Earnings Call: Q3 2019

Oct 22, 2019

Okay. Good morning, everyone, and welcome to this Aker BP Third quarter 2019 presentation here at Vongerboepoten. 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 start up 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 means 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 start up 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 Skav area, a successful start of the Fosk test producer in the Alvheim area. So let me start with Johan Saldrup. As you all know, the Johan Saldrup field came on stream on October 5th this year and the first oil has now arrived at the Monsta plant. We are pleased to see that the start of production and the ramp up is progressing well and the first cargo of 1,000,000 barrels will be shipped later this week. Johan Sverdrup represents 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 to the Monsta terminal through Norway's longest and largest oil pipeline. And in total, of the 50 years of production, the value, the income rather, is a staggering NOK1430 billion. And finally, with only 6 70 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 displeased 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 Vardal in Norway and Dragados in Spain. Utility and living quarters at Stord, Baiklaana and KBR with support from Larvik. Rises and processing platforms built by Samsung Heavy Industries in South Korea, drilling platform engineered and built by Able with support from Numu and the 22,000 ton drilling platform, the 26,000 ton processing platform and the 18,000 ton 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 NOK60 1,000,000,000. 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 20,000,000,000 has been awarded and this time 85 percent 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 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. 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 Fosk test production has commenced. This test is providing us with valuable information, which will be incorporated both in the planning process for the Fosk and for the Foskular discoveries. The production so far has been rather encouraging and the Alvheim FPSO has proven perfectly capable of dealing with the FOSC crude quality. And in addition, the multilateral technology applied on Fosk is showing encouraging production performance. It's worth mentioning that the Fosk 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 operations 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 geopilots around Alvheim to gather more information and to derisk new infill targets. The results are encouraging and we're 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 1 of the mid water arches at Alvheim. As a consequence, we had to shut in Wilje 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 Alfheim system enabled by digital optimization tools. We established a task force together with resources from Subsea 7, Deep Ocean and TechnipFMC and were able to secure, diagnose and repair the Midwater 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 exist 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 Walhalla. We are drilling much faster than planned and have achieved significantly longer reservoir sections than anticipated, which bodes well both productivity and for reserves maximization from these wells. We have also expanded the drilling scope and added at least 2 additional wells to the 6th initially planned. And we are currently drilling the 3rd well on Waalal 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 Waalal 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 a 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 on Waller Westbank 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 the Valhall is now on the verge of a significant production growth over the quarters as more wells are stimulated and will come on stream. 2 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 Q3. 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 also start to see positive effects of our optimization efforts driven by digital innovation on the production at These are small steps made 1 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 the In September this year, the Norwegian Environmental Agency, NEA, carried out an audit at the Iver Orsen 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 start up of production in late 2016. Unfortunately, the reported discharges had exceeded their original discharge 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 within the deadline of 1st November. The company has also initiated an internal investigation to look into the monitoring and following up of this charge permit and the findings of this investigation are already being implemented. Still, it's important for me to say that since the start up in late 2016, AKABI P has been openly reporting all these charges from the Ivarossen 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 used 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 Skav. Skav has continued the impressive performance we saw in Q2 with a production efficiency of a staggering 98%. Phase 1 of the airfield 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 Christmas trees are close to completion. And we remain on track for production in Q4 next year. For Phase 2 of Afl, 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 Skav 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 and the SREP discoveries represent roughly 100,000,000 barrels gross resources located within the catchment area of Skav. In fact, Sreck is only 14 kilometers away from Skav. If I'm not much mistaken, you can actually see the drilling rig just above the FPSO turrets 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 Hafill Phase 1 and 2, Alvenur and Alvenurrest and Sreck as possible oil contributors. And then we'll fight hard for into Skow 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 Triassic 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 Taiaasik as well has significant resource potential, but today we have limited data. In addition to the new Ula wells, at Tamba, which is a satellite tie in to Ula, we are performing wireline operations both to add production and to gather data related to new site track that is planned to be drilled in the second half of twenty twenty. 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 Toromba 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 Tamba 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 for ULA and extensive studies are ongoing on the various pieces of this puzzle and will 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's significant improvement potential. On Skou, this has skillfully been tested and we've analyzed the energy use, the energy consumption and production in the different processes and has been able to reduce the energy consumption with approximately 3.4 megawatts through 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 Nuaka, 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 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 Liatona 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 250,000,000 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 ourselves a target to find as much oil as we produce 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 number 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. Thank you, Karl, 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 Q3, we produced 146,000 barrels per day. And contrary to the last two quarters, we experienced an underlift in the 3rd 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 2nd quarter. This resulted in total petroleum revenues of SEK 721,000,000. If we move on to the income statement, adjusting petroleum revenues for other income, get a total income of SEK 723,000,000. Production costs were SEK 167,000,000 dollars and remember this refers to the cost of sold volumes. The production cost related to the produced barrels amounted to 177 $1,000,000 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 3rd quarter. Exploration expenses amounted to SEK70 1,000,000 in the quarter, SEK42 1,000,000 of which is related to dry well cost. And then in addition, we spent roughly $28,000,000 on seismic, GNG and field evaluation combined. As planned, the activity level was high also this quarter with a cash spend of 144,000,000 in exploration related activities. Summarizing the items discussed so far gives us an EBITDA of SEK 480,000,000. Dollars Depreciation in the quarter was $206,000,000 or $15.3 per barrel. The increase from the Q2 was both driven by the higher production volume, but also an increase in 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 SEK78 1,000,000. As in the Q1, the impairment is specifically related to the Ula area and is mainly driven by lower commodity prices and some rephrasing of production from the future sub projects in the area. Deducting depreciation and impairment, we get an operating profit of 196,000,000. Net financial expenses was 53,000,000 and profit before tax ended at 143,000,000. Taxes amounted to 186,000,000 and out of these 186, minus 90 $2,000,000 was the current tax arising in the quarter. Dollars 274,000,000 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 106,000,000 which is in line with our previous guidance. Thus, net loss in the 3rd quarter ended at NOK 43,000,000. As previously discussed, the effective P and L tax rate in any given quarter is highly affected by the change in FX rates and impairments. As you know, the P and 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 reconciled. 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. Now 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 kronor 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 kronor. 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 dollar is strengthening and a reduced tax expense when the dollar is weakening. In the Q3, 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 SEK 314,000,000 in the 3rd quarter. We had additions of $492,000,000 where investments at Valhall, Alvheim and Johan Sverdrup made up roughly 75%. And then depreciation of PP and E amounted to 178,000,000. Calculated tax receivables were roughly 16,000,000 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 220,000,000, which is the sum of net income, dividends and the sale of treasury shares for the employee share program. Deferred tax increased by SEK 288,000,000 and this is mainly made up of an increase of SEK 45,000,000 related to the difference in accounting versus tax depreciation, an increase of NOK 109,000,000 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 100 and 35,000,000. Bonds and bank debt increased by 305,000,000, where of NOK 217 has been reclassified from long term to short term bonds. Tax payables decreased by roughly NOK244,000,000 giving a balance of NOK195,000,000. This can be divided into NOK 5,000,000 related to the income year 2019, minus NOK 25,000,000 related to prior period adjustments and the netting of the tax receivables and then NOK214 million related to the accrual for uncertain tax positions. In sum, total equity and liabilities amounted to SEK11.7 billion at the end of the quarter. Looking at Q3 cash flows, you can see that we started the Q3 with $102,000,000 of cash. And then during the quarter, we do debt of $315,000,000 and then cash flows from operations amounted to 4.88 and then the tax payments was as mentioned 106. Cash flows to investments was 585,000,000, of which the main contributors were 435,000,000 in investments in fixed assets, including 44,000,000 of capitalized interests, 115,000,000 in exploration and then $35,000,000 in Dcom and P and A. Lease payments amounted to 32,000,000 of which 26,000,000 was related to CapEx activities. And then lastly, dividends amounted to 187,500,000. Then at the end of the quarter, our cash balance was 5,000,000. The book value of net interest bearing debt excluding lease debt was roughly 2,900,000,000 and we had 2,900,000,000 of undrawn capacity on our $4,000,000,000 bank facility. This gives a leverage ratio of net debt over EBITDAX of roughly 1.2. As already touched upon, the tax payable at the end of the Q3 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 twenty nineteen and the estimated amounts for the 3 installments for the first half of twenty twenty. The remaining installments to be paid in 2019 are fixed, but the installments to be paid in the first half of twenty twenty, 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 if we see cash tax as being less than half of what we paid in the second half of twenty nineteen. 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 155,060,000 barrels per day. In the 1st 9 months, we produced on average 144, and due to the delayed stimulation and startup of new wells at Valhall, which has been covered by Karl, we ended Q3 a little bit behind plan. Now that Johan Sverdrup has started and we expect new wells at Vallaharl to come on stream, our production should increase sharply in the Q4. 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 Q2 presentation, we adjusted CapEx guidance slightly when we shifted scope from abandonment to production drilling. As CapEx in the Q3 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 Liatorna and Froskelor and the addition of 2 new wells to the program, we updated the expected exploration spend to SEK550 1,000,000 in July. Q3, as Carlo mentioned, has been yet another successful quarter with discoveries at Erne and Sreck. And the fact that they are discoveries should add some more costs to those wells. However, we still expect to end the year at around $550,000,000 In July, we also adjusted down abandonment expenditure spend with 50,000,000. Year to date spend is 99,000,000 and we have completed more or less the full program for 2019. Therefore, we keep the guidance at around $100,000,000 Production costs per barrel is guided at $12.5 The first half of twenty nineteen 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 Q3, we have seen costs come down and when we exclude the one off related to the Alvheim Midwater 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 costs as well as ramping up low cost production from the Johan Sverdrup field in the Q4, we still expect the full year cost per barrel to end roughly at 12 $500 However, if the insurance claim related to the Midwater Arch repairs for some reason is not accounted for in the Q4, 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 $750,000,000 in dividends for the full year. I will now hand the word back to Karl for some closing remarks before we move on to the Q and A session. Thank you. 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 and A. So the key priorities, as we've already discussed, is to continue the safe and efficient operations. And 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 Waalal as fast as we possibly can. We also have a significant project execution in 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 20 20. And we have spent quite a bit of time, energy and money developing technology in the first half of twenty nineteen. We're now seeing that the implementation projects are ongoing and we plan to strengthen that activity going into the Q4 and also into 2020. And then finally, we have now several new fields and wells that need start up and we need to continue to mature discoveries ranging from Liatorna and all the way up to the Skov 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 Vonneboporten and then open on the net afterwards. Thank you, Karl Erik. It's Anders Holten from Kepler Cheuvreux. Two questions here for Obviously, we can't have a Aker BP presentation without talking about Nuaka, which I'm sure are aware of. I think we've all seen the comments from Equinor that they would prefer 2 platforms instead of a central processing help. And I guess with your comments on the various oil qualities, any comments around if that could 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 Nuaka, which if my mind serves me correctly, you were at roughly 280,000 barrels per day by 2022 on everything except Nuakaa. So any comments now, please? Thank you. Let me start with Norka. 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's coupled 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 the wrong range of technical issues. Now the fact that there are many various oil qualities actually points to our central processing platform rather than 2 platforms. And the reason is very simple. You have more utilities available at 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 the later stage. So in our opinion, from a technical perspective, the PQ is a more robust solution. And I'll leave it at that. And then 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 Sahlrup. 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. On Iver Olsen, 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? So in Aker BP, all our data is now flowing through the CONAD Data Fusion platform. That means they're being harvested from various data sources, control systems, logistic platforms, SAP or ERP platforms, etcetera, and flowing through the Konec 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 van Wijn Boorten. And I think operator, if there are questions from the participants on the call, we'll take those questions now. Thank you. We'll now take our first question from Cesar Nilfens from SD WAN Markets. Good morning, guys, and thanks for taking my questions. Two questions from me, please. First on just the Q3 production, I think it was several thoughts that you've been presenting around the Q3 production. Could you indicate what was the exit rate from Q3, I. E. What was the production like 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 work on in 2020 despite that 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? Thank you. I don't I'm not sure I got your questions, but you asked about the exit rate of from September in terms of production. And then you asked about guidance in terms of CapEx for 2020. Is that correct, Theodor? That's correct. Okay. Well, when it comes to 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, 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 average production needs to be in Q4 in order to end up at 155. 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 bit dependent on the progress in Nuaka, the guidance we had at the Capital Market Day, which I believe was in roughly in the range of 16, suddenly, that is also included in that estimate. That is to say, if you end up in a situation where the NOACA is pushed further down the road, you should expect a downward revision of those figures in 2020. We will now take our next question from Ashikanth Siroku from Morgan Stanley. Hi, everyone. I had two 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 4Q? There's no spillover effect coming into 2020. 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 Ivarazin and the additional discharge volumes. I was just wondering if whether you anticipate any financial impact, I. E. Penalties as a result of that? Thanks. Okay. So let me comment on the simulation first. Right now, we have 2 coiled tubing units working, 1 at the Walhalla field center and one at the Varhall Westbank, both specifically made to deal with simulation. We have also added what we call a single trip multi flak type of technology, which should significantly accelerate the simulation program compared to normal simulation. So on average, in a normal simulation program, 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 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 are dependent on stimulation both carrying solids and some of the chemicals lying alongside the Wallachal West Bank 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 Iverhausen, 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 not particularly high related to other comparable assets. We will now take our next question from Carl Peterson from ABG. Please go ahead. Mr. Peterson, your line is now open. Ensure that you're not on mute. Good morning, guys. 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? Yes. So if you remember back, Carl, 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. 2 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 there 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 now. And we'll come back with the updated 2020 activity program at the Capital Market Day in 2020. Okay. In terms of total size of the program, is it so that we should expect it to be around the same size as what you've shown for 2019? 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. I think you should expect roughly the same amount of capital allocated to exploration in 2020 as you've seen in 2019. Sounds good. Thanks so much. We will now take our next question from James Hosey from Barclays. Hi, good morning. Just a question on Valhall. If I look back at your Capital Markets Day presentation from January, you indicated the Valhall area averaging over 70,000 barrels a day in 2020 net to yourselves. Does that outlook still stands, flow to the wage you've experienced this year? Yes. So that question depends on how quickly the stimulation issue 20. The positive thing that we're drilling longer wells, we're 20. The positive thing 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 simulation program is normalizing. And then remember, with 2 ongoing drilling 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 Walhalla in the next few quarters. 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? Yes. I think I'll avoid guiding on very specific numbers on very specific dates 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, and that should give you an idea of exit rates in 2019. We will now take our next question from Alwyn Thomas from Exane BNP Paribas. Hi, good morning. Just to follow-up on Sverdrup. Just sort of want to get your indications on a well performance, I guess. Do you expect all 8 pre drilled wells to be online by year end? And I guess, the sort of key things you look for, how many wells you would expect to bring online 1 by 1? 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 so 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 for next year now in terms of forming a concept selection around how you bring the wider resources online? Okay. Two 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 Q3 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, Alvin. 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 2021. And obviously, as you point out, due to discoveries, the I would say, rather positive experience from Fosk in the test production, we are assessing whether we should change our activity program for 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. Okay. Thanks very much. Our next question comes from Daniel Vaughan from JPMorgan. 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 and P adjusted basis of about 50% at the full year, that you continue to expect an upgrade to investment grade by S and P shortly after the full year results? David? Yes. So S and P has indicated in their positive outlook that a potential trigger could be the startup 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. Our next question comes from Mark Wilson from Jefferies. Hi, good morning, gentlemen. Just first question on the stimulation technique at Valhall. Isn't that the fishbone technique you were talking about for the CMD? 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 need. Historically, that's been done by 2 measures, a conventional fracking stimulation in the tool reservoir and then acid stimulation in the better, more competent hot reservoir. These simulation 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 Tor 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 adaption 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. We'll need to run more tests on Fishbone. But no, it's not the same case. I got it. Really appreciate that clarity. So can you confirm then that have you completed wells at Valhalla with the single trip multi frac method? 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, etcetera, 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. Okay. Thank you very much. And finally, just an observation. I look back at the 2016 CMD, and you said that Norsca was targeting 150 1,000,000 barrels of exploration additions net to itself by 2020. So I'd say you're healthily beating that target with the 250,000,000 barrels. Well done. Thank you. I actually thought we said 250. So maybe a typo in that number. But the idea has 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 have actually been able to pull this off. It's quite a feat. It appears there are no further questions over the phone. As I understand that there is at least one person who wasn't able to connect via the phone who has sent his questions to Kjetil Bakken. So Kjetil, the floor is yours. Yes. Thank you. These are questions from Johan Charrenton of Societe Generale. First question is, what sort of timing should we have in mind for bringing SKARVE tieback candidates discovered in 3Q 'nineteen and Sreck on stream? Yes, that was 1. 2nd question, is it reasonable to assume a significant drain on working capital in 4Q 'nineteen 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? Yes. So okay. So let me touch on Skav first. On Skav, there are now several projects ongoing. So the first order of priority is to execute the Afl project efficiently and with the necessary quality. So that's first order of priority. And then we're continuing to work 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 Alvenor 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 lost assets to optimize timing, both in terms of value creation at the different tiebacks, but also taking capacity constraints on Skav into account. And then David, I think you can answer on working capital changes. Sure. So we do not expect any big changes. However, I think it's worthwhile noting also that a 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've 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 Q4. So that's roughly between SEK25 1,000,000 and SEK30 1,000,000. When it comes to the booking of it, I guess it depends on the ongoing discussions that we have with the insurance company. We do have insurance for these types 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 the situation as Karl has referred to. So that's also worth taking into consideration. Thank you. Then I think we've answered all the questions in all different channels. So I think we'll say goodbye here from Vornbo Borten and thank you for participating in this Aker BP Q3 presentation. Thank you so much.