Aker BP ASA

OSE:AKRBP

Earnings Call Transcript 2019-Q3

[Karl Johnny Hersvik, Chief Executive Officer]

Okay. Good morning, everyone, and welcome to this Aker BP Third Quarter 2019 Presentation here at Fornebuporten. A warm welcome also to those of you who follow us online or on the conference call.So let me just open with a few high-level comments on the quarter. The biggest event of this quarter is, of course, the startup of Johan Sverdrup, which we've waited for, for quite some time. I'll come back to this in more detail shortly.I am also pleased to report that all of the Aker BP operated field developments are progressing as planned. And in sum, this mean that Aker BP is on track to deliver strong production growth in the coming quarters.On the operational side, we delivered high production efficiency across the portfolio. The main challenge in Q3, however, was related to the stimulation program at Valhall, which leads to delayed startup of new wells and consequently resulted in production below plan in Q3. I will also revert to this later in the presentation.On the exploration side, this has been yet another successful quarter with 2 new discoveries in the Skarv area, a successful start of the Frosk test producer in the Alvheim area.So let me start with Johan Sverdrup. As you all know, the Johan Sverdrup field came on stream on October 5 this year, and the first oil has now arrived at the Mongstad plant. We are pleased to see that the startup of production and the ramp-up is progressing well, and the first cargo of 1 million barrels will be shipped later this week.Johan Sverdrup represent a massive value creation for Aker BP and the other partners as well as for the Norwegian society. The production from this giant oilfield will be a major contributor to Aker BP's production and earning growth in the years to come. And today, it's maybe worthwhile to sum up the experience somewhat. To us, as a partner, this has been a fantastic project. It's a great achievement. We are extremely pleased with the work that the operator has done on behalf of the partnership. And the facts are impressive. This is the largest field development on the Norwegian Continental Shelf since the 1980s. And at the peak of the construction activity, nearly 30 yards worldwide were active. When production is at plateau, it will make up 30% of all Norwegian oil production and up to 660,000 barrels of oil equivalents will flow through the Mongstad terminal through Norway's longest and largest oil pipeline. And in total, after 50 years of production, the value -- the income rather is a staggering NOK 1,430 billion.And finally, with only 670 grams of CO2 emitted per barrel of oil produced versus the average on the Norwegian Continental Shelf of approximately 8 kilos per barrel of oil equivalent, this is arguably also one of the cleanest field developments. To me, this is an IOC at its best. And our best congratulations to Equinor as an operator. But there are also others that deserve praise at this location. I'm just as pleased with the work that the many contractors have done on Johan Sverdrup. And I'm particularly happy with the fact that many of these contributors are also our alliance partners and carry out just as well work on the Aker BP project.Let me mention a few achievements. The engineering and procurement has been carried out by Aker Solutions, steel jackets built by Kvaerner Verdal in Norway and Dragados in Spain; utility and living quarters at Stord by Kvaerner and KBR, with support from Leirvik; risers and processing platforms built by Samsung Heavy Industries in South Korea; drilling platform, engineered and built by Aibel, with support from [ Limu ]; and 2 -- 22,000 tonne drilling platform, the 26,000 tonne processing platform and the 18,000 tonne living quarter topside were all lifted in 1 piece. This is the first-ever use of the single-lift installation technology by Allseas and the heaviest lift ever -- offshore lift ever executed.In sum, contracts awarded in Phase 1 amounted to more than NOK 60 billion. More than 70% of the contracts were awarded to suppliers in Norway in strong international competition. And now for Phase 2, contracts with an amount of more than NOK 20 billion has been awarded, and this time, 85% of the contracts have been placed to suppliers in Norway.In my opinion, the Johan Sverdrup project is a fundamental evidence that Norwegian oil and gas industry is still one of the best and maybe the best in the world. My deep-felt congratulations both to the operator, our partners and the contractor group.Now moving on, this slide shows the development in production and production efficiency for our portfolio. We note that the production increased, again, following the heavy maintenance season in Q2. And we also note that production efficiency is back up where we want it to be even if it's slightly impaired by less than usual well workover in the quarter, and I'll get back to the reason for that.And now let us dive deeper into each of the assets. Moving on to Alvheim, I think the key issue here is the fact that the Frosk test production has commenced. This test is providing us with valuable information, which will be incorporated both in the planning process for the Frosk and Froskelår discoveries. The production so far has been rather encouraging. And the Alvheim FPSO has proven perfectly capable of dealing with the Frosk crude quality. And in addition, the multilateral technology applied on Frosk is showing encouraging production performance.It's worth mentioning that the Frosk production started just 15 months after the discovery was made; in itself, quite an achievement.I'm also happy to report that the Skogul project remains on track for first oil in Q1 2020. All the subsea work has been nearly completed, and we plan to commence drilling operation shortly and complete them before year-end.We continue to work to maximize recovery in the Alvheim area as we've done over the last few years and have recently drilled 3 geo pilots around Alvheim to gather more information and to derisk new infill targets. The results are encouraging, and we are now in the process of maturing several new infill targets to be drilled over the next couple of years, the first already next year.Last quarter, we reported an incident of one of the mid-water arches at Alvheim. As a consequence, we had to shut in Vilje and a couple of other Alvheim wells. The overall impact on production was mitigated by swift optimization of the project -- of the production from the other Alvheim system, enabled by digital optimization tools. We established a task force together with resources from Subsea 7, DeepOcean and TechnipFMC, and were able to secure, diagnose and repair the mid-water arch within a few months. In my judgment, this is also quite an achievement, and it's probably a world's first, and it illustrates the capabilities, the courage and the commitment that exists in this organization and in our partner group.At Valhall, we are now on the final stretch of the Flank West project. The Flank West platform itself is declared ready for operation, and drilling operations are ongoing at a high efficiency. This is probably the fastest wells we've ever drilled at Valhall. We are drilling much faster than planned and have achieved significantly longer reservoir sections than anticipated, which bodes well for both productivity and for reserves maximization from these wells.We have also expanded drilling scope and added at least 2 additional wells to the 6 initially planned. And we are currently drilling the third well on Valhall Flank West.We plan to stimulate and put the first well on production before year-end. We are also continuing to drill new wells on the Valhall field center, utilizing the existing facilities and recovering existing well slots. So this means that we have 2 parallel drilling operations ongoing at Valhall at this point in time.The high drilling activity at Valhall has revealed another bottleneck in the system. The wells at Valhall need to be stimulated, either by fracking or by acid stimulation. And this is -- and due to a combination of operational issues and adverse weather conditions, we have been unable to progress this stimulation program as fast as we would have liked. This is the main reason for the somewhat disappointing production figures in Q3.Meanwhile, due to our high drilling activity and high efficiency in the drilling activity, we have now built up a backlog of more than half a dozen wells that are drilled but not stimulated. The upcoming wells of Valhall West Flank would add another 6 wells to this scope. And we have, therefore, mobilized additional resources to increase our stimulation capacity.In summary, this means that Valhall is now on the verge of a significant production growth over the quarters as more wells are stimulated and will come on stream. Two stimulation crews are now working in parallel on both the Valhall field center and the Valhall West Flank.Moving on to Ivar Aasen. Ivar Aasen performed well in the third quarter. Production efficiency improved significantly from the previous quarter, reflecting that the previous quarter was impacted by drilling operations and more power outages than we've seen in this quarter. Production was also positively impacted by the addition of 2 new wells drilled this year. The first of these wells were put on stream in late June, and the other started in late September. We're also starting to see positive effects of our optimization efforts, driven by digital innovation on the production at Ivar Aasen. These are small steps made one at a time but represent low-hanging fruits with very low CapEx and very high returns on investments.And also, I'd like to share a few words on the issue of the discharge permits at Ivar Aasen. In September this year, the Norwegian Environmental Agency, NEA, carried out an audit at the Ivar Aasen field center. A couple of months earlier, during the summer of 2019, Aker BP had submitted an updated application for discharge. The updated application was based on operational experience and reported discharge since the startup oil production in late 2016. Unfortunately, the reported discharges have exceeded their original discharge permit. And we strongly regret that an audit by NEA was necessary for the discrepancies to be identified.As some of you know, the company has received an improvement order from the NEA to investigate the environmental consequences of the discharge volumes. And we're currently working fast and systematically to address the issue raised by NEA, and we'll respond within the deadline of 1st of November. The company has also initiated an internal investigation to look into the monitoring and following up of discharge permits, and the findings of this investigation are already being implemented. Still, it's important for me to say that since the startup in late 2016, Aker BP has been openly reporting all discharges from the Ivar Aasen field. Regardless of this, we made a mistake with a permit, and we're taking this very seriously.On the positive side, the incident has inspired us to commence the development of a digital tracking system to keep an active track of use discharge permits and other issues related to chemicals on the platforms in real time, allowing optimization and sharing of those data. A prototype of this is, in fact, already being tested.Moving on to Skarv. Skarv has continued the impressive performance we saw in Q2, with a production efficiency of a staggering 98%. Phase 1 of the Ærfugl development is progressing according to plan. The offshore modification scope is ongoing. The subsea structures -- the subsea structure installation campaign is completed in this quarter, and the drilling campaign has just started and will continue in Q1 next year.The remaining technology qualifications related to trace heated pipe in pipe, and the new generation of vertical Xmas trees are close to completion, and we remain on track for production in Q4 next year.For Phase 2 of Ærfugl, we are also progressing as planned, and we are currently working on the front-end engineering and design. The final investment decision is planned to be made by the end of this year.On the exploration side, this has also been an excellent quarter for Skarv as we've made 2 new discoveries in the area.Let me remind you that our exploration strategy, which was presented at the Capital Market Day earlier this year, has been to focus, to an increasing extent, on near-field exploration called ILX. The goal is to find additional resources that can be tied back to our existing assets. The beauty of such discoveries is that they can be developed relatively quickly and at a relatively low cost as they need limited investments in new infrastructure. Such projects will also positively contribute to high capacity utilization and, hence, low unit cost at the hub.Now both the Ørn and the Shrek discoveries represent roughly 100 million barrels across resources located within the catchment area of Skarv. In fact, Shrek is only 14 kilometers away from Skarv. If I'm not much mistaken, you can actually see the drilling rig just above the FPSO turret here.Towards the end of this year, we are planning yet another exploration well in this area, the Nidhogg well, which, if successful, will add even more resources to the hopper in the area, which now seems to consist of Ærfugl Phase 1 and 2, Alve Nord and Alve Nordwest and Shrek as possible oil contributors. And then we'll fight hard for Ørn into Skarv as well.So now this hopper is starting to look rather robust from my point of view.Moving on to Ula. We are finally drilling again. The purpose of this campaign is to open up new WAG sector, which is water alternating gas, in the Ula reservoir, and thereby, rejuvenate the so far very successful tertiary oil recovery scheme.In addition, 3 existing producers need to be redrilled and recompleted due to old age. And finally, the 3 asset reservoir above the main Ula reservoir will be explored by a number of pilots, and the test gas injection well is to be drilled.The Ula Triassic as well has significant resource potential. But today, we have limited data.In addition to the new Ula wells at Tambar, which is a satellite tie-in to Ula, we are performing wireline operations, both to add production and to gather data related to a new sidetrack that is planned to be drilled in the second half of 2020. The oil from Tambar is exported to Ula utilizing a multiphase pump, probably one of the first multiphase pumps that was installed on the Norwegian Continental Shelf. As Tambar is normally not manned, uptime on this pump has been an issue since we took over operatorship.We have now implemented a predictive artificial intelligence monitoring algorithm on the multiphase pump. And to our knowledge, this is the first time such an algorithm has been implemented on such a complicated piece of equipment. This algorithm and this monitoring scheme has significantly improved availability of the multiphase pump located at Tambar and proves that our strategy of data liberation, utilizing the Cognite Data Fusion actually works.We are continuing also to work on a long-term strategy of Ula, and extensive studies are ongoing on the various pieces of this puzzle, and we'll revert with more information later.Let me spend a few moments to talk about 2 examples of digitalization and improvement work that are ongoing in the company at this point in time. The first example is about the use of data and performance data ranging from equipment data to operator data. This is a tool that we call Best Day, and I'll admit it's a working title, but there's nothing wrong with the product. The product is, in fact, a very advanced visualization and analytics system that allow the production engineers, operators and other interested in maximizing operation to transfer knowledge, understand best practices and quickly come up with optimization strategies and maximize production under an asset. And even if the gains are relatively small, in the range of 5% to 10%, the investment is nearly 0, and, when repeated, yields a very high return, and even better, a lot more stable production.The second task here is what we call an energy optimizer. We have carried out quite a few studies across our portfolio on how energies are being consumed and wasted in our installations. And we've come to the conclusion that there is significant improvement potential.On Skarv, this has skillfully been tested, and we've analyzed the energy use, the energy consumption and production in the different processes and that's been able to reduce the energy consumption with approximately 3.4 megawatt for a couple of issues, the first one is to match the export pressure to the pipeline pressure and also to optimize the energy use in the gas cleaning process by advanced process modeling. To put it simply, we have removed waste. As a consequence, we have reduced the annual CO2 emissions by approximately 17,000 tonnes, representing a reduction in CO2 emissions intensity of approximately 0.4 kilos per BOE. Aker BP will continue to look for similar energy efficiency measures, utilizing digital technology across the portfolio in order to reduce our emissions and cut costs even further. And in addition, a project is underway to turn the energy optimizer into a product that can be implied on any installations worldwide.Moving on. At NOAKA, there are no fundamental developments since last quarter. The discussions with the stakeholders on how to develop the area are still ongoing. Aker BP is still of the opinion that the central processing hub, the PQ concept is the best solution with regards to resource utilization and value creation, supported by the fact that this area has many accumulations of hydrocarbons of various types and by the further exploration potential in the area.In parallel with the ongoing discussions, we continue to work towards an appraisal well on the Liatårnet discovery and are now targeting a well next year to collect more information about the reservoir, the oil quality and to perform a production test.Moving on to exploration. 2019 has been a fantastic exploration year for Aker BP, and we can so far count 5 discoveries. I think it's actually also worthwhile to take a step back and look at the big picture in terms of exploration and what we set out to do. Back in 2016, we set a target of finding 250 million barrels over the next 5 years. This target corresponded roughly to the expected production volume over the same period of time. In other words, we set ourself a target to find as much oil as we produced over a 5-year average period of time. And I'm very pleased to see that we have actually surpassed this target more than 1 year ahead of time.I'm also very pleased to see how these results rank in comparison with our peers. We now rank as a clear #2 on the Norwegian Continental Shelf in terms of net resources discovered, second only to a company that is still slightly larger than us.And with that, I'll leave the floor to David to run us through the finances.

[David Torvik Tønne, Chief Financial Officer]

Thank you, Kalla, and good morning, everyone. As normal, I will start my financial review with the big picture before deep-diving into some selected details.In the third quarter, we produced 146,000 barrels per day. And contrary to the last 2 quarters, we experienced an underlift in the third quarter and the sold volumes ended at 143,000 barrels per day. Liquid prices decreased throughout the quarter, while the price of gas was quite stable. The realized average hydrocarbon price was $54.4 per barrels of oil equivalents, which is a 10% decrease from the second quarter. This resulted in total petroleum revenues of $721 million.If we move on to the income statement, adjusting petroleum revenues for other income, we get a total income of $723 million. Production costs were $167 million. And remember, this refers to the cost of sold volumes. The production cost related to the produced barrels amounted to $177 million. And the cost per produced barrel was $13.2, and this is a 14% decrease from the previous quarter. This was driven by both higher production but also reductions in operating costs, modifications and maintenance mainly at Valhall and Ula.At Alvheim, there was an increase in costs, driven by the mid-water arch repair, which is pending insurance recovery. Excluding this one-off, Aker BP's underlying production cost per barrel was $12.1 in the third quarter. Exploration expenses amounted to $70 million in the quarter, $42 million of which is related to dry well cost. And then in addition, we spent roughly $28 million on seismic, G&G and field evaluation combined.As planned, the activity level was high also this quarter, with a cash spend of $144 million in exploration-related activities.Summarizing the items discussed so far gives us an EBITDA of $480 million. Depreciation in the quarter was $206 million or $15.3 per barrel. The increase from the second quarter was both driven by the higher production volume, but also an increasing depreciation per barrel. And this is due to a change in the relative share of production from the various fields.This quarter, we recorded an impairment of technical goodwill of $78 million. As in the first quarter, the impairment is specifically related to the Ula area and is mainly driven by lower commodity prices and some rephasing of production from the future subprojects in the area.Deducting depreciation and impairment, we get an operating profit of $196 million. Net financial expenses was $53 million and profit before tax ended at $143 million. Taxes amounted to $186 million. And out of this $186 million, minus $92 million was the current tax arising in the quarter. $274 million was changes in deferred tax. The negative current tax for the quarter is mainly driven by significant taxable FX losses due to the reevaluation of dollar-denominated bonds and loans. The actual tax payment in the quarter amounted to $106 million, which is in line with our previous guidance. Thus, net loss in the third quarter ended at $43 million.As previously discussed, the effective P&L tax rate in any given quarter is highly affected by the change in FX rates and impairments. As you know, the P&L tax is not the actual tax paid in the quarter, but I still thought it would be worthwhile to walk you through an illustration of how a tax rate of 130% could be reconciliated.So on this slide, we start with the 78% tax on the pretax profit. This is then reduced with the uplift, which is a relative stable amount quarter-on-quarter, which reflects the investments made over the last 4 years and which reduces the effective tax rate by 22 percentage points this quarter due to the relative low pretax profit. The impairment of technical goodwill does not have any deferred tax associated with it; hence, this increases the effective tax rate by 43 percentage points.The other items in this chart refers to all other items impacted by the tax rate -- no, that impacts the tax rate. This is predominantly caused by currency movements. And there are 3 principal effects that comes into play. The first one is Norwegian kroner monetary items. These are currency effects that are accounted for in our income statement, but which do not impact tax as the tax accounts are in Norwegian kroner. The second one is U.S. dollar monetary items. These are currency effects that occur in our Norwegian kroner-based tax accounts, but which are not visible in our U.S. dollar-based income statement. And then thirdly, you have the tax balances. The biggest single driver of deferred tax is the temporary differences between the book values and the tax values of our assets. A stronger dollar contributes to an increase in this difference, and hence, it increases deferred tax.And then, as you can see from the chart on the right-hand side, the net effect of these other factors tend to cause increased tax expense in periods when the dollars is strengthening and a reduced tax expense when the dollar is weakening. In the third quarter, the effect was to increase the tax rate by 32 percentage points.Now if we move on to the balance sheet. Property, plant and equipment increased by $314 million in the third quarter. We had additions of $492 million, where investments at Valhall, Alvheim and Johan Sverdrup made up roughly 75%. And then depreciation of PP&E amounted to $178 million.Calculated tax receivables were roughly $16 million at the end of the quarter, but this has now been netted against the tax payable on the other side of the balance sheet.And moving to the other side. We can see that equity was reduced by $220 million, which is the sum of net income, dividends and the sale of treasury shares for the employee share program. Deferred tax increased by $288 million, and this is mainly made up of an increase of $45 million related to the difference in accounting versus tax depreciation, an increase of $109 million related to capitalized exploration, interests and actual decommissioning costs, which is expensed for tax purposes, and then the reevaluation of the tax balances, increasing the deferred tax with $135 million. Bonds and bank debt increased by $305 million, whereof $217 million has been reclassified from long-term to short-term bonds.Tax payables decreased by roughly $244 million, giving a balance of $195 million. This can be divided into $5 million related to the income year 2019, minus $25 million related to prior period adjustments and the netting of the tax receivables and then $214 million related to the accrual for uncertain tax positions.In sum, total equity and liabilities amounted to $11.7 billion at the end of the quarter.Looking at third quarter cash flows. You can see that we started the third quarter with $102 million of cash. And then during the quarter, we drew debt of $315 million. And then, cash flows from operations amounted to $488 million. And then the tax payments was, as mentioned, $106 million. Cash flows to investments was $585 million, of which the main contributors were $435 million in investments in fixed assets, including $44 million of capitalized interests, $115 million in exploration, and then $35 million in decomm and P&A.Lease payments amounted to $32 million, of which $26 million was related to CapEx activities. And then lastly, dividends amounted to $187.5 million.Then at the end of the quarter, our cash balance was $5 million. The book value of net interest-bearing debt, excluding lease debt, was roughly $2.9 billion, and we had $2.9 billion of undrawn capacity on our $4 billion bank facility. This gives a leverage ratio or net debt over EBITDAX of roughly 1.2.As already touched upon, the tax payable at the end of the third quarter for the income year 2019 is quite low. It is, therefore, natural to also comment a bit on cash tax payments for the coming quarters.In June, we set the actual amount for the 3 tax installments for the second half of 2019 and the estimated amounts for the 3 installments for the first half of 2020. The remaining installments to be paid in 2019 are fixed, but the installments to be paid in the first half of 2020, they will be adjusted to reflect the correct tax for the fiscal year of 2019.As it stands right now, both oil prices and FX rates contribute to lower payable tax for 2019. Hence, we expect to reduce the tax installments in the first and the second quarter next year compared to our previous guidance. We will revert with new updated figures in our Q4 presentation. But if FX rates and commodity prices stay at the current level, I will not be surprised to -- if we see cash taxes being less than half of what we paid in the second half of 2019. To round off my section, I will, as normal, revisit our guidance for 2019. At the start of the year, we guided our 2019 production between 155,000 and 160,000 barrels per day. In the first 9 months, we produced, on average, 144,000 and due to the delayed stimulation and startup of new wells at Valhall, which has been covered by Kalla, we ended Q3 a little bit behind plan. Now that Johan Sverdrup has started and we expect new wells at Valhall to come on stream, our production should increase sharply in the fourth quarter. Our updated estimates indicate that we will end the year at around 155,000 barrels per day, which basically represents the low end of the guiding range given at the beginning of this year. In our second quarter presentation, we adjusted CapEx guidance slightly when we shifted scope from abandonment to production drilling. As CapEx in the third quarter came in as expected and there are no major changes in our plans for the next -- for the rest of the year, we will keep this guidance as is. With the discoveries at Liatårnet and Froskelår and the addition of 2 new wells to the program, we updated the expected exploration spend to $550 million in July. Q3, as Kalla mentioned, has been yet another successful quarter with discoveries at Ørn and Shrek. And the fact that they are discoveries should add some more cost to those wells. However, we still expect to end the year at around $550 million. In July, we also adjusted down abandonment expenditure spend with $50 million. Year-to-date spend is $99 million, and we have completed more or less the full program for 2019. Therefore, we keep the guidance at around $100 million. Production costs per barrel is guided at $12.5. The first half of 2019 was, as expected, higher than the yearly average due to the maintenance activities at Valhall and Ula and including the turnarounds that we had in June. In the third quarter, we have seen costs come down and when we exclude the one-off related to the Alvheim mid-water arch repair, we see that we ended the quarter with cost in September at roughly $10.5 per barrel. As we expect to continue the positive trend on cost as well as ramping up low-cost production from the Johan Sverdrup field in the fourth quarter, we still expect the full year cost per barrel to end roughly at $12.5. However, if the insurance claim related to the mid-water arch repairs, for some reason, is not accounted for in the fourth quarter, then you can expect to add another $0.50 per barrel to the production cost for 2019. Lastly, we still plan to pay in total $750 million in dividends for the full year. I will now hand the word back to Kalla for some closing remarks before we move on to the Q&A session. Thank you.

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you, David. So just a short glimpse on the priorities ahead to put this into context and to round off before we do Q&A. So the key priorities, as we've already discussed, is to continue the safe and efficient operations. A key focus area for us in the next quarter, will, of course, be to get the stimulation program back to where we want it to be and to ramp up production at Valhall as fast as we possibly can. We also have a significant project execution hopper, both in the late stages and in the early stages, and the new discoveries have added more work to that project hopper, so we're continuing to work on efficient and excellent project execution. In the improvement area, the momentum have picked up in the quarter, and we'll focus on keeping that momentum high into Q4 and into 2020. And we have spent quite a bit of time, energy and money developing technology in the first half of 2019. We're now seeing that the implementation projects are ongoing, and we plan to strengthen that activity going into the fourth quarter and also into 2020. And then finally, we have now several new fields and wells that need startup, and we need to continue to the mature discoveries ranging from Liatårnet and all the way up to the Skarv discoveries and future tiebacks. So there are plenty of work to be carried out in Q4 and a very highly motivated management team here at Aker BP. So with that, I think we'll open for questions, and I think we'll start with those who have actually made the effort and come here to Fornebuporten and then open on the net afterwards.

[Anders Torgrim Holte, Equity Research Analyst]

It's Anders Holte from Kepler Cheuvreux. Two questions if I may. Obviously, we can't have a Aker BP presentation without talking about NOAKA, I'm sure we're all aware of. I think we've all seen the comments from Equinor that they would prefer 2 platforms instead of a central processing hub. And I guess with your comments on the various oil qualities, any comments around if that would make any sense? And if you were to go for it, what would be the impact on your long-term guidance? And then while we're on to the guidance, I saw that you -- despite your side of being early on, you were pointing towards the lower end of the scale. And I guess, any comments what that would mean for your medium-term outlook, excluding NOAKA, which, if my mind serves me correctly, you're at roughly 280,000 barrels per day by 2022 on everything except NOAKA. So any comments now, please.

[Karl Johnny Hersvik, Chief Executive Officer]

Let me start with NOAKA. There have been lots of discussions ongoing in that area surrounding field developments for the last almost 10 years. And lots of attempts have been made to make this area fly with floating units, with a distribution of subsea units and a central processing quarter. I don't know what have not been tried. And so far, nobody has been able to come up with a robust development solution that couple the complexity, the resource utilization with a sufficiently low breakeven to make it economic. So our position is still, from a technical point of view, that the PQ is the best solution. We haven't seen any solution that are better in terms of economic performance and resource utilization so far, not even from Equinor. So from a technical perspective, we are convinced that the PQ is the best solution. And that's our point of view from that. And then, of course, there might be commercial solutions, which is the topic that is also being discussed in the partnerships currently along with a long range of technical issues. Now the fact that there are many very various oil qualities actually points to our central processing platform rather than 2 platforms. And the reasons are very simple. You have more utilities available at the platform. You have continuous manning that is needed for pretty much continuous tieback. We're talking about 12 to 14 different oil accumulations that all needs to be tied back to the platform. And you have spare capacity in terms of weight and added utilities or processing equipment at a later stage. So to our -- in our opinion, from a technical perspective, the PQ is the more robust solution. And I'll leave it at that. And then at Sverdrup. Yes, we have always been a bit more optimistic in terms of ramp-up and in terms of production start-up. So we are pretty much on our expected profile in terms of Johan Sverdrup. So we don't see any material change as a consequence of the recent events to the short-term or nor the long-term or medium-term outlook.

[Jørgen V. Bruaset, Senior Analyst]

Jørgen Bruaset, Nordea Markets. On Ivar Aasen, the comments you made about digital efforts to monitor discharge, is that something you're driving internally? Or is that something you're doing together with Cognite?

[Karl Johnny Hersvik, Chief Executive Officer]

So in Aker BP, all our data is now flowing through the Cognite Data Fusion platform. That means they're being harvested from various data sources, control systems, logistic platforms, SAP or ERP platforms, et cetera, and flowing through the Cognite Data Fusion and then ending up in visualization and analytics tools. That's also the case here. And then, what we're trying to do now is to see if we can actually make this a generic tool to be spread across different licenses and different portfolios because it's also quite clear to us that the current solution, both in terms of reporting and also in terms of monitoring, is manual and cumbersome and prone to inaccuracies.So I think that concludes the question round from Fornebuporten. And I think, operator, if there are questions from the participants on the call, we'll take those questions now.

[Operator]

[Operator Instructions]. Well, I take our first question from Teodor Nilsen from SB1 Markets.

[Teodor Sveen-Nilsen]

Two questions from me, please. First, on just the third quarter production [indiscernible] around the third quarter production, but could you indicate what was the exit rate from Q3, i.e., what was the production like there the last week of September? My second question is related to activity in 2020 and there's, like, no doubt about that you have a lot of projects to working -- work on in 2020 despite that Sverdrup CapEx will, of course, be lower in 2020. So how should we think around 2020 CapEx? Will it be around the same level as you will report for 2019 or actually even higher?

[Karl Johnny Hersvik, Chief Executive Officer]

I don't -- I'm not sure I got your questions, but you asked about the exit rate from September in terms of production. And then you asked about guidance in terms of CapEx for 2020. Is that correct, Teodor?

[Teodor Sveen-Nilsen]

That's correct.

[Karl Johnny Hersvik, Chief Executive Officer]

Okay. Well, when it comes to the exit rate, let me put it like this. When we -- 2 months before year-end goes out and say that we have updated the guidance with 155,000. That means that the production performance that we're seeing in the latter end of Q3, and also now going into Q4, is in line with that estimation. And then, of course, you can make the math yourself to end up with the -- what the average production needs to be in Q4 in order to end up with 155,000. So I won't go into specific details on week-by-week production numbers. Then in terms of 2020 CapEx. We are basically following our own plan in terms of CapEx. And if anything, a little bit dependent on the progress in NOAKA. The guidance we had at the Capital Market Day, which I believe was in -- roughly in the range of 16 -- USD 1.6 billion, is probably sufficient. If NOAKA ramps up suddenly, that is also included in that estimate. That is to say if you end up in a situation where the NOAKA is pushed further down the road, you should expect a downward revision of those figures in 2020.

[Operator]

We will now take our next question from Sasi Chilukuru from Morgan Stanley.

[Sasikanth Chilukuru, Research Associate]

I had 2 questions, please. The first thing, I just wanted some clarity on the stimulation program. You've talked about increasing the resources in order to get the stimulation program back to plan. I was just wondering, in your base case, would you have the normalization of that plan coming in in 4Q? There's no spillover effect coming into 2020? You are just trying to see if this in itself affects the ramp-up of the Valhall West Flank ramp-up in 2020 itself? The second one was regarding the Ivar Aasen and the additional discharge volumes. I was just wondering if whether you anticipate any financial impact, i.e., penalties as a result of that.

[Karl Johnny Hersvik, Chief Executive Officer]

Okay. So let me comment on the stimulation first. Right now, we have 2 coil tubing units working, one at the Valhall field center and one at the Valhall West Flank, both specifically made to deal with stimulation. We have also added what we call a single-trip multi-frac type of technology, which should significantly accelerate the stimulation program compared to normal stimulation. So on average, in a normal stimulation program, we will use about 1 frac every second day, whereas a single-trip multi-frac is actually in the range of 2 to 5 fracs every day. So we expect a quite rapid normalization of the stimulation program as the -- this strategy comes into play. So the unknown factor that will impact the Q4 in terms of stimulation is, of course, the weather conditions because we're dependent on stimulation, both carrying solids and some of the chemicals lying alongside the Valhall West Flank and the field center. And of course, this can't be carried out over a certain wave height in order to ensure the HSE performance and the integrity of the installations and the vessel itself. So the only unknown factor in terms of how rapid that normalization will be is the weather conditions. I think we're now set up to normalize this situation extremely quickly if weather permits. And I can't really guide on the weather. Then in terms of Ivar Aasen, we expect limited, if any, financial impact from the current situation. So this is more about, I would say, our ability to track our own performance. And as I said, we've been openly disclosing all these volumes and they're not particularly high related to other comparable assets.

[Operator]

We will now take our next question from Karl Pedersen from ABG.

[Karl Fredrik Schjøtt-Pedersen]

I just wanted to congratulate you on the strong exploration performance for this year and trying to get a grip on your plans going ahead. So you continue to have the high focus on the ILX exploration wells, and how are the prospects lined up for 2020 and strategy thereafter?

[Karl Johnny Hersvik, Chief Executive Officer]

Yes. So if you remember back, Karl, to the Capital Market Day in January this year, we presented an activity program, which we have now added 2 operated wells to in 2019. Two of those wells has actually moved from the 2020 program and into the 2019 program. As a result, we are actually in the process right now of putting together the final touches on the 2020 program. So the question we're struggling with -- not struggling, but we're working on now is the balance between the growth prospects and the ILX prospects because we try to find an ideal timing so that we drill these exploration wells when the volumes are needed in the hopper and not earlier. Because if they're -- if we drill an exploration well that make a discovery close to one of these field centers, and we need to wait 5 years in order to get production capacity to tie it in, that's a waste of capital. And that's the assessment that is going on right now, and we'll come back with the updated 2020 activity program at the Capital Market Day in 2020.

[Karl Fredrik Schjøtt-Pedersen]

Okay. In terms of total size of the program, so that you should expect it to be around the same size as what you've shown for 2019?

[Karl Johnny Hersvik, Chief Executive Officer]

If you also remember back to the Capital Market Day, we showed a pretty flat prognosis for exploration spend, going from 2019 and into 2020 and then somewhat declining into the mid-'20s. So I think that's pretty much unchanged. And I think you should expect roughly the same amount of capital allocated to exploration in 2020, as you've seen in 2019.

[Operator]

We will now take our next question from James Hosie from Barclays.

[James William Hosie, Research Analyst]

Just a question on Valhall. If I look back at your Capital Markets Day presentation from January, you indicated Valhall area averaging over 70,000 barrels a day in 2020, net to yourselves. Does that outlook still stand following the delays you've experienced this year?

[Karl Johnny Hersvik, Chief Executive Officer]

Yes. So that question depends on how quickly the stimulation issue is normalized. And as I said, the remaining unknown factor right now is the weather conditions going into 2020. The positive thing is that we're drilling longer wells which have more reserves, and we're drilling them quicker than ever before. And that means that we're continually adding to that well hopper with now about 6, maybe 7 wells that are drilled and not stimulated and put on production. So the production volume going into 2020 and the average in 2020 will depend essentially on how this stimulation program is normalizing. And then remember, with 2 ongoing drilling operations, we are roughly putting 1 well into that hopper, or 1.5 well into that hopper every second month. So that means that on Valhall West Flank, we will continue to drill these wells, and they're roughly about a month apart. And then slightly more at the field center, which have a less performing rig and an older drilling installation. So there is no shortage of new wells coming on stream on Valhall in the next few quarters.

[James William Hosie, Research Analyst]

Okay. That's clear enough. Could you give us an idea of what you think the exit rate for Valhall will be at year-end?

[Karl Johnny Hersvik, Chief Executive Officer]

Yes. I think I'll avoid guiding on very specific numbers on very specific deals on each of these fields. And I'll refrain from commenting specifically. But again, as I said, if you run the math across the numbers that have now been disclosed for the different fields, you can also calculate what the different field centers need to contribute to get to 155,000, and that should give you an idea of exit rates in 2019.

[Operator]

We will now take our next question from Alwyn Thomas from Exane BNP Paribas.

[Alwyn Thomas, Analyst of Oil and Gas]

Just a follow-up on Sverdrup. Just wanted to get your indications on early well performance. And I guess, do you expect all 8 predrilled wells to be online by year-end? I guess, the sort of key things you look for, how many wells you would expect to bring online one by one. And I guess, some of the -- some indications of performance that you've seen per well so far would be helpful. I guess, also moving forward into sort of next year's plans, the discoveries you've made do give you a lot of options for next year in terms of how you -- because I'm quite interested to see how you think about prioritizing those options and in particular, following some additional successful exploration in the Frosk area. What are your plans there for next year now in terms of performing a concept selection around how you bring the wider resources online?

[Karl Johnny Hersvik, Chief Executive Officer]

Okay. They're 2 very good questions. So in terms of wells, let me just say that we're really happy about the activities that the operator has been carried out to ramp up production from the start of our production. And then Equinor is doing their Q2 presentation on Thursday, I think. And I'm sure they'll provide a sufficient amount of details on both wells, performances and ramp-up profile. So I'll leave that to the operator in 2 days, Alwyn. When it comes to prioritization, this is a very timely discussion, and we're in the middle of that process now as we are discussing budgets and activity programs for 2020 and 2021. And obviously, as you point out, due to discoveries, the, I would say, rather positive experience from Frosk in the test production, we are assessing whether we should change our activity program from -- for 2020, both in terms of wells to be drilled and the utilization of our drilling rigs, but also in terms of where we prioritize our resources from an early stage perspective. So that work is currently ongoing. And we're, of course, trying to optimize both in terms of production, in terms of cost per unit across the different field centers, but also in terms of technology application and technology readiness. So we'll come back in the Capital Market Day in 2020 with a detailed overview of the both existing prioritization, but also the revised prioritization now being worked.

[Operator]

Our next question comes from [ Daniel Vaughan ] from JP Morgan.

[Unknown Analyst]

Could you just confirm that now that Johan Sverdrup is online faster than expected and you should get an FFO to debt position on an S&P adjusted basis of about 50% at the full year, that you continue to expect a upgrade to investment-grade by S&P shortly after the full year results?

[Karl Johnny Hersvik, Chief Executive Officer]

David?

[David Torvik Tønne, Chief Financial Officer]

Yes. So S&P has indicated in their positive outlook that the potential trigger could be the start-up of Johan Sverdrup. I don't think I should speculate if they are to upgrade us now or wait. We'll just have to wait and see what the rating agency does.

[Operator]

[Operator Instructions] Our next question comes from Mark Wilson from Jefferies.

[Mark Wilson, Oil and Gas Equity Analyst]

Just first question on the stimulation technique at Valhall. Is that the Fishbone technique you were talking about at the CMD?

[Karl Johnny Hersvik, Chief Executive Officer]

No, that's a different discussion. So again, let me try to put some perspective into it. At Valhall, because of the high porosity but low permeability of the chalk, we need to stimulate these wells to get the production we needed. Historically, that's been done by 2 measures, a conventional fracking stimulation in the cool reservoir and an acid stimulation in the bit more competent, the hot reservoir. These stimulation techniques have obvious restrictions, both in terms of taking time, but also in terms of limiting the well concept that can be used. So currently, we can't, for example, pump 15 fracs through 2 or 3 branch wells. So the Fishbone technology, which was tested earlier this year, was an attempt to mitigate this issue and allowing us to drill multilateral wells into the dual formation. So that's one way of addressing the problem, and that was, as a technology test, successful but needs further technology improvement because before it can be put into production. Another way of optimizing that production is by increasing the productivity in the stimulation process itself. And here, we're utilizing something called single-trip multi-frac, which is an adoption of a technology used on parts of the onshore U.S. portfolio. Particularly if you have deep, that is talking about 30,000 feet wells, which need a significant amount of fracking rather than a specific amount of fracs, right? So these are big jobs, pretty big jobs. And this will actually just increase the productivity of the fracking job itself. So we are following 2 angles of attack here. So the first one is to try to develop technology that avoid fracking altogether. And this is the Fishbone. It's one of those paths. And the other one is to maximize the performance of the conventional fracking technology by just improving the productivity of that frac operation itself, which is the current production technology that we're utilizing. So we'll come back to Fishbone, and we'll need to run more tests on Fishbone. But no, it's not the same case.

[Mark Wilson, Oil and Gas Equity Analyst]

Okay. Really appreciate that clarity. So can you confirm then that have you completed wells at Valhall with the single-trip multi-frac method?

[Karl Johnny Hersvik, Chief Executive Officer]

We have so far this year pumped about 20 single-trip multi-frac jobs. So the technology itself, we know work. The issue we've had is more operational in nature as this equipment has been so far only used for onshore work. And now we're moving it offshore. So we've been spending quite a bit of resources redesigning the tools, the way we operate the procedures, et cetera, to make it adaptable for offshore conditions rather than onshore conditions. So we know that the technology works. Now we just need to find an operational procedure that makes this stable.

[Mark Wilson, Oil and Gas Equity Analyst]

Okay. And finally, just an observation. I look back at the 2016 CMD and you said that Norsk was targeting 150 million barrels from exploration additions net to itself by 2020. So I'd say you're healthily beating that target with the 250 million, well done.

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you. I actually thought we said 250 million, so maybe a typo in that number. But the idea is actually, at least internally, always been to replace all these reserves that we produce over the 5-year average by exploration alone. And I must say I'm really proud of the exploration team who've actually been able to pull this off, it's quite a feat.

[Operator]

It appears there are no further questions over the phone.

[David Torvik Tønne, Chief Financial Officer]

Yes. I understand that there's at least 1 person who wasn't able to connect via the phone who has sent these questions to Kjetil Bakken. So Kjetil, the floor is yours.

[Kjetil Bakken, Vice President of Investor Relations]

Yes, thank you. These are questions from Yoann Charenton of Societe Generale. First question is, what sort of timing should we have in mind for bringing Skarv tieback candidates discovered in 3Q '19, Ørn and Shrek, on stream?

[Karl Johnny Hersvik, Chief Executive Officer]

Yes, that was one.

[Kjetil Bakken, Vice President of Investor Relations]

Second question, is it reasonable to assume a significant drain on working capital in 4Q '19 as your production jumps? Any color on that matter would be welcome. And then the third question is, can you touch upon insurance recoveries, i.e., timing and associated amount in relation to MWA repairs at Alvheim?

[Karl Johnny Hersvik, Chief Executive Officer]

Yes. So okay. So let me touch on Skarv first. On Skarv, there are now several projects ongoing. So the first order of priority is to execute the Alve project efficiently and with the necessary quality. So that's first order of priority. And then we're continuing to work on the -- on the necessary capacity, both in the subsea spread, but also at the FPSO in order to do further tiebacks. And that is 2 very different discussions when it comes to oil and it comes to gas. So this needs to be worked with the different operators of these tiebacks. And then, of course, we have the Alve Nord acquisition that we did with Total a bit earlier this year, which are also put into the hopper. So I think I'll say that, of course, this is Aker BP, we want to do this as quickly as we possibly can. And we are discussing with the operators of these 2 last assets to optimize timing both in terms of value creation at the different tiebacks but also taking capacity constraints on Skarv into account. And then, David, I think you can answer on working load capital changes?

[David Torvik Tønne, Chief Financial Officer]

Sure. So we do not expect any big changes. However, I think it's worthwhile noting also that the big part of the variations in working capital is accrued income, which is depending on the lifting schedules. So of course, depending on how the lifting happens within each of the quarters, you could see swings; and as the production increases, you could potentially see more swings. When it comes to the insurance, so I think I indicated the size of that when I indicated the impact -- potential impact on the production cost, if we're not able to book that in the fourth quarter. So that's roughly between $25 million and $30 million. When it comes to the booking of it, it -- I guess, it depends on the ongoing discussions that we have with the insurance company. We do have insurance for these type of situations. And then I also think it's worthwhile noting that the number that I referred to does not include any loss of production insurance, so that could potentially be something in addition. However, we do have -- been able to balance some of that potential production loss at Alvheim during this situation, as Kalla's referred to, so that's also worth taking into consideration.

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you. Then I think we've answered all the questions in all different channels. So I think we'll say goodbye here from Fornebuporten, and thank you for participating in this Aker BP Q3 presentation. Thank you so much.