moved rig capacity from P&A to production drilling and adjusted down the ABEX, we therefore simultaneously also adjust CapEx slightly up, and the new guiding is $1.6 billion-$1.7 billion.
Exploration spend was guided at $500 million and with an original program of 15 wells. The success with discoveries at Froskelår and Liatårnet and the ongoing work at Rumpetroll means that we increase data gathering related to those wells and thereby also slightly increasing the associated costs. Furthermore, as Evy has mentioned, due to the very strong drilling performance, we have created room in our rig lines to fast-track two additional wells into the 2019 program. Thus, in total, this could put some pressure on the guided exploration spend, and we therefore adjust it slightly upwards to a new guiding of $550 million for the full year. Production cost per produced barrel is guided at $12.5. We expected the first half of 2019 to be higher than the yearly average due to the maintenance activities, especially at Valhall and Ula, and including the turnarounds in June.
In Q3 and Q4, we estimate cost per barrel to go down, especially as the turnarounds are behind us, and of course, with Valhall West Flank and Johan Sverdrup coming on stream. We therefore keep the guidance as is. Regarding dividends, we paid another $187.5 million in the second quarter, and we still plan to pay $760 million for the full year. That concludes my part of the presentation. I will hand the word back to Karl for some closing remarks before moving on to the Q&A session. Thank you.
Thanks, David. A thorough walkthrough of the financials as always. Now, I said Aker BP is never boring, and this quarter we've had more activities than we've had ever before. My main priority is also going forward, is to continue to focus on safe and efficient operations, whether that is related to production activities, drilling activities, or project activities. We're really happy to see the project execution accelerate and that these alliances are now really getting up to speed. We'll continue focusing on further improvement in the project execution range. On the improvement side, we are continuing to keep the momentum of the improvement agenda. Evy has just showed you one of these examples of activities, and we try to present one in each quarter. Again, it's an application of technology and supported by excellent people.
I also touched on the Fishbone application at Ivar Aasen, which is yet another application of high-end technology in our operations. We really utilize technology to drive value creation is fundamental in our improvement program as well. When it comes to growth, the exploration activity is high and actually increasing from the start of the year, and as are appraisal activities related to the discoveries that Evy just walked you through. We are also looking quite a lot into maturing resources to reserves in our existing fields, and the recommencement of drilling on Ula is an example of that. Of course, we are really looking forward to the start of our new fields, Johan Sverdrup and Valhall West Flank , in the next quarter.
Again, I want to thank you for participating, and I would also like to extend our thanks to all of the teams that have been working so hard this summer to complete a lot of these operations. I think we'll open up for Q&A, and David, if you'd like to join me. Guys, should we start?
Thank you
with questions in the room? Okay.
Thank you. Jørgen Bruaset from Nordea Markets Research. The discovery on Liatårnet, would you say that this has any major impact on your discussions with your partners regarding concept selection, or is this in line with the business case you have outlined in your previous discussions?
We just announced this morning, what impact it will have on concept selection discussions is yet to be determined. From our perspective, this further underlines the need for infrastructure in the area and supports the development solutions that we've been advocating for quite a while.
Thank you. Just a question for you, David. You referred to your net debt of $2.9 billion, including IFRS 16 leases, you referred to your EBITDAX under net debt of 0.9 x excluding leases. Can you just net out, what is the net interest-bearing debt pre IFRS 16? Of the $2.9, how much are these obligations?
It's roughly $365 million.
Thank you.
Okay.
Christian Yggeseth from Danske Bank. First of all, congratulations on what seems to be a great discovery announced this morning. I have a question on the OpEx per barrel guidance. It seems like it has to come down quite a bit towards the end of the year. How confident are you that you will achieve that target of $12.50 per barrel? Can you comment on how you expect to get down to the, I guess, around $10 at the end of the year?
Sure. I'll start. Then maybe Karl can add on. I think the $12.5, as you mentioned, is the average throughout the year. First quarter, we saw significant maintenance work, including the accommodation units that was present at Valhall and Ula driving the cost up. Second quarter, we had much lower production due to the turnarounds and the high maintenance activity there. With that behind us, we're moving towards a more normal maintenance level. Then with increasing productions from Valhall West Flank coming in and also Johan Sverdrup towards the end of the year, that balances out. We're still confident and our best estimate is that we'll end up at $12.5. Then we've yet to see.
Just another one on, I think it's fair to say that the share price has been quite volatile during the past six to nine months. Have you considered introducing a buyback program or changing parts of your dividend payout to buyback program pure dividends?
We have been very clear on our dividend program and also our ambitions for that program. That ambition stands firm, as previously communicated during the capital market day.
Thank you.
Okay, let's move online, shall we?
Thank you.
Operator-
If you would like to ask a question, please signal by pressing star one. We'll take our first question from the lines of Anders Holte from Kepler. Please go ahead.
Yeah, good morning, guys. Can you hear me?
Absolutely.
Okay, there's a bit of an echo here, I'll go ahead. First of all, congrats on a solid quarter, and of course, the Liatårnet discovery is of interest. I'd just like to pick up on something that was mentioned during your presentation here. You say that the Liatårnet discovery, you're giving a range of 80 bbl-200 bbl, but you're also quite clear in saying that it is not a standalone development. If it's not a standalone development, 200 million bbl, is that not a tiny bit high in terms of the recoverable resources? Also, if you give a bit more color on where you stand in terms of the confidence of that interval, that'd be good.
Thanks, Anders. We can hear you loud and clear. I don't know how you can hear us. When we comment on this, of course, this is all very fresh. The data is just in. We expect to carry out one or possibly two appraisal wells in that discovery before concluding on development solutions. However, the first look at this field gives us reason to believe that it would be better served as a part of a larger field development in the entire area than as a standalone development in its own right. That's also, of course, driven by the location and the other discoveries in that area. We'll come back to the market with more information as soon as we have conducted the disposal activities, which will give us reason to lower the range.
Okay, thanks. Just a follow-up question there. There's been quite a lot of noise in the media, should we say, on the NOAKA development. Is there anything new you can share with us on the progress of, say, a potential area development here?
I think I'll reiterate my statement during the presentation that discussions are ongoing between the parties.
Okay, thanks.
Okay, bye.
We will take our next question from the line of Yoann Charenton from Societe Generale. Please go ahead.
Yes, good morning. I would like to ask a few questions. First set of questions will be on M&A, a topic du jour on the NCS, it seems. In this respect, have you achieved any progress in finding an additional equity partner at Valhall? Where does Garantiana fit in the context of potential swaps?
Okay, thanks, Yoann. We have actually not looked for another partner at Valhall. I guess the answer to that is no. We've been preoccupied with driving up value in the asset. For the time being, we are happy with our ownership in Valhall. We've previously communicated that over time, we would like to reduce to about 67% or 2/3. Right now, there are no such processes ongoing. Of course, there are lots of M&A activity ongoing on the Norwegian Continental Shelf, we don't normally comment on our discussions on that field. There are also a number of swap opportunities, and possibly also discussions ongoing. Again, we normally don't comment on these issues.
Thank you. That's very clear. During this quarter, you announced a digital cooperation with OMV. Does such a partnership involve any data sharing on the NCS with OMV? If so, what sort of data fall under the scope of the cooperation?
Thanks. Yes, we did. This is kind of following our strategy of trying to be as open and driving standards in the digital space in the oil and gas industry. In OMV, we found a partner, a collaboration partner who shared a lot of the mindsets that we at Aker BP have been advocating for at least the past couple of years. Really happy about that collaboration and the combination between DigitUP, which is their digital program, and Eureka, which is our digital program. In the middle with the Cognite and their platform technology, it looks like we have a very forceful collaboration scheme ongoing. We have been discussing exchanging information about ongoing digital projects, exchanging development projects and technologies, and also sharing technologies and ways of working. The collaboration agreement does not exclude sharing of data.
As you're probably aware, Yoann, we are very much in favor of sharing data. I wouldn't exclude that that will become a case later on. Thank you for picking it up. We're actually quite excited about that.
Thank you. The last question will be, following your exploration success in the first sub-area, have you considered entering the U.K. continental shelf?
Could you repeat that, Yoann?
Yes, sorry about this. Hopefully, you can hear me well. Given your success in the Frosk sub-area, which is fairly close to the U.K. CS, would you have considered entering the U.K. waters?
We have previously communicated that we predominantly are looking at Aker BP as a pure-play Norwegian oil and gas company. Of course, if it ends up in a situation where it's natural for us to progress our operations into U.K., because, for example, of extension of reservoirs or plays or similar type of geology, we'll consider that in due course. I wouldn't completely rule it out.
Okay, thanks a lot for your time.
Ladies and gentlemen, if you find that your question has been answered, you may remove yourself from the queue by pressing star two. We'll take our next question from the line of Alwyn Thomas from BNP Paribas. Please go ahead.
Hi, guys. Just a couple of quick ones from me, hopefully. Just on the CapEx drivers, I know there's some moving parts there. With the development CapEx slight increase in guidance, and I know there's a rig allocation sort of there as well. Will that save CapEx in future? Is that a productivity improvement type of movement? Just a few thoughts on that. Again, on the sort of financials, given the high overlift position you had in the first half of the year, should we expect some reversal second half of the year? Perhaps a little bit more broadly on the NCS, Karl, I just wanted to ask, we've seen few indications of some cost inflation on the NCS in absolute terms. I was wondering, are you seeing the effects being offset by productivity, some of the technology improvements that you're seeing?
Is that more than offset at the moment, or is that going to take a little bit longer to come through? Thanks.
Thanks, Alwyn. I think we got all three questions. You would start with the CapEx, David?
Yeah.
Thank you for those questions, Alwyn. On the CapEx side, the slight increase that we do is mechanical since we're moving the P&A scope from Valhall Hod to production drilling at Valhall. Obviously, that's fast-tracking production drilling at Valhall, which would naturally have come later on. I guess you can say that it's pulling production drilling forward. When it comes to your question with regards to free cash flow, if I heard you correctly, and if there is a potential reversal of working capital, given that the development in working capital has positively impacted free cash flow this quarter. We expect that there might be some reversal. We're a bit low on working capital now if you compare to the last six quarters.
On NCS and cost inflation, again, remembering that we put a lot of these alliance contracts in place a few years ago. While we are actually seeing impact on cost, particularly related to our rates and to a certain extent, rig rates and service contracts. So far, the increase in productivity has more than removed that activity, and we're actually seeing more activity coming into our rig lines and activity lines. Whereas you can see the guidance are pretty stable over the year. So far we're seeing that the activity level, and the productivity increase has compensated from the slight increase in cost. Now, of course, Aker BP is not immune to cost increases in the industry, but we're doing our best to mitigate those cost increases by implementing productivity-increasing measures. So far, we've been quite successful.
Okay, thanks. Maybe just one quick one. Just into the third quarter, what are your production expectations and where might there be continued maintenance in the third quarter? Thanks.
Most of the maintenance activities that were planned for 2019 are now executed. The remaining scope is related to tie-in of Ærfugl at Skarv and also Valhall West Flank at the Valhall Field Center complex. Those are all accounted for when we reiterated our guidance of 155-160 over the complete year. The exact timing of the distribution of the remaining production in the second half of 2019, we'll come back to. We're currently following our plans.
We'll take our next question from the line of Sasikanth Chilukuru from Morgan Stanley. Please go ahead.
Morning, gentlemen. I had one question on the discovery again. You mentioned the Liatårnet discovery, it needs to be as part of a bigger development. I was just wondering, with this discovery, would it support two development plans, an unmanned platform at Krafla and a centralized processing hub for the remaining reserves?
Thank you for that, Sasikanth. You're of course, in the middle of the discussion right now. I think the easier answer is to say that, so far the indications have been that the economy will improve more in the PQ alternative or the common field development alternative than in the dual development alternative. This is simply put, because the total CapEx of the PQ over the total barrel of oil is lower than for two developments, which will have a higher CapEx per barrel of oil, which should, from a very easy perspective, give better economy. Then we'll have to redo the calculations once we have appraised the field.
Thank you very much.
Ladies and gentlemen, once again, if you would like to ask a question, please press star one on your telephone keypad. We'll take our next question from the line of Michael Alsford from Citi. Please go ahead.
Thanks. Good morning, everyone. I've got a couple of questions if I could, please. Just on Johan Sverdrup, could you maybe talk a little bit about what the key outstanding, I guess, events or risks that you see to first production in November? Are you more or less confident that we could see it in November or maybe even earlier than that? Would be my first question. Just secondly, coming back to the new discovery today, congratulations on that. I was a bit surprised at the low end of your range. The recovery rate is particularly low at about 16%. I was wondering if you could talk a little bit more about what you see in terms of, I guess, reservoir properties and why is that recovery rate so low. Then just sort of finalizing on NOAKA.
It does feel like there's clearly ongoing discussions, which I can understand. Would one of those discussions be that you give up operatorship of the area in order to push this through? Thanks.
Yeah, thanks. When it comes to Johan Sverdrup, again, I must say that Equinor is doing a great job as the operator of that field. We are seeing the project progressing on or better than our plans and hopes. The remaining activities is mostly related to testing, tieback of pre-drilled producers, and also pre-commissioning activities of pipelines, and utility systems, as well as control systems on the platform. Right now we are really happy about the progress. We are quite confident that we'll be able to deliver startup according to our plans or maybe even sooner. There are a couple of deadlines later this month that may give more light on the startup dates. Evy, do you want to comment on the range?
Yeah, just a little bit. We haven't told you much about the prospects. It's a very shallow in-depth discovery. It's at about 1,000 m depth. We haven't really succeeded in the data acquisition that we wanted to have because it's unconsolidated sediments. Since we're struggling a little bit to get all the data we need to talk more about the oil quality, mobility, and also recovery factors, we have to go out with a very wide range until we go back and test it. That's why you see that wide range. It's not to be overly optimistic, but to show some pragmatic range until we have more data.
Yeah. I wouldn't put too much of an emphasis on the calculation of recovery factors just yet. It's basically an outline where you combine recovery factors, rock mechanics, porosities, and gross rock volumes that gives that kind of range. We, of course, in this phase, we may even be accused of being a bit conservative, but I'll take that on my head and not on others. On NOAKA, I won't comment on the specifics in the discussions ongoing. Just comment on the fact that we continue to see PQ as the most realistic, but also most economically viable development scheme in that area. We'll keep the discussions between the parties.
Understood. Thank you. Sorry, just a quick follow-up. I know you've just announced the discovery, but when would you expect to come back and appraise? Would that be early next year, or would that be longer to get that in place? Thank you.
I'm speculating a bit now, Michael, but the next well will be the Vårgårda well in the Norwegian Sea, and then we'll do the Nipa, which is in the same area. We'll do our best to fast track and appraise a well and try to put that into the drilling schedule immediately following the Nipa well. We'll get back to you on specifics on that, but that's the working hypothesis as of now.
Great. Many thanks.
In that case, it will be towards the end of this year.
Understood. Thank you.
We'll take our next question from the line of Teodor Nilsen from SB1 Markets. Please go ahead.
Thank you. Good morning, congrats on a great discovery. Two questions from me. You spent a lot of time discussing the exploration activity. Just looking into 2020, should we expect an even higher exploration activity in 2020 versus 2019 in terms of number of wells and spending? Second question is to David. You mentioned some uncertain tax positions in your balance sheet. Can you just elaborate a little bit on those? Thank you.
If I let Evy answer that first question, I'm probably getting a lot more wells in 2020. Maybe you can start, Evy.
Yeah, no, we haven't planned higher activity. We've said that for 2020, we're going to have roughly the same activity level that we've had in 2019. It's still a little bit uncertain which wells that we were going to drill in 2020. We're going to evaluate the discoveries that we have had this year so far and see if we need to do more appraisal on more of them.
Yeah, Teodor, as you saw during the presentation, we have actually accelerated two of the 2020 wells into the 2019 program due to significantly higher drilling performance than we accounted for in the beginning of the year. I would say that the drilling program for 2020 is a bit volatile at the moment. There's a lot of exciting prospects also in that drilling program. We'll get back to you later this autumn with more information on that. David, about tax, this is your favorite topic.
My favorite topic. Yes. Thank you. Please. The uncertain tax position that we have in the balance sheet is typically related to the historical tax discussions with Oil Taxation Office, that typically has been accumulated through the acquisitions back both with Hess Norway and also BP Norway. We don't comment specifically on the ongoing discussions, but typically they are related to intercompany transactions between the parent company and the Norwegian subsidiaries.
Okay. Thank you.
We'll take our next question from the line of Karl Fredrik Schjøtt-Pedersen from ABG Sundal Collier. Please go ahead.
Yes. Congratulations on your discovery on the NOAKA area. Just trying to get the grips on the economics of such a discovery relative to the full area development. If you could shed some light on, in broad terms, how would the break-even levels of a discovery of this type, you don't have the specific on this discovery, but in general terms, discovery on this type affect the break-even of the entire PQ concept?
Well, it's of course a bit speculative to generalize on development concepts and related drilling activities and break-evens. I think I'll reiterate what's been stated previously, and that is the PQ without the Liatårnet discovery, had a break-even that was hovering around $35 per barrel, with the OpEx and per barrel down at the $3-$5 range. Of course, the more volume you put into such a PQ, the break-even will drop. How much it will drop depends, of course, on the marginal economy of the barrels you put in, which is directly related to how much oil you're actually getting out of this as well. There's of course a really different impact, whether this ends up as 80 million- 200 million, if I'm going to be really generalistic.
You should expect Liatårnet to have a downward progression of the break-even when you include discoveries of this magnitude.
When you're looking at the ongoing discussions with Equinor, how would, in your view, such a contribution to reserves in the area as a whole, that alter the power of the negotiations in your favor?
I think I'll refrain from commenting on how this will impact discussions on area solutions like Karl Fredrik. I'm sorry about that.
No worries. Had to try. Thank you.
We'll take our last question from the line of Eddie Spence from Bloomberg. Please go ahead.
Hi, guys. Congratulations on the discovery. I just wanted to ask about the increase in CapEx. It is not that normal at the moment for oil companies to be doing so, especially given the kind of volatility we have seen over the past year. Is there a particular reason you guys are sort of setting yourselves apart?
Yeah. Let me just reiterate that. The total spend level does not increase. Basically what we have done, we have moved $50 million from abandonment expenditure as we have postponed decommissioning work, and then fast-tracked production drilling, which is obviously more value accretive for the company. It is not an increase in total spend, but it is just a shifting between buckets of costs.
Okay, thanks very much.
Okay. Is that the last question, operator?
Yeah, we have one last person, sir. Would you like to take it?
Absolutely. Let's do one last question.
Sure.
It's almost summer.
Thank you. It's James Thompson from JP Morgan. Please go ahead.
Great. Thank you very much for fitting me in there. Much appreciated. I just wanted to go back to one of your comments in the presentation on Skarv, if that's all right, Karl. You talked about a new production strategy there. Obviously much higher liquids content this quarter versus last quarter. I just really wanted to understand how much flex there is in the system and what's driving that change. Is it gas prices? Do you really have a lot of flex to flip between the amount of gas you're injecting over such a short timeframe? What's the value proposition for Skarv by having this completion tactics? That'd be great. Thanks.
Yeah. We've actually been reassessing or reevaluating the drainage strategy on Skarv for almost a year and a half now, where the strategy has been to inject more of the gas in the early phase and thereby increase oil production. Of course subsequently produce back all that gas and sell it to the markets. The reason we've postponed this or not executed sooner is related to restrictions in the gas distribution system, and particularly related to flow-induced vibrations in the flow bases in few of the gas injectors. Now we have verified by inspection and installation of instrumentation that such flow-induced vibration is below the acceptable threshold, and thus we've been able to increase gas injection, and thereby increasing oil production in the area.
We'll continue that drainage strategy as that is more value accretive in the longer term than the drainage strategy that we've been pursuing previously. Of course, there is a complete flexibility should we end up in a situation where gas prices are soaring, and that the reversal of the strategy is necessary. There's no real problem in reversing that strategy. It's basically just a distribution of gas in the injection system.
Okay, you've actually increased
I think you dropped off there a bit, so I didn't get the last question.
Sorry, Karl. Just to reiterate, it sounds to me like you've got quite a lot more flexibility in terms of how you produce Skarv over the next few years on that basis. Will that also fold into Ærfugl as well?
Ærfugl don't really have the amount of liquids that the Skarv development has. Remember, Skarv is several different segments with different GORs, different oil-water-gas distributions. Here we're basically redistribution gas from high gas parts of the field and into high oil parts of the field, and then increasing the oil production as we're maintaining mass balance in those segments. When you introduce Ærfugl, you have more gas of course, but we are currently gas constrained. It won't really impact the production strategy over the field.
Very good. That's okay. Thanks so much.
Thank you. With that, I think
Closing remarks.
Okay. Thank you. With that, I think we conclude the Q2 presentations. Thank you to everybody both here at Fornebuporten and those online, and I wish you all a great and safe summer. Thank you.
That concludes today's conference. Thank you everyone for your participation. You may now disconnect.