Earnings Call: Q2 2020

Jul 14, 2020

Welcome everyone to this Q2 2020 presentation by Aker BP ASA. My name is Kjetil Bakken. I am the Head of Investor Relations in the company. And the presentation today will be given by our CEO, Karl Johan Eli Haszviig and our CFO, David Toner. And without further ado, I leave the floor to Karl Johnnie. Thank you, Cetel, and thank you to everyone online for joining Aker BP's quarterly presentation. And this time here from Vornenbeuk, together with me, I have CFO, David Turner, and we will take you through the presentation and subsequently answer questions in the end. The first half of twenty twenty has been extraordinary in many ways, mostly due to the COVID-nineteen situation. At Aker BP, we have implemented a wide range of measures to minimize the risk to people and operations. And I'm happy to say that the company in yet another quarter has delivered strong operational performance and record high production. Despite the challenging environment, the quarter has had other real highlights as well, including the petroleum tax changes approved by the Norwegian Parliament. These changes provide the oil and gas companies in Norway with a liquidity boost and improved project economics and thereby unlocking profitable investments for the company but also for the Norwegian society at large. We responded to these changes quickly and submitted a plan for development of operations for Hod just a few days later. And I'm also very pleased with the positive development for Norka, where we have now reached an agreement on the commercial framework with our partners, paving the way for a coordinated development of the entire area. So despite the challenges that have been thrown our way during the quarter, we have definitely, as a company, been building momentum for more value creation in the future. Let me share a few words on how we are dealing with the COVID-nineteen situation to kick the presentation off. Our priorities with regards to COVID are pretty simple. The first priority is, as always, to keep our people safe, and the second priority is to keep production running and ensure business continuity. Operationally, this means that we have implemented a series of practical measures. The offshore manning has been reduced to a level which is needed to perform safe production. We have implemented strict travel controls to keep the virus away from our installations, and we have established procedures for installation and for isolation and quarantine to handle potentially infected personnel. Our onshore personnel has largely been working from home, and we have implemented mandatory testing for all offshore personnel traveling offshore. The testing procedure for our offshore personnel is actually what you can see on the left hand side of this left hand of this slide. And note that the refrigerator is not filled with coke. It's filled with testing equipment. These measures have worked well so far. Our people remain safe, and our production has continued uninterrupted. In fact, production efficiency has continued at high levels, although a notch down from the previous quarter, mostly due to necessary maintenance and as a function of production curtailments in June. Going into the operational performance, a few more details. We delivered strong HSE performance, although our safety record shows 1 serious incident in the quarter. This incident was a benchwise that fell off a workbench and led to a leg injury. The company continues to work systematically to maintain safe and reliable operations as activity returns to more normal levels. For the Q3 in a row, we have now set new production records, driven by a continued ramp up at Johan Sverdrup and strong performance across the rest of our portfolio. Production costs ended at $9.1 per barrel in the quarter. The slight increase in production cost in Q2 was mainly driven by a planned well maintenance campaign at Ula. And adjusting for this well maintenance, the underlying production cost was below $7 a barrel, and we therefore maintain our guidance of $7 to $8 per barrel on average for the full year. Our CO2 emissions ended up below our targeted five kilograms per barrel, firmly positioning Akabipi among the very best oil companies globally with regards to CO2 emissions. And although the activity has been reduced as a protective measure due to the COVID-nineteen situation, this does not mean that there has not been a lot of activity going on across the portfolio. Most of these were activities that were planned and in execution when the COVID situation hit us, and we have executed them safely during the quarter. At Alvheim, Skogel is now on production and performing very well. Thanks to Skogel, production from the Alvheim area increased from Q1 to Q2. We are also drilling the Kamilian infill mid well with Diepsi Norkap, and first oil is expected during the Q4. Development of the Fosk discovery has been further matured and the partners agreed to enter the concept select phase during the quarter. The ambition is to close the Concept Select phase by the end of this year. At Iverossen, we have increased the water injection in order to increase the reservoir pressure. Production efficiency was at a stellar 98% in the quarter. In August, we planned to spud the first of 2 new IOWA wells, and we are also continuing to mature the Hanns development. Skau is also one of the assets with higher production in Q2 compared to Q1 and with an incredibly high production efficiency. The Afrold project is progressing well, and the first well from Afrold Phase 2 was put in stream in April. Phase 1 start up is expected in the Q4 this year, and the remaining Phase 2 wells is expected to come on stream in the Q4 next year. At Dula, we have now completed our 4 well drilling campaign over last year. Planned maintenance also affected the production somewhat in the quarter. Drilling of the 9 wells at Val Hall Westbank is now complete and stimulation continues. The 2nd quarter production decreased due to a planned shutdown in June. At Sverdrup, the ramp up continued safely throughout the quarter, and 11 wells have now been put on stream. And in April, the oil production reached the new Phase I plateau of 470,000 barrels of oil equivalent per day. A significant event in the Q2 was the Parliament's approval of temporary tax changes and the following investment decision of the HOD development. The day after the Parliament's decision, the Aker BP flag was hoisted by workers at Kvaerner Adal, and the welding started only hours or later. The tax changes are really important for several reasons. First, they accelerate cash flows for oil companies like ourselves. This improves liquidity and after tax returns and hence stimulates investments in the downturn. 2nd, this contributes to maintaining competence and capacity in the Norwegian oil service industry. As an oil company, we are totally dependent on having access to world class oil service industry. And it's vital for us that this industry not only survives but that it actually thrives. This is the only way to secure that the industry can continue to attract competent people and remain capable and innovative. This is fundamentally a part of our philosophy that has shaped the alliance model, where we are building long term relationships with our key suppliers based on a one team culture and common incentives. Thirdly, the increased activity the increased investment activity will have positive effects for the Norwegian society at large, both in terms of job creation and in terms of increased tax revenue to the Norwegian state. And we're already starting to see the positive ripple effects of the tax changes. The HUG project, which I will revert to shortly, is expected to generate 5,000 FT feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet Es along the Norwegian coast. Feet feet feet feet feet feet feet feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet Feet For instance, Christian Kirvik, who is working at Larvik at Stord. And Larvik has been awarded a contract to build a housing module for the helideck and the helideck for the hard project. And it means that highly skilled competent workers will once again be employed. For instance, Horva Forslund, working at Kvaerner. He worked as an apprentice on the Waalal West Frank project and was offered employment at Granada Varal the day after we took the investment decision for Hod. Our job is to maximize the value of our Kbibis portfolio, but I'm also genuinely happy when we contribute to important ripple effects in the society where we operate. The HOT project is for sure an inspiring one. It's not the largest one in our portfolio, but it has important industrial implications. The HOT platform will be the first real copy on the Norwegian continental shelf. With this project, we are moving the oil and gas industry in Norway from custom design and tailoring to manufacturing. And to us, manufacturing is the only way to reap the benefits of learning effects, pushing efficiency up and costs down. This has been the main pillars of the Aker BP improvement program for years. The concept, the execution model and the organization are copied from the Waalar West Frank development. The Waalar West Frank development started production in December 2019 and set a new standard for delivery of this kind of platforms. We see room for continued improvements into the HOT project. With only 40,000,000 barrels, we're still expecting very good economics of this project with a breakeven oil price for the company less than $25 per barrel. This is key to succeed with our ambition of producing another 1,000,000,000 barrels for the Varal area over the next 40 years. During the quarter, we also reached an agreement with Equinor and Lutos on a commercial framework for a coordinated development of the Noire area. This agreement is an important milestone, and it sets the conditions for development of all the resources in the area. This will potentially unlock more than 300 1,000,000 barrels of oil and gas resources for AKABP and hence significantly contribute to the company's growth in reserves and production in the years to come. The purpose of the commercial terms between the partners is to secure an optimal and fair allocation of cost and production between the different discoveries in the area and to align incentives and ensure good integration and synergies between the different facilities and licenses. The development concept will be further optimized prior to submitting the PDO, and the partnership has an ambition to further reduce cost with an integrated contract strategy. Nuaka will be built on our field of the future concept with extensive use of digital We also intend to develop Nokka with a minimum carbon footprint powered from shore. The area is prolific with many exploration opportunities, including the appraisal of the Liaoton discovery. The infrastructure will enable tie ins of further and future discoveries. The development in the area will also have significant effects on the supply industry. Total investments are expected to be more than NOK 50,000,000,000 and the employment effect is expected to around 50,000 FT feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet feet Es in the early phase of the project, and contracts for the concept studies are expected to be awarded shortly. Our goal is to submit plans for development 2022. This concludes my operational part of the presentation, and David will now go through the financials of the quarter. David, the floor is yours. Thank you, Carla, and good morning, everyone. Aker BP's net production in the 2nd quarter was 210,000 barrels per day. This represents a new all time high for Aker BP. With an over lift in the quarter, the sold volumes ended at 230 2,000 barrels per day. Both liquids and gas prices decreased quarter on quarter and the realized average hydrocarbon price approximately 38% lower than in Q1 and ended at $27.5 per barrels of oil equivalents. Total income ended at $590,000,000 which consisted of $584,000,000 in petroleum revenues and $6,000,000 in other operating income. Now before leaving the topic of oil prices, although the average prices were low in the Q2, we have observed an improvement from April to June. The reference price for our oil sales is Platts Brent dated and normally this price is highly correlated to the front end Brent which is an indication of a very weak physical market. Towards the end of the quarter, this gap closed, providing a sign of normalization. For Aker BP specifically, realized liquid prices were positively impacted by the timing of liftings with more cargoes in May June compared to April. Using average Brent dated for the quarter as a starting point, this timing effect was roughly $3.1 per barrel. As noted in our Q1 presentation, we started to see differentials deteriorating across the various crude qualities and therefore indicated that differentials would turn negative on average for the Q2. The end result is better than many feared and the negative $1.8 per barrel in differentials was more than outweighed by the positive timing effect. The initial indications for the Q3 is that differentials are now slowly normalizing. Adjusting for NGL, Aker BP's average liquid price was roughly $30 per barrel. And if we add the tax adjusted contribution of our hedging program, the all in price was equivalent to $41 per barrel. The hedging program had a positive effect on our cash flow for the quarter. The P and L effect however was reflected in the Q1 as these options are recognized at fair value each quarter. Hence, since oil prices increased throughout the quarter, the contribution from hedging to the P and L was slightly negative. For the remainder of 2020, we have roughly 80% of the after tax value of our oil production hedged with put options at an average strike of $30 per barrel. Before I go through the results and main movements in the balance sheet, it's worth highlighting how the temporary changes in the petroleum tax system is impacting some of the line items. In short, the changes implies that oil and gas companies operating on the NCS will pay less tax short term and more later, meaning that roughly the same amount of tax is paid through the cycle. This is accomplished by accelerated depreciation for capital investments through immediate deduction in special tax of 56%, increased uplift from 20.8% to 24% now with immediate deduction in special tax. It applies to all CapEx in 2020 2021 and all CapEx related to projects with PDOs delivered by end 2022 until the year of first oil. And lastly, the tax value of taxable losses in 2020 2021 are refunded in cash through the normal tax installments. More details on this can be found in the appendix of this presentation. The accounting effects of these changes are simply put that, all things equal, tax payable will be reduced and deferred tax will increase. The increased and accelerated uplift reduces tax payable and hence the effective tax for the period. Now with that as a backdrop, let's shift focus over to the financial results. As mentioned, total income was $590,000,000 Production cost of sold volumes were 196,000,000 dollars and the production cost related to the produced barrels amounted to $173,000,000 equaling a cost per produced barrel of $9.1 Adjusted for the well maintenance mentioned by Karl, the underlying production cost was roughly $7 per barrel. Exploration expenses amounted to $50,000,000 $22,000,000 was related to the purchase of seismic and $10,000,000 dry well costs, mainly related to the Sandia well. Total cash spend on exploration activities in the second quarter ended at $59,000,000 The high other operating expenses in the second quarter was mainly due to a termination fee related to the Maersk Reacher rig of approximately 13,000,000 dollars Maersk Reacher has been an accommodation unit at the Valhall field since October 2018 and was due to come off contract in October this year. The contract was terminated early since we now have reduced the activity level at Valhall and do not need the extra bed capacity. Depreciation in the quarter was $286,000,000 or $15 per barrel. Furthermore, this quarter we recorded a reversal of prior period impairments amounting to $72,000,000 on Eberosen and $64,000,000 on Ula Tammar, in total 136,000,000. This reversal is mainly triggered by the partial recovery of short term oil prices. Net financial expenses were $27,000,000 The main reason for the decrease from the Q1 is the change in fair value of currency contracts as the Norwegian kronor strengthened during the quarter. Profit before tax was $151,000,000 and taxes gave a positive contribution of 19,000,000 dollars Now I'll come back to the details on taxes on the next slide. In summary, net profit in the second quarter ended at 170,000,000 dollars or $0.47 per share. The tax income of 19,000,000 dollars implies an effective P and L tax rate in the quarter of minus 12%. On the left hand side of this slide, we have illustrated how this to a large extent is driven by the increased and accelerated uplift introduced with the temporary tax changes, but also due to currency effects. Specifically worth noting here is that parts of the effect comes from a catch up from Q1 of roughly $40,000,000 On the right hand side, you can see that the actual tax payments in the quarter amounted to $81,000,000 representing the 5th and fixed tax installment of the taxes for the fiscal year 2019. Furthermore, this graph illustrates how the change in the tax system is causing a shift from current tax to deferred tax. As roughly $340,000,000 are moved from a deferred tax asset to a tax receivable due to accelerated tax depreciation. This is then the key driver for the change from a tax payable of $260,000,000 in the first quarter to a tax receivable of $187,000,000 in the second. Now let's move on to the balance sheet. In addition to the 3 tax lines already covered on the previous slide, I would like to highlight a couple of other line items. Other intangible assets increased by 52,000,000 dollars mainly due to the mentioned impairment reversal. Property, plant and equipment increased by 114,000,000 and we had additions of 390,000,000 where investments at Valhall, Alvheim and Johan Sverdrup made up roughly 80%. Depreciation of PP and E amounts to $253,000,000 and the reversal of impairment was 69,000,000 dollars And lastly, the sale of our ownership in Gyna Krog reduced PP and E by 91,000,000 On the other side of the balance sheet, equity was increased by 99,000,000, which is the sum of income and dividends. And bonds and bank debt increased by NOK 119,000,000. Regarding 2nd quarter cash flows, a couple of things to note in particular. During the quarter, we drew debt of $98,000,000 We received in total $55,000,000 in cash for the sale of our stake in Gyna Klog and cash flows from operations amounted to $243,000,000 before tax. This number was obviously negatively impacted by the low oil prices, but also by an increase in working capital as the over lift in the quarter with many liftings increase in accounts receivables and accrued income of roughly $100,000,000 Cash flow to investments was roughly $394,000,000 across the various spend categories with CapEx being over 90% of these and dividends amounted to 70,800,000. At the end of the quarter, our cash balance was 142,000,000. Aker BP has a track record of continuously optimizing the capital structure to ensure we have a robust balance sheet and flexibility at a reasonable financing cost. Under the current challenging and volatile market conditions, the main financial priority for Aker BP has been exactly this, to secure the company's financial robustness, to protect its investment grade credit profile and to secure future financial capacity to pursue value accretive growth opportunities. We entered the market turmoil in March with roughly $3,300,000,000 in net debt, a leverage ratio of 1.2 $4,000,000,000 in available liquidity, supported by the $1,500,000,000 bond issuance in January. Now after one of the most dramatic 4 months in the history of the oil industry in Norway, Aker BP ended the 2nd quarter with a book value of net interest bearing debt of roughly NOK3.6 billion, NOK3.7 billion in available liquidity and the leverage ratio net debt over EBITDAX of 1.5, significantly below the 3.5 covenant threshold in our loan agreement. Since the end of the quarter, we have reached another milestone with the repayment of the Detnor II Norwegian bond of NOK 1,900,000,000 issued back in 2013. Lastly, just 3 months after S and P and Moody's changed the rating outlook to negative, both agencies announced in June that they have reversed the outlook back to stable. Supported by our resilience to weaker market conditions, actions to adjust capital allocation and the supportive temporary changes in the petroleum tax system. Now we have touched upon the changes in the fiscal regime several times already today. Karl from a strategic perspective about what this means for Aker BP, the supplier industry and for the broader society in Norway. Myself, mainly regarding the accounting effects. However, more important than the accounting effects is what accelerated tax depreciation and increased uplift means for Aker BP's profitability and financial strength over the coming years. First of all, the breakeven oil prices for a typical project in our portfolio is reduced with roughly 25%. Further strengthening the profitability of an already robust project portfolio of approximately 900,000,000 barrels of 2C resources. Secondly, year 1 tax deduction for CapEx increases from 16% to 73%. For the fiscal year 2020, this means that the post tax cash outflow related to our investments is reduced with over 60%. And this is after we have added an additional $150,000,000 for investments in the generated is substantially improved in a period with planned high investments in among other the Nuaka project. This implies significantly less strain on the balance sheet to capture profitable organic growth in the coming years. Based on the temporary changes in the fiscal regime, we have estimated the 3 tax installments to be paid in the second half of 20. In the 3rd and the 4th quarter, we expect to receive a cash refund of approximately $100,000,000 $200,000,000 respectively. Furthermore, we have illustrated the sensitivity for the installments in the first half of twenty twenty one at various oil price scenarios. The prices indicated are averages for the full year 2020. Now before leaving the word over to Karl again for some concluding remarks, I will as normal quickly walk you through the latest guidance update for 2020. Production in the Q2 was somewhat above our original plans with strong performance in particular at Alvheim, Ivarossen and Skarve. Although the production curtailments will have a certain negative impact on our production in the second half of the year, due to the strong performance so far, we remain comfortable with the guidance range of 205,000 to 220,000 barrels per day. Our CapEx guidance for 2020 was adjusted to $1,200,000,000 in March, down from the original plan of $1,500,000,000 However, as mentioned at our Q1 presentation, the changes in the petroleum tax system could trigger additional investments already in 2020. This has now materialized and in June, we sanctioned the HOD project, adding an additional 150,000,000 to the CapEx program this year. The updated guidance is therefore $1,350,000,000 pretax for 2020 and post tax for the fiscal year, this equals roughly $360,000,000 with a new temporary tax system. We reduced the exploration program from 10 to 6 wells earlier this year and adjusted the estimated spend level accordingly. The updated exploration plan stands firm and so does the expected spend level of $350,000,000 pretax. Spend so far this year related to abandonment has been low. The main bulk of the planned work is related to P and A at Valhall and is scheduled to start in September. We keep the original guidance at $200,000,000 pretax. And lastly, in March, we reduced our guidance on production cost from $10 to $7 to $80 per barrel. The two key drivers for this was reduced activity offshore due to COVID-nineteen and the weakening of the Norwegian kroner to an estimated average of NOK 10 per dollar. Production cost per barrel year to date is $8.9 and the key driver for being above the average guidance level year to date is the planned well work at Ula in the second quarter. Our planned well maintenance work has now to a large extent been completed for 2020 and consequently we keep our guidance for the full year at $7 to $8 per barrel. In sum, with the performance so far this year and with these guiding figures, we estimate the company to be cash flow breakeven for the full year 2020 pre dividends at a realized oil price of roughly $25 Brent for the rest of the year. I will now hand over the word back to Karl for some closing remarks before we move on to Q and A. Thank you. Thank you, David. Thank you for a walkthrough of the financials, as usual. And I'm sure there was a lot of interest in the tax discussions. For those that are interested in even more details, the IR guys are, of course, always at your service. Now returning to the more strategic level. I must admit that the Q2 has probably been one of the more challenging events in the Aker BP history. From the start in March with the COVID-nineteen situation, the rapid deployment of a lot of mitigating measures and response both on our operations and our financials, This was a very challenging event for Aker BP. However, I'm also extremely proud to say that the organization has responded forcefully, quickly and with determination. We have kept our people safe. We have kept our operations going, and we have delivered excellent operational results in the quarter, both in terms of project execution, in terms of production efficiency and indeed in terms of production. And ultimately, we ended the quarter with realizing starting to realize an unprecedented opportunity for value creation for the Aker BP shareholders as the new tax changes take hold in Norway. This means that the hopper, the large 2C hopper that's been one of the traits in the Aker BP history has now been transformed into a fundamental and probably unique value creation opportunity. That being said, I can assure you that here in Aker BP, we will continue to work diligently to maximize shareholder value. We will continue to stay focused on our performance, to stay focused on our business and to make sure that we create all the opportunity we possibly can and turn that into value for the shareholders. Let me also remind you that while I actually went out in the organization and said Aker BP is going to come out of the COVID-nineteen situation as a stronger company than we went into the COVID-nineteen situation with. Right now, that is probably going to be true. But let me remind all of you that we're not completely out of the woods yet. And let's make sure that we continue to focus on our performance, continue to focus on our operations and maximize value creation. I wish you all a safe summer wherever you are, and I hope you stay safe in this rather challenging situation even as it starts to normalize here in Norway. So with that, we'll conclude the Q2 presentation and open up for questions. Our first question comes from Anders Holter from Kepler Cheuvreux. Please go ahead. Yes, good morning guys. Thanks for taking my questions. I have 2, if I may. First, I'd like to tap into something that was mentioned by David here on his closing remarks, that the differential between Beethoven and the prices you see on our screen is starting to close. I mean, last quarter, there was a lot of talk about the demand kind of falling through in terms of non ferocity cargoes. Do you see anything shifting in terms of the physical demand out there for crude oil, especially the crude oil that you ship yourself? And lastly, you have in the past been very evident in saying that you are in optimization any projects that have breakeven levels of of about $35 per barrel. Just wondering, has the recent COVID-nineteen effect adjusted that threshold somewhat? And if you can give me the guidance on that, that would be it. Thank you. Thank you, Anders. So when it comes to the physical market, I think the short answer is yes, that we have seen the physical market improving. As you could also see from the slide that I presented, you could see that dated Brent and then the first forward contract pricing is sort of closing in. Also when it comes to differentials on our crude qualities, we do see a normalization and the negative differentials across our portfolio that we saw in the Q2 have now normalized more into sort of neutral slightly positive environment. On breakeven levels? No, I think you're absolutely right, Anders. We've been quite clear that the sanction level on the Aker BP portfolio has been set at $25 And recently due to the temporary tax changes, we changed that down to $30 Let me remind you that this tax change does really impact other things than the financials. So as we are assessing these projects, we're continuing to assess the resource base and the risk factors and all the other parameters that are involved in the sanctioning of our project. We will take our next question from Jon Charrenson from Societe Generale. Please go ahead. Yes. Good morning, gentlemen. I would like to ask 3 questions, if possible. The first one will be on the CapEx outlook. It's clear that you have now moved away from the sanction only scenario. So would you mind providing some indication on next year's capital and possibly E and S spending trend? That would be appreciated. And then the second question would be on Uplift. Thank you for singling out the related catch up effect from Q1 on the Q2 uplift. As we are now halfway through the year and moving into a new semester, are you able to guide on the uplift for the second half of the year? And then last question, very quickly, can you touch upon the hedging policy for tax installments? Thank you. Thank you, Johan, for your questions. I'll start and then Karl can add on. When it comes to CapEx level, yes, as you mentioned, we back in March moved into sort of a sanctioned only scenario. But with the changes in the fiscal regime, we have now sanctioned the HOD and we are, of course, also evaluating other opportunities in the portfolio to sanction. It's a bit too early to guide on CapEx for 2021 yet, but I think an indication would be to go back to the capital markets update presentation and look at sanctioned only levels and then add back the CapEx for 2021 on HOD. And then we are, as I mentioned, also maturing other opportunities. So with that in total, we are probably looking at a CapEx level in the close vicinity of the updated guidance level for 2020. When it comes to uplift, So the uplift for the remaining parts of the year would be, I guess, quite similar to what we have seen in Q2 isolated. I think that's the best assumption to use. Of course, and then you can also do the math looking at the CapEx spend for the second half of the year with the new updated uplift percentages. And your last question was related to? And hedging policy, if I may, on tax installments. Do you hedge the actions, right? Yes. So when it comes to hedging on FX, we do have an active policy of hedging some of the currency exposure and we will be hedging the tax refunds continuously as they have been set. We will now take our next question from Michael Alsford from Citigroup. Please go ahead. Thank you. Good morning. I've got a couple of questions, please. So firstly, on the Wacker, you announced the agreed sort of commercial terms and given the tax changes in Norway. Could you maybe talk a little bit about where you see the breakeven that project? And given the high equity that you have in that area, do you see yourselves carrying that level of equity through to development of the project? Secondly, could you maybe elaborate a little bit more on seizing new opportunities? You've got a large resource base already. So I just wondered if you could update on your criteria for new assets, given the recent tax changes. And then just finally, understandably a lot of focus on investment levels given the tax changes, but where does that leave your ambition to regrow the dividend? Thank you. Yes. Sure. Thank you, Mikael. So when it comes to Nuakon, I think it's a bit early to guide on breakevens. On the afternoon when we announced the agreement, the commercial agreement, I was quoted in the merchant press saying that as we had a basis for our investment decision at that point in time of 35, they should expect that this also was valid for the Nuakka project, which is probably a good assumption right now. And then there is, as I also stated, a continuous improvement now in place to reduce the CapEx spend, which will impact the breakeven positively. The time line for the Novakka project is that we try to get to a TG2 level within the end of 'twenty one and then get to a PDO within the end of 2022. So there's remaining quite a lot of work on the detailed cost assessments of this new development solution before we can update the breakevens firmly. What we'll try to do is to keep the market posted on that development as we progress. Moving on to our equity. This commercial solution is basically a combination of a tariff and a CapEx contribution type of mechanism and it doesn't directly impact our equity in the area. So that means that the underlying equity of the different companies in the different licenses are unchanged. And right now, we don't have any divestment plans for our current Nuakka stake, quite the contrary. We used to like having high stakes in the assets and the projects that we are fond of. And then your final question is around the ceasing additional opportunities. When we have a look at the Aker BP IIC hopper, there are, of course, a lot of interesting investment opportunities in that hopper. David alluded to the fact that there might be other opportunities that we will choose to progress as 2020 progresses. And it wouldn't be strange if we try to make at least try to maximize the activity in that hopper within this temporary tax window. However, I'd also like to stress that we will not do this without regard to the execution schedule and to the risk that this is imposing both to the balance sheet and our execution model. So this is also work that's ongoing as we speak. And I think we'll revert to the market in Q3 with an updated long range plan, including investment opportunities. When it comes to your last question, Mikael, on dividends. So I think what we can say now is that our capital allocation priorities stand firm, and that means that distributing parts of value creation back to shareholders is part of that framework. And as you know, cash dividends has been the preferred method of that type of distribution and that I also expect to be an important element going forward. When it comes to dividends for 2021 and beyond, we will have to come back to that at a later stage. Okay. Thanks, you guys. Our next question comes from Keodor Mollson from SB1 Markets. Please go ahead. Good morning and thanks for taking my questions. Two questions, if I may. The first one is on the gas developments. I know that most of your portfolio is separately oil related, and that is also what you probably have discussed this morning. But how do you think around gas developments in light of the very low European gas prices? Second question is on hedging strategy going forward. You said that 80% after tax rollers is hedged up there for those per barrel for the second half of this year. But going into 2021, should we expect you to continue to hedge a substantial portion of your roll loans just like you have done this year? Yes. So let me start with the gas developments, Theodor. So you're absolutely right, of course. Our portfolio is now heavily weighted towards oil. I think the ratio now is roughly 80%, 20%. And we're monitoring the gas market, particularly in Europe. It's not totally unexpected to us that we're seeing weakening of the European gas markets. I think the level is a bit lower than we expected a few months back. But I mean the COVID situation has basically thrown a lot of our models out of whack. And of course, it represents a dual, both an opportunity as a challenge. The opportunity is that there will be gas assets that will look cheap. And the challenge is, of course, that we are quite uncertain as to when, how and to what level the European gas market will pick up. I think you should expect us to be cautious on gas developments, at least in our organic portfolio for the time being, Todor. Your second question, Thodor, with regards to hedging. So we do have a policy when it comes to hedging, which allows us to, of course, hedge 18 to 24 months into the future, but this is, of course, not a mechanical approach. So we do a sort of a holistic evaluation of the whole risk management framework and evaluate sort of the cost benefits of that. That being said, we do expect also to continue our hedge That being said, we do expect also to continue our hedging policy also into 2021, but the timing will, of course, be dependent on how the market develops and the cost benefit of that. Okay. Thank you. Next question comes from James Thompson from JPMorgan. Please go ahead. Good morning, gentlemen. Thanks for taking my questions. Can I just really talk a little bit strategically about what you can actually do relative to the tax changes announced in Norway? And you kind of alluded to a little bit earlier, but I just wondered what the sort of capacity was. You obviously got a big contingent resource space, but Noaca is a big complicated project. Do you have the resource to kind of develop the rest of several more projects in your hopper in the time frame that you have available to you? It'd be great to get some color really about how much more you can do beyond what has already been announced without, as you say, putting risk to execution or being able to find the right people. And in that context, how should we think about your exploration plans going forward? I mean, clearly, you suspended 4, 5 wells earlier in this year due to the crisis, which is unsalable. Should we think that those come back and then some next year? I mean, is the mindset that you want to drill as much as possible before 2020 end of 2021 to try and find another project on top of what you've already got in the hopper? Or you sort of have the view that what you've got on your plate at the moment is more than sufficient for the period? Thanks, James. So first of all, I think it's there are a couple of avenues into that first part of your question, how much can we actually do. So one avenue is talking about this from an execution perspective. And right now, given the fact that we have implemented the Alliance model, we're not really that impacted by capacity in the execution side. There's still a lot of capacity in the contractor market. We still are the preferred customers for a lot of our alliance partners. So we don't really see execution or capacity and execution to be a big hurdle right now. 2nd, I think it's important when you get too before you get too enthusiastic or all of us get too enthusiastic, I mean, the project doesn't really change. The cash flow is basically the same. The subsurface risk is basically the same. The technical challenges are essentially the same plan. So the only thing that has actually changed is the way that we depreciate the CapEx. And it's important to remember that as we start executing project because it impacts how we think about the operational plans and how we put drilling plans and project plans together. And this is the work that's actually ongoing as we speak. So we'll come back to the specifics of that. But I think you expect that there are some more projects in that hopper that we wish to realize inside the value, inside this tax window. We'll try to make the best of it because in my view, this is actually a pretty unique opportunity to create value from an organic hopper. The breakeven reduction from a financial perspective is in the range of $10 a barrel on a project basis, which is a pretty unique opportunity. And of course, as a management team set out to maximize shareholder value, we'll try to find a balance between executing as many projects as we possibly can but at the same time not putting the execution model at risk and ending up with severe delays and cost overruns. And then finally, I think it's also worth noting that out of the 9.80 roughly 2C resources, Noaca is roughly onethree. So with Noaca running at full steam, quite a lot of this is actually already in the works. Now when it comes to exploration, the updated program of 2020 is roughly 4 wells from an operated perspective. And I think I don't really James, I don't really see the need for a lot of additional prospects to come into this hopper. We have sufficient resources and sufficient work to do inside the existing resource hopper. So what I think we should expect going into 2020 is not at all that we'll revert to the old exploration strategy, But you should expect that we remain cautious and focus on replacing the 2C hopper around our operated assets. And then we'll come back as we usually do in the autumn with updated drilling programs for next year. But don't expect us to come back with a very ambitious drilling program for 2021. Okay. Okay. Thank you for that. Appreciate the color there. Just one other one follow-up for me. I mean given the extra liquidity you're getting over the next couple of years and given that I think it feels now that a lot of the focus is organic rather than inorganic. Could you argue that perhaps you have a little bit too much liquidity at this point in time? And actually you could maybe trim the balance sheet down a little? I think it's important to look at the whole balance sheet and the timeline of the changes in the temporary fiscal regime holistically. And if you look at the illustrative chart on one of our slides in the presentation where we are showing the cumulative cash flow over time, you basically see at in the end of the time period, you basically have the same cash flow cumulatively. So with that being said, I think it's natural that the robustness of the balance sheet will improve, of course, in the medium term when the cash flow is significantly improved. But then keeping in mind, of course, that the cumulative cash flow is almost the same over the whole period. But that we're also James, we've also been quite clear that in terms of liquidity and availability of funds, we would like to be cautious and maintain a robust capital structure. And that has been our strategy now since 2015, and that will be our strategy also going into the future. And if anything, this COVID-nineteen situation has learned us that it actually pays to have a bit of available headroom when you have these kind of situations. Very good. Thanks guys. Our next question is from Alf Stanson from RBC. Most of my questions have been asked. So it's just a very simple I was wondering why you've not tightened up the range on 2020 production guidance. You've averaged 210 in the year to date. So I was wondering why that's not the back the bottom end of the range. And I suppose the question then is, is June's presentation of production growth in Q3 and Q4 still standing? Thank you for that, Al. So I think the reason for not tightening up the range is, of course, that there is quite a lot of uncertainty when it comes to the curtailments and also the ramp of production in the second half of the year. So that's why we haven't adjusted it. But as mentioned, we feel very comfortable with the range provided. And then we'll come back, I guess, in the Q3 with also the results from the Q3 and then probably adjusting the range accordingly. With that, operator, we have time for one last question. Perfect. Thank you. So our last question comes from Karl Friedrich from ABG. Please go ahead. Hi, guys. A quick question on following up on exploration. The Barents Sea, will we see you doing anything more than your mandatory programs? Or is this essentially an area where you will not pursue any further activity, leaving it for others to do the works there. And should we expect into 2021 that it will be a higher than a normal proportion of near field exploration wells? I think the last part of your question is definitely simple. That's yes. As also following from the reasoning I just laid out that we'll try to maximize the value of resource hoppers going into our operated hubs. When it comes to the Barents Sea, I think the in going assumption is that we have been, as an industry, rather disappointed at the lack of discoveries in the Barents Sea. And with the current portfolio, acreage coming out, and we'll have a look at that, of course, as everybody else. But I don't think you should expect us I think I'll put it like this, Galfalik. I think our expectations to the Barents Sea and also to our enthusiasm around the Barents Sea is somewhat muted at this point in time. Makes sense. May I have a follow-up on my other question in terms of near field activities? Which hub do you think or do you see as the most promising for being able to add more projects under the temporary tax change regime? I think right now, that will probably be Alfheim, but also Skav is showing some promise. So those 2 FPSOs are probably the most interesting right now, both not necessarily in terms of total returns, but certainly in terms of activity that can come to play within the current temporary tax changes. Thank you. Okay. Operator, I think we have to close off then. So any further questions could, of course, be guided towards the IR department here at Aker BP. And with that, I would like to thank all of you for joining the call and also for asking questions and wish you all a very good summer.