Aker BP ASA

OSE:AKRBP

Earnings Call Transcript 2020-Q3

[Kjetil Bakken, Vice President of Investor Relations]

Good morning, and welcome to Aker BP's Third Quarter 2020 Results. My name is Kjetil Bakken, and I'm heading the company's Investor Relations department. Today's presenters are CEO, Karl Johnny Hersvik; and CFO, David Tønne. The presentation will be followed by a questions and answers session. Before we start, I would like to refer you to the disclaimer on Page 2 in the presentation. And with that, I leave the floor to Karl Johnny.

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you, Kjetil, and a warm welcome to all of you who are listening to this call. I sincerely hope you are all safe and healthy. Third quarter of 2020 was a very good quarter for Aker BP. I would, of course, like to have seen high oil prices, but we delivered strong performance within most of the areas we control. We are well on the track to the level of our production guidance for the year. Our development projects are progressing as planned and we are keeping costs under control as well as, that's the message. And finally, we generate a free cash flow that more than covers our cost and dividend in the quarter. Our vision is permanent. We desire to be the leading company in our industry. And we, therefore, have a relentless focus on improvements. Our main priority right now is to refinement and implementation of a new operating model aiming to further improve efficiency, safety and cost to standardizing best practices across all our operated assets. We also continue to focus on and improve our financial flexibility. This time if we have bond refinancing which have increased our liquidity, reduced our interest cost and extended the maturity profile above that. And now the time has finally come to start talking about group once again. And at times, when many of our payers are struggling to make entry will take it's time to be countercyclical. The changes made -- the temporary changes made to the tax system this summer was aimed at improving activity levels in the E&P industry. And Aker BP with our huge inventory of two key resources with low breakeven is uniquely positioned to benefit from this golden opportunity to potentially double our production. And some, I believe Aker BP now offers a unique value proposition. We are demonstrating strong execution, we produce with low cost and low emissions, we can double our production at low breakevens. And we can do this without stretching our balance sheet. We will cover all of these topics in more detail. But let us first cover the operational highlights for the third quarter. And as usual, I will start with the safety record.The company has worked systematically to protect personnel and to ensure continued and uninterrupted production from all assets during the current COVID-19 outbreak. We have not experienced any confirmed infections affecting operations or impacting our HSE performance. Policies and procedures have proven effective and will remain in place for as long as necessary. Both the total recordable injuries frequency and the serious incident frequency, so called SIF showed a marginally negative trend compared to the first two quarters in 2020. This is mainly due to slight increase in personal injuries with low potential and is being addressed systematically. Production costs dropped to $7.30, per produced barrel in the quarter, mainly caused by lower well maintenance activity than in the previous quarter. For the full year, we now expect the production cost to average around $8 per barrel, 20% below the original guidance from temporary. Our CO2 emissions ended up below our targeted 5 kilograms per barrel. Currently positioning Aker BP amongst the very best oil companies globally with respect to CO2 emissions.Production volumes and efficiency were slightly down from previous quarters, and as we can see on the next slide, this is down from very high levels in the first and second quarter. The third quarter number were impacted by a number of planned activities at both Alvheim, Ivar Aasen and Skarv, such as well interventions, drilling operations, pulling operations, turnaround and emergency shutdown tests. At Valhall, however, both production and production efficiency increased in the third quarter and the production ramp-up and regularity at Johan Sverdrup also continued to impress. During November, further testing of the upside to Phase 1 capacity at Johan Sverdrup will be provoked. For the first 9 months, our average production was 206,500 barrels of oil equivalents. We expect fourth quarter to be the strongest quarter of the year as we will be starting production from Ærfugl as well as a new multilateral production well at Alvheim. We are, therefore, well on track to deliver our production guidance for the year, which we have now narrowed into 210,000 to 250,000 barrels as there is only 1 quarter left to go. We are also on track to deliver our emission targets for 2020. With a year-to-date emissions intensity of 4.8 kilograms per barrels of oil equivalent, in line with our target of less than 5 kilograms per BOE, this is less than 1/3 of the global average. Efficient operations, whether we talk about emissions or cost is, in my mind, the strongest contribution we can make as a pure-play E&P company to enable the energy transition. We enable that energy transition from 3 main channels. First, to maximize the value creations for assets and activities. This means that we also maximize the profits we could definitely back to our shareholders and the taxes we pay. These funds can then, in turn, be used to fund the energy transition. Second, we will continue to minimize the environmental footprint of our operations. Our CO2 emissions are already among the lowest in the global E&P space, and we will continue to work to maintain and further improve this position. And third, we believe we can also contribute to the transition for sharing of data, know-how and technology with other companies and industries to support the development towards a more sustainable society. A good example of this third point is the recently launched collaboration with Aker Offshore Wind. With a common aim of decarbonizing oil & gas assets on the Norwegian Garantiana shelf and realizing Offshore Wind in Norway at a large scale. Aker BP will not operate or build offshore wind parks but we will contribute with industry and technology competence and be a potential customer of the electricity from Offshore Wind. However, this strategy will only be successful if we can manage to be the most efficient operator of oil & gas assets. And that is why we are implementing a new operating model across all our operated assets using the toolbox from our improvement program. The new operating model represents the transition of the operational performance in Aker BP. Key focus areas consist of standardization of best practices and processes across the operational and maintenance teams; funneling up the organizational structures based on asset type and complexity; better integrated planning and reduced activity set through top scrutiny and prioritization of the activity set; new ways of working using digital solutions matured from our EurekaX efforts. The purpose of this new operating model is to improve efficiency and safety and to help us achieve our long-term goal of sustained production cost below $7 a barrel. Now I talked about growth. So let's move to the update on our development projects. We will start with a highly profitable Ærfugl project, which is on track for production start-up during the next month with 3 production wells. This will mark the completion of the Phase 1 of the project. Phase 2 of the project is also well underway with 1 well already on production and 2 remaining wells are set to come on stream towards the end of 2021. I'm extremely proud of the excellent performance shown by the Ærfugl Project team and our alliance partners. The Modification Alliance, Subsea Alliance, Central Alliance have all been vital in this project with major improvements in PDO, including accelerated development of Phase 2, better economics and equally important progress according to cost and schedule at a very bumpy environment. Increased reserves are also a part of the improvements in PDO, enabled by new technology, such as the lighter and more cost-efficient vertical laboratories and an electrical heated pipeline extending more than 60 kilometers to cover the Ærfugl as well. When both phases of the Ærfugl project come on stream, we will be back to full capacity utilization at the Skarv FPSO, representing roughly a doubling of production compared to current levels. Our other development projects are also progressing well, and the construction of the Hod facility is well underway in the Kvaerner yard at Valhall. The Subsea Alliance have completed the first offshore campaign by preparing for a Hod path operation that will take place next year. And the Modification Alliance have commenced detailed engineering and will be ready to start offshore work by the end of the year. Production started Hod is planned for first quarter 2022. Moving on to Johan Sverdrup. It has, during the first year of operation, produced some 130 million barrels of oil in total. Experienced from the first year in operation have shown continued high regularity. As I mentioned initially, testing of further upside to Phase 1 capacity at Johan Sverdrup will be performed in November. This is, of course, very encouraging. In parallel, Phase 2 of Johan Sverdrup development has progressed well and in accordance with the PDO and start-up scheduled for the fourth quarter of 2022. In addition to these development projects in the execution phase, we have a large hopper of resources, and we are currently working to mature towards the final investment position. This resource base represents a unique runway for further organic growth for the company, both with regards to size and the quality in terms of low breakevens. And the recent tax changes have further lowered the breakeven as well as significantly reduced the capital commitment necessary to realize this resource base. As you will see from the chart on the right-hand side of Slide 10, the most striking improvement is the accelerated depreciation with 70% -- 73% of the CapEx being covered by tax reduction in the same year as the investment. This provides a massive liquidity boost compared with the ordinary system and hence, reduces the capital requirements through the investment phase. The implication is that we, despite the challenging macro environment, can take countercyclical approach and deliver significant organic growth without putting the strain on the balance sheet. And of course, deliver significant activity into the Norwegian E&P under space as was the design of the temporary tax changes. So let's take a look at -- closer look at some of these growth opportunities. The biggest single item in our resource space is NOAKA. In the second quarter, we reached an important milestone when we reached an agreement with our partners on a commercial framework for a coordinated development of the area. In the third quarter, Aker BP's NOAKA team has mobilized the company's strategic partners to mature and improve the development concept of newer and a fuller development. A concept select position is planned for the third quarter of 2021. Equinor, as operator on Korpfjell has mobilized their project organization and collaborated closely with Aker BP to optimize the area development concept. That concept will be further optimized prior to submitting plans for development and operations in 2022, which is the deadline to qualify for the temporary tax system. And we're also working to mature several other projects within this time line. These projects were in our plans prior to the combined COVID and oil price shock in March when we decided to freeze all nonsanction projects due to high uncertainty. Since then, we have further strengthened our financial flexibility, and the tax system has, as I've repeatedly discussed, significantly improved. So now we are continuing to mature this project, which represents more than 500 million barrels of oil equivalent of resources with an aim to make a final investment decision before the end of 2022. We believe it will be possible to bring all these projects below our investment base of $30 per barrel in a full life cycle and to kind given. If we manage to keep the schedule, we are looking at a company that would roughly double its production over the next 7 to 8 years. NOAKA is obviously the largest project on the list. Most of the projects are linked to our existing operating hubs. Some of these are a result of successful exploration like Frosk, Shrek and Alvheim, while Trell & Trine and Alve North are example of discoveries we have acquired in the spirit. Meanwhile, the and the Kobra East/Gekko and Valhall projects are initiatives to unlock additional resources within our existing producing asset base. We will continue to systematically mature this project, and we'll provide more information as we progress them through their decision base. When it comes to how this fits into our capital allocation framework, we will come back with more details at our capital market update in February. But just to be clear, our capital allocation priorities remain the same. Our overarching goal is, as it's always been, to maximize shareholder value. When we are planning to develop 500 million barrels we just talked about at breakeven below $30, it is exactly because we believe this will create a lot of value. In order to keep this value creation machine running, it's also important to maintain a sufficient financial capacity and we therefore give high priority to maintaining a strong balance sheet and protecting our investment-grade credit portfolio. The recent tax changes are also very helpful in this respect. Based on current forward curve, we expect to be able to cover all our growth products while reducing our leverage ratio. And it remains our firm intention to return value creation to our shareholders. I guess, David, that this provides a good segue for you to talk about our financial statements here in Aker BP, and I give the word over to our CFO, David Tønne.

[David Torvik Tønne, Chief Financial Officer]

Thank you, Karl, and good morning, everyone. Aker BP's net production in the third quarter was 202,000 barrels per day. The change from the second quarter was mainly driven by planned maintenance and drilling activities. With an underlift in the quarter of 14,000, sold volumes ended up 188,000 barrels per day. Both liquids and gas prices increased quarter-on-quarter, and the realized average hydrocarbon price was up approximately 41% and ended at $38.8 per barrel of oil equivalent. Total income ended at $684 million, which consisted of $675 million in petroleum revenues and $9 million in other operating income. Before moving on to the income statement, I will firstly brief upon the breakdown of liquids price realization. We observed a decent recovery in Brent prices from April to June and the convergence of Platts Brent Dated in the front-end Brent contracts traded in the financial market. In the third quarter, the recovery slowed down. Brent traded in the $40 to $45 range, and the average Brent Dated in the period was $42.9. Aker BP realized a positive differential of $0.8. And together with a small positive timing effect, the realized crude price ended at $43.8 per barrel. The positive differential in the third quarter stands in sharp contrast with a negative $1.8 experienced in the second quarter. Although this is a clear indication that the physical market has improved over the last 3 months, there is still a way to go before we can say that the market is back to normal, and we actually see signs of weaker market in the fourth quarter. Adjusting for NGL, Aker BP's average liquids price was $42.7 per barrel. Now moving over to the income statement. As mentioned, total income was $684 million, and this is an increase of 16% from the second quarter. Production cost of sold volumes were $134 million, and the production cost related to the produced barrels amounted to $136 million or $7.3 per barrel. This compares to a production cost of $9.1 in the second quarter. The decrease in the third quarter is as expected and mainly due to less well maintenance work, Ula and Valhall.Exploration expenses amounted to $32 million, $12 million in dry well costs, mainly related to the Sørvesten well and $10 million in field evaluation costs, mainly related to the Alvheim area and NOAKA.Total cash spend on what is defined as exploration activities in the third quarter ended at $54 million. It's worth noting that in the next 12 to 18 months, we expect an increase in field evaluation costs, a spending related to early phase project development, including NOAKA, are accounted for as field evaluation expenses also expect before contact selection. Summing up the items discussed so far. We end up with an EBITDA of $511 million, up 55% from the second quarter. Depreciation was $269 million or $14.5 per barrel, and net financial expenses were $51 million. The main reason for the increase from the second quarter is the change in fair value of currency contracts as the Norwegian kroner strengthened during the quarter. Profit before tax was $191 million and tax expenses amounted to $111 million, and which is largely caused by an increase in deferred tax. The effective tax rate for the quarter was 58%. In sum, net profit in the third quarter ended up $80 million or $0.22 per share. The main line items in the balance sheet were fairly stable in the quarter. The key changes are bonds and bank debt on the right-hand side and on cash and cash equivalents on the left-hand side. This change was driven by our bond issuance in late September, leading to a relative large cash position of $819 million at quarter end. In addition to that, on the left, property plant and equipment increased by $43 million. We had additions of $287 million where investments at Valhall, Alvheim and Johan Sverdrup made up roughly 75%. On the other side of the balance sheet, equity increased by $70 million, which is the sum of net income, dividends and sale of treasury shares for the employee share program. The increase in bonds and bank debt of roughly $661 million is the net of the $1.25 billion in bond issuance in September and the repayment of the debt load in Norwegian kroner bond and a repayment of all drawings under the RCF. Today Karl has given you some more details on the project hopper and the value creation potentially in Aker BP going forward. We have the opportunity to double the company's production over the next 7 to 8 years, investing in projects with a full life cycle breakeven below $30 Brent at a discount rate of 10%. This ambition continues to be well supported by a very strong financial position. 7 months into one of the most productive periods in the history of the global oil industry, Aker BP has been able to further fortify its balance sheet by adding liquidity, keeping the leverage ratio in check and extending our debt maturity profile. At quarter end, Aker BP had a book value of net interest-bearing debt of roughly $3.6 billion, more than $4.8 billion in available liquidity, and the leverage ratio slightly below 1.5. Lastly, on October 2, after the quarter end, we called the $400 million 2022 bond and we now have no debt maturities before 2024. We continue to experience strong support in the credit markets and see the successful bond offering in September as another testimony to the company's track record and the value creation potential going forward, supported by a leading financial robustness and flexibility. In spite of continued challenging market conditions, Aker BP's third quarter cash flow generation was relatively strong. Cash flows from operations amounted to $417 million, and we received an additional $109 million in tax refunds. Cash flows to investments was in total $331 million across the various end categories, with CapEx being over 18%. Free cash flow before financing was just $195 million. And the other cash flow to financing here mainly consists of a realized loss on the cost-currency interest rate swap related to the debt now on 2022 bond from 2013 that was repaid this summer. Lastly, dividends amounted to $71 million. At the end of the quarter, our cash balance was $819 million before following the 2022 bond in October. Based on current oil price levels, Aker BP expects a tax refund for the full fiscal year of 2020. This summer, we estimated the full tax installments to be refunded in the second half of 2020. And in the third quarter, we received the first installment of $109 million. In the fourth quarter, we will receive 2 more installments totaling around $200 million. The tax installments to be paid or refunded in the first half of 2021 will be decided after year-end based on the estimated actual 2020 results. All other things equal, these installments are sensitive to the realized oil price in the fourth quarter. And on the right-hand side of this chart, we illustrate this sensitivity, now showing what the refund is estimated to be at $30, $40 and $50 Brent oil price on average in the fourth quarter. Before leaving the word back to Karl for some concluding remarks, I will walk you through the updated guidance for 2020. In addition -- and in addition to provide some initial flavor on what we currently expect for 2021. Production year-to-date is 206,000 barrels per day. In the fourth quarter, we expect both the Ærfugl Project Phase 1 and the newly drilled King well at Alvheim come on stream. As we now only have 2 months left of the year, uncertainty is reduced and unless there are any unforeseen project delays or production outages, we expect 2020 production to end between 210,000 and 215,000 barrels per day. For 2021, we expect relative stable production compared to 2020. We expect the entry rate in January to be somewhat higher than the yearly average, with the underlying decline and normal maintenance turnarounds during the summer being offset by new wells coming on stream towards the back end of the year. Production cost per barrel is $8.4 year-to-date. The cost is trending down nicely as major well maintenance work is completed for the year. The third quarter production cost per barrel was $7.3, and we expect a similar cost level per barrel in the fourth quarter. This means that for the full year 2020, we now expect production costs to end at roughly $8 per barrel. The original guidance for the year was 10%, but we updated this in the second quarter to 7% to 8% as we reduced activity, accelerated cost reductions and the Norwegian kroner significantly weakened. The updated guidance assumed a dollar NOK rate of USDNOK 10. Lately, the Norwegian kroner has been stronger and this is the key driver for why we now forecast to end in the higher part of the updated range. For 2021, I'm very happy to see that the company is able to drive down underlying cost further. While at the same time, we add back value-adding activities that was postponed this year. Furthermore, we anticipate a stronger Norwegian kroner on average in 2021 than what we have seen in 2020. Consequently, we currently forecast a slight increase in the cost per barrel from 2020 to 2021, measured in U.S. dollars. CapEx year-to-date is roughly $1 billion. Our key projects are progressing as planned. But partly due to strong performance and partly due to timing effects, we expect that the full year spend now will end at roughly $1.3 billion, down $50 million compared to previous guidance. Year-to-date spending on is $166 million. We are currently drilling the Alve North East well. And in the fourth quarter, we plan to drill 2 nonoperated wells Frosk and Mercx.Based on an assessment of spend so far and the planned activities for the remaining part of the year, we expect 2020 spending planned at roughly $300 million, down $50 million from previous guidance. Advancements expenditure year-to-date is $73 million. In September, we ramped up the P&A activity at Valhall which will now continue until mid next year. We maintain the full year guiding at $200 million, but there is a good chance we will end up somewhat below this. For 2021, we target total investment spending close to or slightly above the 2020 level. For CapEx, we have ongoing projects, such as Johan Sverdrup Phase II and Hod as Karl has talked about. And in addition, we plan to drill production wells in all our operating areas in 2021, investing in highly profitable barrels close to existing infrastructure under the temporary fiscal regime. For EXPEX, we expect a slight increase in 2021 compared to 2020. This is driven primarily by early phase project development at NOAKA and other projects that have not yet reached final contract selection. Costs related to these projects are categorized as field evaluation EXPEX. This means that a significant part of EXPEX for 2021 will be field evaluation costs. And all other things equal, EXPEX will be higher than what the number of exploration wells would normally indicate. The final exploration program, including number and timing of wealth is not completed, and we will, of course, provide more details on this at the next capital markets update. Abandonment expenditure in 2021 is expected at the same level as in 2020, with the big driver still being P&A work at Valhall. It's worth reiterating that for CapEx in 2021 qualifies for the temporary fiscal regime. And to simplify a bit, you could say that the tax treatment of investment spending across the various cost categories are, therefore, quite similar the first year. And on average, we expect roughly 75% tax deduction for the total investments in 2021 already in the second half of the year and the first half of 2022, with additional tax deductions for CapEx for the next 5 years. This means that if we, say, invest $2 billion in 2021 across the 3 spending categories, the after-tax cash flow of that spending is roughly at $500 million in year 1. The plan for 2021 will be further matured, also with input from our license partners at the year-end, and we will return with the final plan for 2021 and detailed guiding at our capital markets update, most likely scheduled for February next year. I will now hand the word back to Karl for some closing and final remarks before we open up for questions. Thank you.

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you, David. I'll walk through as always. Before we open up for questions, let me just summarize our main priorities for the coming quarters and reiterate a few key points. First of all, Aker BP has a very strong operational track record. And we will continue our relentless focus on operational excellence, which is basically about maintaining safe and efficient operations with good cost control. And we will continue to focus on strong project management and to deliver our development projects on time, on budget and with the right quality. Second, we are already one of the leading global operators when it comes to low cost and low emissions. To further improve our position, our main priority is the implementation of a new operating model, which I touched on earlier. Thirdly, Aker BP is uniquely positioned for profitable growth due to the combination of a larger resource base and Norway being probably the most attractive place in the world right now for E&P investments. With our project portfolio, we can mature more than 500 million barrels for FID by the end of 2022, potentially doubling our production a few years down the road. These projects will all have breakevens below $30 per barrel. And helped by the temporary tax regime, we can do this without stretching our balance sheet. In my mind, this is a unique value proposition. This concludes our presentation, and we are now ready to take your questions.

[Operator]

[Operator Instructions] We'll now take our first question from Alwyn Thomas from Exane BNP Paribas.

[Alwyn Thomas, Analyst of Oil and Gas]

I guess, if we could just start off at a reasonably high level. You've got a bit of a war chest now after the recent bond raises. I wanted to ask how you think about using that? And whether M&A comes into it or particularly as you've got 500 million barrels of resource that you can put into action relatively quickly over the next couple of years. Is that really the priority for that, that money at the moment? And then perhaps, Karl, maybe get your thoughts, maybe we're a bit too early here to ask this, but can I get your thoughts on when you think about the dividend level at the moment. And like I said, if things are slightly improving, and obviously, the tax regime is starting to help as well on a cash flow basis, whether we can see an increase in dividend early next year?

[Karl Johnny Hersvik, Chief Executive Officer]

Yes. Thanks, Alwyn. Excellent questions, as always. So let me start with the so-called war chest. We really don't think about it as a war chest. We think about this as a robust balance sheet. And we have, for a long time now, we've been communicating a message that we want to be ahead of the game when it comes to maintaining a robust balance sheet and liquidity. We actually see that as probably one of the cheapest ways of -- as a hedging volatile oil price environment. And if anything in 2020, it has proven that this volatility is, one, significant and, two, probably here to stay. I think in the E&P space, the CEOs have always been talking about the better world, and now we're actually living one. So it's good to see that Aker BP is in a position where our main strategies on hedging those risks are actually working and we're able to secure additional financing in the middle of this huge turmoil. So that, of course, also means that, as you probably realize from our presentation, our primary focus now is to realize the early phase projects that are ongoing, roughly 500 million barrels. And with the $30 breakeven, it's really difficult to see how M&A should compete. And as always, we will be disciplined when it comes to M&A. We are a company that's all about value creation. So while M&A is not entirely off the table, it, of course, will need to be more profitable than the alternative investment into our organic hopper. And if you start running the numbers, you'll realize that, that has to be quite a spectacular good deal. When it comes to dividends, I think I'll come back to that when we come to our capital market updates, probably in February. There are, of course, discussions ongoing, both internally, and we also hear that there are a lot of advice and a lot of opinions from different parts of the ownership groups. So we'll come back to that in more detail in February, Alwyn.

[Operator]

The next question comes from Teodor Nilsen from SB1 Markets.

[Teodor Sveen-Nilsen]

Karl, you highlighted that in your investment proposition low OpEx is very important. And just looking forward on next decade, are you doing any specific steps right now to avoid cost inflation in the next part of the cycle? Or do you never see that we will have actually a tight supplier market? Second question, just a follow-up on the dividend level. Of course, I understand that you can't guide specifically on 2021 dividend today. But can you just provide some high-level thoughts around how you consider cash dividend versus buyback?

[Karl Johnny Hersvik, Chief Executive Officer]

Teodor. Well, I must have missed that. I actually expect some cost escalation as we increase our investment portfolio in the Norwegian E&P space. And to some extent, this is actually desirable. Because if you remember back, the idea among this temporary tax change was to ensure that the vendor industry, one, has a sufficient influx of, I would say, activities; and two, that these activities generated a positive result for this company. But it's not necessarily just about surviving. It's also about actually being able to run through that transition. So I think that's my point of departure on that discussion. And then I think the primary strategy from an Aker BP perspective is along 2 main lines. So when it comes to how we deal with the vendor market, we've been for a long time now working within these alliance partners. And I think around 95% maybe of our CapEx is currently passing through different alliances and the OpEx is similar or trending similarly. And then, of course, we talked today about the new operating model, which is the first stage about standardization. We've been now focusing, as you've probably seen, on operational issues like uptime, throughput, maximizing production, et cetera, et cetera. And now we're starting to kind of back to stable. We're starting to run down standardization, which will also enable us to acquire these services and goods in a much more predictable manner and thereby also providing better influx and better planning and lower waste in our processes. So at least there's a solid plan in place. And then, of course, we are always eager to stay ahead of that game and see if we can actually do further improvements. Now when it comes to dividends, and of course, instruments, I don't think I'll speculate too much in this call. And we'll come back to this in detail when we come to the Capital Market update in February.

[Operator]

The next question from Anders Holte from Kepler Cheuvreux.

[Anders Torgrim Holte, Equity Research Analyst]

Sorry, if there are some sound effects in the background. But just a couple of questions, if I may. First of all, related to your operational cost guidance for next year. I'm just curious to see how much of that increase in '21 that you gave in your slide is due to FX rate and how much of it is due to underlying costs coming up? And also in relation to your spending level that you're now indicating for next year, how much, if any, is related to NOAKA? And what are the key drivers for that continued high level of CapEx for next year?

[David Torvik Tønne, Chief Financial Officer]

Anders, I can do the question around guiding on cost level. So the slight increase indicated for 2021 on OpEx per barrel is primarily driven by FX. So if you refer to the footnotes on the slide, we are basically assuming NOK 9 per $1 as average for 2021 compared to the average, what we've seen this year is more close to NOK 9.5. So that's the reason why there is a slight uptick. When it comes to NOAKA total spend, I don't think we will go into details on sort of CapEx for project as of now. But I assume you will provide some more details on the NOAKA project probably when we get back to the capital markets update.

[Karl Johnny Hersvik, Chief Executive Officer]

Absolutely, Anders. But also remember that before DG2 this is field evaluation cost, meaning expects. And DG2 is planned for Q3 2021, right? So there will be a limited CapEx spend for NOAKA, and most of this field evaluation of steady cost is now being projected as expects. And then maybe an additional comment to the 2021 OpEx per barrel. In his remarks, David also talked about the underlying cost performance. So while the change in dollar per barrel is primarily driven by FX, the activity level is somewhat increased. So the underlying cost performance, if you view it from a resource utilization point of view or an activity point of view, is declining.

[Operator]

The next question comes from Yoann Charenton from Societe Generale.

[Yoann Charenton, Equity Analyst]

3 questions, if I may. Turning back to Slide 21, which shows tax payments and refunds. The projections for the first half of 2021 in terms of payments or refund has changed dramatically on the $50 scenario. Would you please shed some light on the drivers behind this? Second set of question, would it be possible to hear a bit more from you about further likeliness of further deployment of power from shale solutions across your existing hubs? And secondly, about the opportunity set for powering some facilities with Offshore Wind? Finally, would you mind providing some color on how environmental considerations may have played a role in forming a decision regarding the barrel fee in recent licensing rounds?

[David Torvik Tønne, Chief Financial Officer]

So Yoann, I could do the tax question, and then I'll leave the word over to Karl. So on Page 21, we illustrate the fact for the fiscal year 2020, meaning based on the results in 2020, we paid 6 installments, 3 of them are paid in second half of 2020 and 3 of them are paid in the first half of 2021. And what we are indicating here on the slide is basically what installment to be basically here at the tax refund, depending on what the oil price will be in the fourth quarter this year. So we have, of course, now 3 quarters of actuals. And then spending of oil price in the fourth quarter that indicates the cost results for the year. We have already picked the three first installments and then the variable is 3 installments first half of 2021. So that's what the $50 scenario here indicates. And Kjetil will add the additional comments here.

[Kjetil Bakken, Vice President of Investor Relations]

Yes. Yoann, one additional commentary is that in the previous version of this chart, the sensitivity was made based on full year oil prices versus now it's only Q4 oil prices that vary. So that's why the bars have narrowed in.

[Karl Johnny Hersvik, Chief Executive Officer]

Thanks, Yoann. And then for the other 2 questions, and if you start asking these difficult questions, David and I may have to change roles, so I can answer back questions and he can do the more environmental discussions. So power from shore, we are assessing power from shore, concretely, of course, related to NOAKA, which will be powered using an onshore grid action. That it's already decided. There is, of course, questions whether or not this can form some sort of system where Offshore Wind production is finding an offtake in the NOAKA area. Maybe in addition to power from shore solution, where the volatility in the -- or I'd say, flexibility in the offshore wind production will be countered by power from shore. So the discussions such that these are, of course, ongoing and also ongoing at other assets, both operated by Aker BP and other companies. Then there are discussions related to existing operational assets. Both of those who are now, I mean, ramping up to be powered from electricity is of course we've already in 2022 and for Aker BP clear our electrification that is ongoing at the moment. And also this already powered and does really have a power production going on and give an alternative power using gas turbines at advanced tank, which one this cost line side decommissioned and replaced by power from shore. It will be entirely electrified. And then there are assessments ongoing, both on Alvheim and Skarv at the moment. Currently, I would say that these projects are challenging. Retrofit of power from shore solutions to FPSO. So it's technology novelty, but we are addressing it. So when it comes then to, let's say, other possibilities in terms of Offshore Wind, Norway has really 2 areas for application of Offshore Wind. And also in Southern North Sea, very close to Valhall in fact. And it's these two areas, which is just in from the NOAKA field development. Of course, brings up discussions around how offshore operations can be utilized, current infrastructure offshore in oil & gas can be utilized to improve Offshore Wind installations. There is 100-megawatt or HVDC line out to Valhall, the longest HVDC aligned on the industry in powering and offshore installation that's 295 kilometers. So we are in the middle of all of these discussions. And as soon as we have more clarity, Yoann, we'll come back with more details. So when it comes to the Barents Sea. So, first of all, we, as a company, entirely believe that it's fully technologically and technically possible to develop an oil and gas installation in the Barents Sea. So let me not leave any doubt about that on the table. It is entirely possible and has been proven already to do this in the Barents Sea. It's not a particularly different -- difficult regime to operate in. Yes, it's dock and somewhat full, but it's not more difficult than the Norwegian. Second, when we think about our priorities in terms of capital allocation, I think, first and foremost, we've been disappointed about the exploration success, primarily linked to the number of exploration models that have now been drilled out with limited success. So to us, this is mostly about a commercial decision, where we believe that our exploration cost is better than elsewhere. Two, that we have a really large organic that would like to mature. I don't necessarily see the need to go looking for long in the two assets in the Barents Sea. And thirdly, this is also about the geological assessment of the opportunities we've seen in the Barents Sea. So let me go back and say that we entirely believe that it's durable and viable to develop operations in the Barents Sea, but we have chosen to allocate upon elsewhere.

[Operator]

We'll now take the next question from Karl Fredrik Schjøtt from ABG.

[Karl Fredrik Schjøtt-Pedersen]

A question regarding dividends. Do you feel that there's large political pressure for you not to raise dividends at the Capital Markets Day next year? That would be the first question. The second question relates to the new project and in terms of news flow on the full hopper that you present today. What should we look for in terms of news flow on these projects?

[Karl Johnny Hersvik, Chief Executive Officer]

Thanks, Karl Fredrik. So on dividends, I think I just reiterate what I've already said. It's, of course, helpful when we're now financing. But the Board has made the changes to the dividend policy that we had in place previously. But when it comes to new dividend policy, we'll refer those discussions back to the Capital Markets Update in February. When it comes to news flow, I think, first and foremost, we, of course, plan to run through all these assets, projects and early base prices in somewhat detail, a significant more detail than, of course, today, of course, at the Capital Markets Update. So I think that would be your first touch base in terms of news flow. And then I stated in my presentation that we'll continually operate the markets along 3 main lines. The first one, of course, is the quarterly presentations. Then of course, as we keep on passing decision gates, we will, of course, inform the market as the activities and performance of those decision gate passengers. And then thirdly, there will, of course, be a contract and other, I would say, market communication related to activities carried out by the project themselves. So I think the best advice Karl Fredrik is to stay tuned.

[Operator]

The next question comes from James Hosie from Barclays.

[James William Hosie, Research Analyst]

I was just wondering if you could expand a little about what the new operating model actually entails. I mean you mentioned standardization, in answering an earlier question, but is that -- I'm just wondering, is it investing in technology to increase automation or remote operations, both headcount reductions? Really just if you can give a bit more detail on what's actually going to be done differently?

[Karl Johnny Hersvik, Chief Executive Officer]

Thanks, James. Just to be clear, I haven't paid James anything to ask that question. So it's actually all of the above. I think the way of thinking about this is that since 2016 we have been focusing on improvement quite significantly at Aker BP. And we've done that, I would say, along 3 main lines. The first one is to reshape the, I would say, the way we procure services and goods. We've talked about that as an alliance model. We, of course, spent significant time, money, experience in the digitalization, as you might have seen. In fact, we have now got the pricing on Cognite with the entrance of excellence into that company which also proved that this activity from an Aker BP perspective was actually value-accretive as well as an awful lot. We've been focusing on process optimization using the lean program, and we talked a lot about flexible models. And it's quite clear that this has been quite a bit of experimentation. That means that different assets have different books in the portfolio. And in the same time, we've been really focusing hard on production optimization, getting the uptime to where we like it to be, getting the operations to a stable environment, getting execution right, getting the basics in place. And what we're doing now with the operation model is we're taking all of these pieces, and we're putting that into a systematic framework and implementing them in a consistent way across the portfolio. So we're using all these experiments, and we're basically running that into a structured process. We couldn't have done that 2 years ago, to be honest, because we didn't really know how digitalization we're working with business processes, our alliances and in-sourcing and outsourcing would impact our data flow, et cetera. So we are relying on those experiments and those, I would say, development programs that we've done. So the 3 -- to me the 3 key figures are as follows: It's consistent planning based on flow efficiency, using the lean experiments, both onshore and offshore. It is a consistent framework from an operational perspective in terms of organization, meaning that there will be some redundancies related to the implementation of the operation model. And it's the implementation of digital solutions wherever we can, and that will span from remote operations, remote inspections, condition-based monitoring and maintenance, handheld units to simplify processes offshore, et cetera, et cetera. So basically, the way to think about this is the application and the, I would say, implementation of all the improvement work that they're ongoing in Aker BP since, I would say, 2016. And now it's time to put this into one operating model, and we're going to call this the Aker BP model. I actually am really hopeful that this will mark a real threshold in terms of operational performance. And turning oil & gas operations into similar -- or more similar to onshore operations then in terms of consistency, performance and cost efficiency.

[Operator]

We'll now take the next question from James Carmichael from Berenberg.

[James Carmichael, Analyst]

Just a couple of quick ones on the assets for me. I was just wondering if you could provide a bit of color on the choke influx that you mentioned at the new wells at Valhall, just how significant is that? And are there any set basis you can take to mitigate that in future drilling programs? And then also just quickly on Johan Sverdrup. Just wondering if you could provide any sort of indications of the potential upside you're targeting in the Phase 1 facilities?

[Karl Johnny Hersvik, Chief Executive Officer]

Okay. Good. Let me start on Valhall. So currently, we have choke influx in -- and some reasons to drill some wells at Valhall, this is -- talking to Valhall is really nothing new. It's been a problem since the field was put on stream. And usually, we clean out these wells using coil tubing pretty much immediately. The reason this now becomes a bottleneck is that we're also stimulating wells using the same possible units that we should use cleaning out these wells. We are experimenting with a machine learning algorithm to predict chalk influx as we have been unsuccessful as of the industry of predicting chalk influx using empirical mathematical models. There are some positive results coming out of that work. So we are believing that over time we'll be better faced to pull those and predict, which is the key to avoiding the chalk influx. We are investigating other lower completion technologies that is different track problems, different binders, different mixed frames when pumping the frac frames, et cetera, but also different solids screen out, yes. It's not really screening, but it's more about solid controlled on Valhall. And thirdly, we are assessing different chemical properties to resolidify the chalk after you've seen a chalk influx. So there's quite a lot of activity going on. And to us this is really important because stepping up the system on a control will reduce cost because all this contributed work is, of course impact. But it will also allow us to drill other wells, simple wells, to realize 1 billion barrel at Valhall. Now when it comes to -- when it comes to you onsite, I'll leave it to the operator to disclose details on that in testing program but it, of course, means that we are stress testing and looking for new bottlenecks. And as I've talked about in previous presentations, we are now at a level where we assume that we will meet several of these bottlenecks at the same time or very close to each other in time. So it's a more complicated testing machine that we've seen in the box.

[Operator]

The next question comes from James Thompson from JPMorgan.

[James Thompson, Analyst]

Great. I've got all the James in a row just then. Karl, I just wanted to ask you a little bit about, obviously, the development projects that you've outlined there. You've got 11 projects to sanction by the end of 2022, which in the first instance, feels to me like quite a lot of projects to get done in the organization. And your commentary sounded a bit more like an aim rather than a commitment. The questions really were, is there a plan here that you effectively get these sanctioned and then you sort of stage the investments? It's very clear that your focus on NOAKA and getting that done first, but you just really want to just take the other bits off before you pursue sort of significant development CapEx on them. And also just thinking about the investments there if 3 going into Skarv, another 3 going into Alvheim. Are there any sort of capacity issues in terms of total liquids that might cause you to sort of spread those out over the next 5 or 6 years?

[Karl Johnny Hersvik, Chief Executive Officer]

If I said James, that sounded like an ambition, then let me clarify that immediately. So while there certainly as an ambition, we're staffing all of this project for execution. So we're not playing a game here we throw up a lot of projects. And then some way down the road, discover that they will end up different. They were really running very hard now to execute the project in accordance with what we set out to do in the summer with the temporary tax changes. We're not kind of playing a game here at all. So that means that we're also working really hard to staff these projects. And you're right. It's a stretch, to staff all of this. In Garantiana, of course, is Equinor operated project. And Alvheim is also an Equinor operated project, but we are collaborating with Equinor in the -- this area to do a field development of 4 tiebacks in Alvheim and Skarv in the area. So I don't know if it is part of that. These other projects. If you think about this from an Alvheim perspective. It's a pretty almost right on the milk, so that it's easy. None of these projects are easy, but we know how to do it. There's not a lot of, let's say, new concept development that needs to be done. And we're kind of putting them into an already, I would say, robust execution machine. Valhall is a little bit of a new one chalk depending on solution. But again, the alliance is already on it, worked really hard and that we end up with a solution that's more, I would say, industrial in nature, we can also rely on hopping effects. So each of these projects have their own dedicated team, their own dedicated project leads. We follow them up every month in my effective management team. For us, this is actually fundamental to the valuation potential of Aker BP. So let me be very clear, this is something that we're spending a lot of effort on. We truly believe, as a consequence that it is doable to execute these projects and be FID by 2022. And then to us, execution is a part of getting these projects phased in through our rig lines, our production lines with the alliances and on yards, particularly in Norway and other. So execution in terms of detailed time lines will be a part of the total activity level on the Norwegian contract itself. But right now, I feel that we have very good control over these projects, particularly with the alliances now working on them. And that also gives us a huge muscle for us. So as a company, if we were to execute all of this using a conventional model, I will be doubtful to our ability to execute with quite a few years of experience within the alliance model now I'm actually without a doubt we will be able to execute this project. And that also perhaps volumes -- speaks volumes to the strength of the alliance volumes in addition to currently being costs under control, keeping quality under control, just gives us a huge muscle in terms of execution of this project.

[James Carmichael, Analyst]

All right. Okay or to the FID. And I just wanted to follow-up on the question of the operating model. Are you able to sort of quantify what the sort of formalization of all the improvement work you've done over the last 3 or 4 years, means in terms of that kind of operating cost per barrel? Is it kind of worth of sort of $1 to $2 a barrel to you over the long term? Is that the ambition?

[Karl Johnny Hersvik, Chief Executive Officer]

It's a good question, and it's something we're asking ourselves all the time. That's a question of how the actual value of cost and value and an income on each of these activity programs and improvement programs. So the way I think about this, it's more in terms of development. We are basically now seeing activity levels up or higher than we saw 2 years ago. But we are seeing decreasing underlying costs. Against the same, I would say, outflow in terms of cost per hour, to vendors, et cetera. We're seeing production efficiency trend consistently upwards, meaning that we're driving production up as well. And there's a certain amount of activity that is behind that production efficiency increase. So while there is no doubt that these improvement programs have provided meaningful reduction in cost per barrel, allocating, I would say, $1 per barrel to each of these activities is more difficult. So what we try to do now, and we're set ourselves a quite ambitious target internally, and we'll communicate those to the market at the Capital Market Update and give you a lot of transparency in terms of program and agile ambitions, but they're quite significant in nature. So they're not incremental in nature when you think about the improvement program. And it's basically a continuation of a trend that we'll see or at least the last 3 or 4 quarters.

[Operator]

The next question comes from Sasikanth Chilukuru from Morgan Stanley.

[Sasikanth Chilukuru, Research Associate]

I had 2, please. The first was regarding the expected oil breakeven price. And apologies, if I -- if you've already mentioned that and I missed it. I was just wondering given that you now have indicative guidance for production, CapEx and production cost for 2021, where do you think the crude breakeven price for 2021 is before the dividends, I suppose, if you can give an indication, that would be helpful. And the other one, was also related to the breakeven oil price but for the projects. You mentioned less than $30 breakeven prices. I was just wondering, the field evaluation cost that you mentioned in 2021, particularly for NOAKA, is that included in that breakeven oil price that you highlight or is it post FID?

[Karl Johnny Hersvik, Chief Executive Officer]

So, David, you can answer the first question.

[David Torvik Tønne, Chief Financial Officer]

Yes. Thank you for that. So probably a bit too early to go into too much detail on this. But I think what we have presented today, we are talking about free cash flow breakeven at or below $30.

[Karl Johnny Hersvik, Chief Executive Officer]

And when it comes to breakeven. On MPE breakeven. So the way that is calculated is simply all costs into the project and we don't really differentiate between CapEx and OpEx and all these other cost elements. So of course, field evaluation leading up to which is a part of the breakeven. It is a cost that is incurred because of the budget. So of course, it's included in the break. And this is also why we talk about full life cycle breakeven and not pre -- post FID breakeven, which is a very different number. Of course, all of these projects as you trend towards production staff, that will be lower than $30 per barrel. So that becomes a little bit of a meaningless game. Just this is about capital allocation, and therefore, we need to see the entire COGS picture on this project.

[Operator]

The next question comes from Michael Alsford from Citi.

[Michael James Alsford, Director]

I just got 1 left, please. So Karl, you made a clear rationale of why you're prioritizing organic growth rather than chasing M&A. But on the flip side, you're targeting around 60% of your contingent resource base with the next pipeline of development projects. Are there any non-core resources in the portfolio that we might see you dispose off in the short-term where others maybe haven't got the resource base that you have blessed with?

[Karl Johnny Hersvik, Chief Executive Officer]

That's an excellent question, Michael. Yes. We have around 915 million barrels in 2C resources. And of course, we are receiving a lot of incoming, I would say, requests for 2C resources. I also stated that this is probably the most interesting investment environment in the E&P right now, which also has an effect on pricing and willingness to pay for these 2C resources. Most of these 2C resources that are now, is having in the hopper were either, I would say, doing from an exploration portfolio and probably around $1.1, $1.2, maybe on average per barrel or through M&A activities at basically the same level. So yes, there is a discussion whether or not some of these resources could be divested, but I won't be -- I won't dive into details on these discussions. I think we've given a lot of clarity on which project we are now prioritizing in terms of credit -- or capital allocation. And then there's question also allocated to M&A. Yes, you're quite clear that the -- however we are quite clear that organic growth is a priority at this point in time. And while M&A is not entirely off the table, it will be rather disciplined to see that kind of activity, at least when it's portraying CapEx for the time being.

[Kjetil Bakken, Vice President of Investor Relations]

I think we have time for only 1 more question now before we have to close the discussion.

[Operator]

There is no further questions in the queue at this time.

[Kjetil Bakken, Vice President of Investor Relations]

Okay. That is good. I hope that you have got all your questions answered. And if not, then the IR team at Aker BP is at your disposal. We wish you all a great day, and please stay healthy.

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you.