Aker BP ASA (OTCPK:DETNF) Q2 2019 Earnings Conference Call July 12, 2019 2:30 AM ET
Karl Hersvik – Chief Executive Officer
Evy Glorstad-Clark – Head-Exploration
David Torvik Tonne – Chief Financial Officer
Conference Call Participants
Jorgen Bruaset – Nordea Equity Research
Christian Yggeseth – Danske Bank
Anders Holte – Kepler
Yoann Charenton – Societe Generale
Alwyn Thomas – BNP Paribas
Sasikanth Chilukuru – Morgan Stanley
Michael Alsford – Citi
Teodor Nilsen – SB1 Markets
Karl Fredrik Schjott-Pedersen – ABG Sundal Collier
James Thompson – JPMorgan
Good morning, everyone, and welcome to AKER BP’s Second Quarter and First Half Presentation of 2019 here at Fornebuporten. And also a warm welcome to all of those who follow us online or on our conference call.
Let me warm up my 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 start-up of production from both Johan Sverdrup and the Valhall West Flank later this year.
We also continued 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 these in detail later in the presentation, but before we dive into the details, I would like to share some reflections over the activity level in Aker BP.
As I’m used to saying on these quarterly presentations, it’s been yet another exciting quarter at Aker BP. But 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.
And 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. And 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&L – P&A of the Jette wells.
And now, I’d like to give the word to our Head of Exploration, Evy Glorstad-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 stories starting in 2019. I presented the exploration program in the Capital Markets Day earlier this year and now I’m giving you an update, and 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 in the expenses 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 on Rushmore statistics as the first place, third place and fourth place drilling performance. And that’s very good. We have also added two more exploration wells to the exploration program. I presented 15 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 Nidhogg 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. And for the Nipa well, it’s important for our NOAKA future – hopefully future development.
But I’m also here today to present the Liatarnet 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 to 700 million barrels of oil equivalent. We still need to work a little bit further to figure how much of that oil we can get out of the ground. We need to look into recovery factors. We need to look at drainage strategies.
But so far, we have press released a recoverable volume preliminary estimated to 80 million to 200 million barrels. So 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 Gamma Delta discovery, and it will add significant value and robustness to an area development. This well is a well that we haven’t presented externally before. So on the Capital Markets Day, it was actually just listed as a NOAKA well.
So we haven’t gone out with a new predrill estimates, so 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. But it also shows how exciting it still is to do exploration on the Norwegian Continental Shelf. So this is, for us, a success story today. I’ll also spend 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 Froskelar discovery, which is also a significant discovery this year. It has an estimate of 60 million to 130 million barrels of oil equivalents discovered.
And in the second quarter, we followed that with the Froskelar Northeast well, which is a minor discovery, but it was also one of the appraisal wells linked to the whole Frosk test producer drilling campaign. So we’re doing a lot of drilling activity in this area, but we haven’t gotten any of the results yet from the Frosk test production, but 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, but that was one of the discoveries from last year. And we’re currently drilling the Rumpetroll well, which is ongoing operations, and we’re not sharing any of that information still. But 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 3.5 years.
As also mentioned, we have done some – we’ve done really good drilling performance. And what this DSS rig has done for us, it’s the world’s first dual drilling operations done. And that’s very exciting. It’s drilling faster and faster, and we now completed dual drilling on three wells: the JK prospects; the Hornet; and Freke-Garm. All the three prospects were unfortunately dry, but just showing what the dual drilling can do is very exciting. It has a 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 has two drill crews. So while you’re drilling the top hole, the primary can still run the whole BOP operation. So that’s why this becomes very efficient.
So just looking at the exploration program for 2019 where we have added two new wells. You can see that we have the Nidhogg 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, where have no press release, are ongoing drilling still, and 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. And as I said, on the Capital Markets Day, we are actually the second biggest license holder on the Norwegian Continental Shelf, and 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 barrels in the first quarter, representing a decrease of roughly 31,000 barrels per day compared to the previous quarter. This was more or less in line with our plans and also previously communicated estimates. The main driver was maintenance – planned maintenance on Valhall and Ula, which each carried out a month-long turnaround. That’s been planned for 1.5 years. 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’s will 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%. Ivar Aasen also performed very well but 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 drilled and completed. The Volund Sidetrack well was drilled and completed within 12 days, 23 days ahead of plan. Quite ambitious plan, I must say. So again, kudos to the drilling department. And it’s already been put onstream. We have completed drilling of the Frosk test producer. The test producer is assumed to come on production during the third quarter following subsea installation processes. And the test producer will contribute with important results of the Frosk information and 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 a damage on the riser support system. The damage was just discovered during the annual ROV inspection of the riser support system and anchoring systems. Pending repairs, we have shut in production from a few wells at Alvheim and Vilje, but have been able to mitigate most of the production effect by increasing outputs from other wells in the area. Now moving onto an asset with even more activity in the quarter. At Valhall, we have executed a month-long turnaround in June, executing about 24,000 offshore hours, supported by 10,000 onshore hours. And of course, production was affected negatively by this.
During the shut-in period, we have also removed the QP topside, which is one of the old topside and I’ll come back to that shortly. But first, the most exciting news on Valhall during the quarter, we have successfully installed the Valhall West Flank topsides, only 14 months after first steel was cut at Verdal. And this is probably the most complete offshore platform that has gone onto the sea on the Norwegian Continental Shelf, ahead of schedule, under budget and with no serious injuries. There are no carryover work, and testing and commissioning was 93% complete on installation, meaning only the systems that require live hydrocarbons were yet to be tested and completed.
The Maersk Invincible rig is now in place and will drill wells and function as accommodation rig for the remainder of the hook-up and commissioning work. Start of this plan, 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 first 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 and 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 Jette field and successfully recovered the Christmas trees. And we will reconsider – 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, as usual, smooth operations.
Maersk Interceptor is now drilling at the field again and one well is successfully started up in June. This well was completed with Fishbone technology, which is an enhancement technology for the rest of our 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 will be – is currently being drilled and should be ready for start – production by the end of third quarter.
Now 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 production – 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 AErfugl project is progressing according to plan, and offshore modification work is ongoing.
The picture shows the first AErfugl SPS flow base being loaded up from the yard in May. The new generation of vertical Christmas trees is close to completed, and subsea installation and drilling will start in the second half of this year. Phase 2 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. And 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 hook-up, commissioning and the completion of the four platforms as well as tie-back operations for the pre-drilled production wells.
During the second quarter, the partnership also got the government approval for the Johan Sverdrup Phase 2, which will increase the field’s production capacity from 440,000 barrels of oil equivalent per day to 660,000 barrels of oil equivalent per day when it’s completed in 2022.
Now 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 Liatarnet discovery, the total recoverable resources in the area are now in the order of 700 million barrels of oil equivalents. And as Evy mentioned, we are 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 lack infrastructure.
Aker BP’s answer to these challenges is to develop the entire area with a the PQ concept consisting of a central processing hub in the middle of – 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. And as should be well known by now, discussions are currently ongoing between the partners on how to develop the area.
Now with that, I’ll leave the floor to David and his walk-through of the financial results? David?
David Torvik Tonne
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. But before I do that, let me start with the big picture. In the second quarter, as Karl has already mentioned, we produced 127,300 barrels per day. But similarly to the last quarter, we sold more volumes than we produced, and the total sold volumes ended up 140,700 barrels.
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 were $780 million, which is approximately 9% down from the first quarter.
If we move onto the income statement, adjusting petroleum revenues for other income, we get the total income of $785 million. Production costs in the quarter were $198 million. And remember, this line item is impacted by the change in accounting principles 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 3, 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 of fields at $8.1. 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. And 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 $15.4. 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.
And 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 up $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 $14.5 per barrel. And then 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 unamortized fees related to the termination of the RBL when this was refinanced into a new RCF.
Profit before taxes 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 deferred tax and $5 million was related to prior period adjustments. The effective tax rate for the quarter were 77%, and 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 payments in the quarter amounted to $208 million, which is in line with the guidance that we provided in our Q4 presentation. Thus, net profit in the second quarter ended at $62 million.
If we move on to the balance sheet, which were fairly stable this quarter. You can see that PP&E increased by $346 million. We had additions of $419 million where investments at Valhall and Sverdrup made up roughly 70%, and then we have depreciation of PP&E amounting to $144 million. We have 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 $80 million – or $81 million related to difference in accounting and tax depreciation; an increase of $102 million related to capitalized exploration, interest and actual decommissioning cost, which is expensed for tax purposes; and then 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, and tax payables decreased by roughly $128 million, giving a balance of $439 million, which can be divided into $207 million related to the income year 2019, $4 million related to 2018 and then $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 in 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 debts. Two, we have reduced interest costs significantly. And 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, and in addition, Moody’s rated up our existing bonds as they are no longer subordinated to our bank debts.
In June, capitalizing on the tailwinds 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 and fixed assets, and that includes $44 million in capitalized interests; $87 million in exploration; and $40 million in decom and 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 of EBITDAX 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. And in June, we set the actual amount for the three tax installments for the second half of 2019 and 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 and 160,000 barrels per day. Q1 came in a bit above the midpoint and in line with plan, and the second quarter also came in as expected, roughly 30,000 barrels lower than in the first quarter due to the planned maintenance stops at Valhall and Ula. With the turnarounds behind us and the start-up of Valhall West Flank and Johan Sverdrup in the second half of the year, we expect production to increase accordingly. And consequently, we maintained the full year guidance of 155,000 to 160,000 barrels per day.
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 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.
And now that we have moved rig capacity from P&A to production drilling and adjusted down the ABEX, we therefore simultaneously adjust CapEx slightly up. And the new guiding is $1.6 billion to $1.7 billion. Exploration spend was guided at $500 million and with an original program of 15 wells. The success with discoveries at Froskelar and Liatarnet and the ongoing work at Rumpetroll means that we increased data gathering related to those wells and therefore 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 million. We expected the first half of 2019 to be higher than the yearly average due to 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 after turnarounds are behind us, and of course, with Valhall West Flank and Johan Sverdrup coming onstream. 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 $750 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, for a walk-through of the financials as always. All that said, Aker BP is never boring. And this quarter, we’ve had more activities than we’ve had ever before. So my main priorities 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 these alliances are now really getting up to speed. And we’ll continue focusing on further improvement in the project execution ridge.
On the improvement side, we are continuing to keep momentum on the improvement agenda. Evy has just showed you one of these examples of activities, and we try to present one in each quarter. And again, it’s an application of technology and supported by excellent people. And I also touched on the Fishbone application at Ivar Aasen, which is yet another application of high-end technology in our operations. So we really utilize technology to drive value creation. It’s 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 our 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. And of course, we are really looking forward to the start-up of new fields, Johan Sverdrup and Valhall West Flank, in the next quarter. So again, I want to thank you for participating, and I’d also like to extend our thanks to all of the teams that were working so hard this summer to complete a lot of these operations.
Now I think we’ll open up for Q&A. And David, if you’d like to join me? Guys, should we start with questions in the room? Okay.
Q - Jorgen Bruaset
Thank you. Jorgen Bruaset from Nordea Equity Research. So the discovery on Liatarnet, 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?
Well, we just announced this morning. So what impact it will have on concept selection discussions is yet to be determined. But 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. And then just a question for you, David. You referred to your net debt of $2.9 billion including IFRS 16 leases. And you referred to your EBITDAX under net debt of 0.9 times excluding leases. Can you just net out, so what is the net interest-bearing debt pre IFRS 16? Of the $2.9 billion, how much are lease obligations?
Yes. It’s roughly $365 million.
Christian Yggeseth for 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’ll achieve the target of $12.5 per barrel? And can you comment on sort of how you expect to get down to I guess around $10 at the end of the year?
Sure. So I’ll start, and then maybe Karl can add on. So 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, and then with the increasing productions from Valhall West Flank coming in and also Johan Sverdrup towards the end of the year, that balances out. So we are still confident. And our best estimate is that we will end up at $12.5, and then there is yet to see.
And just another one. I think it’s fair to say that the share prices has been quite volatile during the past 6 to 9 months. Have you considered introducing a buyback program or sort of changing parts of your dividend payouts to buyback [Indiscernible] your dividends?
We have been very clear on our dividend program and also our ambitions for that program. And that ambition stands firm and as previously communicated during Capital Market Day.
Okay. Let’s move online, shall we? Operator?
[Operator Instructions] We’ll take our first question from the line of Anders Holte from Kepler.
Good morning, guys. Can you hear me?
Okay. There’s a bit of an echo here, so I’m just going to plow ahead. But first of all, congrats on a solid quarter. And of course, the Liatarnet discovery is of interest. I’d just like to pick up on something that was mentioned during your presentation here. You say that the Liatarnet discovery, you’re giving a range of 80 million to 200 million, but you’re also quite clear in saying it’s not a standalone development. Now if it’s not a standalone development, then the 200 million barrels, is that kind of a bit high in terms of the recoverable resources? And also if you could give a bit more color on where you stand in terms of the confidence of that interval, that would be good.
Thanks, Anders. We can hear you loud and clear. I don’t know how you can hear us. But when we comment on this, of course, this is all very fresh. The data is just in. And 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. And then we’ll come back to the market with more information as soon as we have conducted appraisal activities, which will give us reason to lower the range.
Okay. And just a follow-up question here. I mean there’s been quite a lot of noise in the media, as you would say, on the NOAKA developments Is there anything you can share with us on the progress of, say, a potential area of development here?
I think I’ll reiterate my statement during the presentation that discussions are ongoing between the parties.
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 question will be on M&A, a topic [Foreign Language] on the NCS, it seems. In this respect, have you achieved any progress in finding an additional equity partner at Valhall? And where does Garantiana fit in the context of potential swaps?
Okay, thanks Yoann. We have actually not looked for another partner at Valhall. So I guess the answer to that is no. We’ve been preoccupied with driving up value in the asset. And 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 two thirds. But right now, there are no such processes ongoing. Of course, there are a lot of M&A activity ongoing on the Norwegian Continental Shelf, and we don’t normally comment on our discussions on that field. There are also a number of swap opportunities, and possibly also, discussions ongoing. But again, we normally don’t comment on these issues.
Thank you. That’s very clear. And maybe then as well, during this quarter, you announced a digital cooperation with
partnership involve any data sharing on the NCS with OMV. Does such partnership involve any data sharing on the NCS with OMV? And 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. So in OMV, we found a partner and – a collaboration partner who shared a lot of the mindset that we in Aker BP has been advocating for at least the past couple of years. So really happy about the collaboration. And the combination between DigitUP, which is OMV’s digital program; and Eureka, which is our digital program; and then in the middle with the Cognite and their platform technology, it looks like we have a very forceful collaboration scheme ongoing.
So far, we’ve been discussing, exchanging information about ongoing digital project, exchanging development projects and the technologies and also sharing technologies and ways of working. The collaboration agreement do not exclude sharing of data. And as you’re probably aware, Yoann, we are very much in favor of sharing data. So I wouldn’t exclude that, that will become a case later on. What – thank you for picking it up. We are actually quite excited about that.
Thank you. And the last question will be following your exploration success in the first sub area. Have you considered entering the UK Continental Shelf?
Could you repeat that, Yoann?
Yes. Sorry about this. Hopefully, you can hear me well. Given your success in the first sub area, which is fairly close to the UKCS, would you have considered entering the UK weather?
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 UK because, for example, of extension of reservoirs and plays or similar type of strategy, we’ll continue – we’ll consider that in due course. But I wouldn’t completely rule it out.
Okay. Thanks so much for your time.
[Operator Instructions] We’ll take our next question from the line of Alwyn Thomas from BNP Paribas. Please go ahead.
Hi, guys. Just couple of quick ones from me, hopefully. Just on the CapEx drivers and some moving parts there. With the development CapEx slight increase in guidance, is that – and I know there’s the rig allocation sort of there as well, will that save CapEx in the future? And is that a productivity improvement type of movement item? Just a few thoughts on that. And again, on the sort of financials. Given the high overlift position you have in the first half of the year, should we expect some reversal in the second half of the year? And perhaps a little bit more broadly on the NCS color. I just wanted to ask, we’ve seen few indications of some cost inflation on the NCS in sort of absolute terms. But I was wondering, are you seeing the effects being offset by productivity, sort 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, Alwyn. I think we got all three questions. You will start with the CapEx, David?
Yes. So, thank you for those questions, Alwyn. So on the CapEx side, the slight increase that we do is sort of mechanical since we’re moving the P&A scope from Valhall hub to production drilling at Valhall. Obviously, that’s fast-tracking production drilling at Valhall which would naturally have come later on, so 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 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. So we’re a bit low on working capital now if you compare it to the last six quarters.
Yes. And on NCS and cost inflation, again, remembering that we put a lot of these alliance contracts in place a few years ago, so while we are actually seeing impact on cost, in particular related to hour 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 being – coming into our rig lines and activity lines, while, as you can see, the guidance are pretty stable over the year. So, 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. And so far, we’ve been quite successful.
Okay. Thanks. And Maybe just one quick one. Just into the third quarter, what are your sort of production expectations and where might that be sort of continued maintenance in the third quarter?
Most of the maintenance activities that were planned for 2019 are now executed. So the remaining scope is related to tie-in of Skarv at – no, AErfugl, not Skarv; and also Valhall West Flank at the Valhall field center complex. Those are all accounted for when we reiterated our guidance of 155,000 to 160,000 over the complete year. So exact timing of the distribution of the remaining production in second half of 2019, we’ll come back to it. But we’re currently following our plans.
We’ll take our next question from the line of Sasikanth Chilukuru from Morgan Stanley. Please go ahead.
Good morning, gentlemen. I have question on the discovery again. You mentioned Liatarnet discovery, it needs to be in – as part of a bigger development. I was just wondering, with this discovery, would it support two development plans and one platform at Krafla and a centralized processing hub for the remaining results?
That’s, of course – thank you for that, Sasikanth. We’re, of course, in the middle of a discussion right now. I think the easy 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. And this is simply put because the total CapEx of the PQ over the barrel of – total barrel of oil, it’s lower than for two developments, which will have a higher CapEx per barrel of oil, which will – well, from a very easy perspective, give better economy. And then we’ll have to redo the calculations once we have appraised the field.
Thank you very much.
[Operator Instructions] 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 you could see it in November or maybe even earlier than that will be my first question?
And secondly, coming back to the new discovery today. Congratulations on that. But I was a bit surprised at the lower end of the range. The recovery rates is particularly lowered to about 16%. So I was wondering if you could talk a little bit more about what you see in terms of, so I guess, reservoir properties and why is that recovery rate so low. And then just sort of finalizing on NOAKA. It does feel like there’s clearly ongoing discussions, which I can understand. But would one of those discussions be that you give up operatorship of the area in order to push this through? Thanks.
Yes. Thanks. Now when it comes to Johan Sverdrup, again, I must say that Equinor is doing a great job as the operator of that field, and we’re seeing the project progressing on or better than our plans and hopes. And the remaining activities, it’s mostly related to testing, tie-back of pre-drilled producers and also pre-commissioning activities of pipelines and utility systems as well as controlled systems on the platform. So right now we are really happy about the progress, and we are quite confident that we’ll be able to deliver start-up according to our plans or maybe even sooner. There are a couple of deadlines later this month that may give more light on the start-up dates. Now Liatarnet, Evy, you want to comment on the range?
Yes, just a little bit. I mean we haven’t told you much about the prospect. It’s a very shallow, in-depth discovery. It was about 1,000 meters depth. So – and we haven’t really succeeded on the data acquisition that we wanted to have because it’s on consolidated sediments. So 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. So 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.
Yes. So 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, work mechanics, processes and then cross-work volumes. That gives that kind of range. Yes. We, of course, in this phase, we may even be accused of being a big conservative. But I’ll take that on my head and not on Evy’s. Now 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. And then we’ll keep the discussions between the parties.
Understood. Thank you. And sorry, just a quick follow-on. 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?
I’m speculating a bit now, Michael, but the next well will be the Vagar well in the Norwegian Sea, and then we’ll do the Nipa, which is in the same area. So we’ll do our best to fast-track and appraisal the 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. So 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 and good morning. And congrats on a great discovery. Two questions from me. You spent a lot of time discussing the exploration activity. So just looking into 2020, should we expect an even higher exploration activity in 2020 versus 2019 in terms of the number of wells and spending? And 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.
Well, I’ll let Evy answer that first question. I’m probably getting a lot more wells in 2020, but maybe you can start, Evy.
Yes. No, we haven’t planned higher activity. We 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’re going to drill in 2020. We’re going to evaluate the discoveries that we’ve had this year so far and see if we need to do more appraisal on more of them.
And also, 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, but there’s a lot of exciting prospects also in that drilling program. So we’ll get back to you later this autumn with more information to announce. And then David, about tax? This is your favorite topic.
My favorite topic, yes, thank you, please. No, so the uncertain tax position that we have in the balance sheet is typically related to historical tax discussions with the Oil Taxation Office that typically has been accumulated through the acquisitions back both with Hess Norway and also BP Norway. So 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 Schjott-Pedersen from ABG Sundal Collier. Please go ahead.
Karl Fredrik Schjott-Pedersen
Congratulations on your discovery on the NOAKA area. Just trying to get grips on the economics of such a discovery relative to the full area that opened, so I guess if you could shed some light on, in broad terms, how would the breakeven levels of a discovery of this type – I know you don’t have the specifics on this discovery, but in general terms, discovery on this type of asset, the breakeven of the entire PQ concept?
Well, it’s of course a bit speculative to generalize on development concepts and related drilling activities and breakevens. But I think I’ll reiterate what we’ve stated previously and after the PQ without the Liatarnet discovery. We’ll have a breakeven that was hovering around $35 per barrel with the OpEx per barrel down at the $3 to $5 range. And of course, the more volume you put into such PQ, then of course, the breakeven 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 reservoir. So there’s, of course, a really different impact whether this ends up as $80 million or $200 million, if I’m going to be really generalistic. But you should expect Ærfugl to have a downward progression of the breakeven when you include discoveries of this magnitude.
Karl Fredrik Schjott-Pedersen
And when you’re looking at the ongoing discussions with Equinor, how would, in your view, structure contribution to resource in the area as a whole that of the power of discovery or – and the negotiations in your favor?
Again, I think I’ll refrain I’ll refrain from commenting on how this will impact the discussions on area solutions, Karl Fredrik. I’m sorry about that.
Karl Fredrik Schjott-Pedersen
All right, that’s okay. Thank you.
We’ll take our last question from the line of Eddie Spence [ph] from Bloomberg. Please go ahead.
Hi guys. Congratulations on the discovery. I just wanted to ask about the increase in CapEx. It’s not that normal at the moment for oil companies to be doing so, especially given the kind of volatility we’ve seen over the past year. Is that – is there a particular reason you guys are sort of setting yourselves apart?
David Torvik Tonne
Yes. Let me just reiterate that. So the total spend level doesn’t increase. So 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. So it’s not an increase in total spend, but it’s just a shifting between buckets of costs.
Okay, thank you very much.
Okay. Is that the last question, operator?
We have one last question waiting for – yes, we have one last question, sir. Would you like to take this one?
Absolutely. Let’s do one last question. It’s almost summer.
Thank you. It’s James Thompson from JPMorgan. Please go ahead.
Great, thank you very much. Much appreciated. I just wanted to go back to one of your comments in your presentation on Skarv, if that’s the right term. 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 split between the amount of gas you’re injecting? Or is this just a short time frame? And sort of what’s the value proposition for Skarv by doing this – by having this completion tactics? That will be great. Thanks.
David Torvik Tonne
Yes. Look, we have actually been reassessing or reevaluating the drilling strategy on Skarv for almost one year, 1.5 years now, where the strategy has been to inject more of the gas in the early phase and thereby increase oil production. And then, of course, subsequently, produce back all that gas and sell it to the market. 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 the fuel and gas injectors.
But now we are 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. So 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.
And 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. So theoretically, you’re increasing [indiscernible]
I think you dropped off there a bit. Sorry, I didn’t get the last question.
Sorry. Just to reiterate, it sounds like you’ve got quite a lot more flexibility in terms of how you produce Skarv in the next few years on that basis. Will that also fold into as good as well?
Yes. AErfugl has – don’t really have the amount of liquids that the Skarv development has. Remember, Skarv is several different segments with different geos, different water and gas distributions. So here, we’re basically redistributing gas from high-gas parts of the field and into high-oil parts of the field and then increasing oil production as we’re maintaining mass balance in those segments. When you introduce AErfugl, you have more gas, of course, but we are currently gas-constrained. So it won’t really impact the production strategy over the field.
Thanks very much.
And with that, I think we…
Thank you. Please go ahead with the closing remarks.
Okay. Thank you. And with that, I think we conclude the Q2 presentations. Thank you to everybody, both here at Fornebuporten and also 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.