Everyone, 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 two in the presentation. With that, I leave the floor to Karl Johnny.
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 higher oil prices, but we deliver strong performance within most the areas with control. We are well on track to deliver our production guidance for the year. Our development projects are progressing as planned, and we are keeping costs under control as well as emissions. Finally, we generate a free cash flow that more than covers our cost and dividends in the quarter. Our vision is firm. 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 the refinement and implementation of a new operating model, aiming to further improve efficiency, safety, and cost through standardizing best practices across all our operated assets. We also continue to focus on and improve our financial flexibility, this time through a bond refinancing which have increased our liquidity, reduced our interest cost, and extended the maturity profile of our debt. Now the time has finally come to start talking about growth once again. In a time when many of our peers are struggling to make ends meet, we think it's time to be counter-cyclical.
The temporary changes made to the tax system this summer was aimed at improving activity levels in the E&P industry. Aker BP with our huge inventory of 2 C resources with low breakeven, is uniquely positioned to benefit from this golden opportunity to potentially double our production. In sum, 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. 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 marginal negative trend compared to the first two quarters in 2020. This is mainly due to a 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 bbl 20% below the original guidance from February. Our CO2 emissions ended up below our targeted 5 kg per bbl , firmly 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. 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, pull-in operations, turnarounds, and emergency shutdown tests. At Valhall, however, both production and production efficiency increased in the third quarter. The production ramp up and regularity at Johan Sverdrup also continued to impress. During November, further testing of the upside to phase one capacity at Johan Sverdrup will be performed. For the first nine months, our average production was 206,500 bbl 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. Therefore, we are well on track to deliver our production guidance for the year, which we have now narrowed into 210,000 to 250,000 bbl, as there is only one 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 kg per bbl of oil equivalent, in line with our target of less than 5 kg per BOE. This is less than a third 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 through three main channels.
First, to maximize the value creations for our assets and activities. This means that we also maximize the profits we can distribute 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. Third, we believe we can also contribute into the transition through sharing of data, knowhow, 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 and gas assets on the Norwegian Continental 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 and gas assets. 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 represent a 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.
Firming up the organizational structures based on asset size and complexity. Better integrated planning and reduced activity set through tougher scrutiny and prioritization of the activity set. New ways of working using digital solutions matured from our Eureka X effort. 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 bbl.
I talked about growth, let's move to the update on our development projects. We will start with the highly profitable Ærfugl project, which is on track for production startup during the next months with three production wells. This will mark the completion of the phase I of the project. Phase II of the project is also well underway, with one well already on production and two 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, semi alliance have all been vital in this project, with major improvements since PDO, including accelerated development of phase II, 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 valve trees and an electrical heated pipelines extending more than 60 km to cover the Ærfugl reservoir. 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 project are also progressing well, and the construction of the Hod facility is well underway in the Kværner Yard at Verdal. The subsea alliance have completed the first offshore campaign by preparing for a hot tap operation that will take place next year. The modification alliance have commenced detail engineering and will be ready to start offshore work by the end of the year. Production start at Hod is planned for first quarter 2022. Moving on to Johan Sverdrup. It has during the first year of operation, produced some 130 million bbl of oil in total. Experience from the first year in operation have shown continued high regularity. As I mentioned initially, testing of further upside to phase I capacity at Johan Sverdrup will be performed in November. This is of course, very encouraging.
In parallel, phase II of Johan Sverdrup development has progressed well and in accordance with the PDO and startup scheduled for the fourth quarter of 2022. In addition to these development projects in the execution phase, we have a large hopper of resources that we're currently working to mature towards a final investment decision. This resource base represents a unique runway for further organic growth out of the company, both with regards to size and the quality in terms of low breakevens.
The recent tax changes have further lowered the breakevens as well as significantly reduced the capital commitments 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 73% of the CapEx being covered by tax deduction 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 a challenging macro environment, can take counter-cyclical approach and deliver significant organic growth without putting strain on the balance sheet. Of course, deliver significant activity into the Norwegian E&P vendor space, as was the design of the temporary tax changes.
Let's take a closer look at some of these growth opportunities. The biggest single item in our resource base 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 NOA and Fulla development.
A concept select decision is planned for the third quarter of 2021. Equinor, as operator of Krafla, has mobilized their project organization and collaborate closely with Aker BP to optimize the area development concept. The 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. We're also working to mature several other projects within this timeline. These projects were in our plans prior to the combined COVID and oil price shock in March, when we decided to freeze all non-sanctioned project 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.
Now we are continuing to mature these projects, which represents more than 500 million bbl of oil equivalents 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 hurdle of $30 per barrel in a full life cycle NPV10 breakeven. If we manage to keep this schedule, we are looking at a company that will roughly double its production over the next seven to eight years. NOAKA is obviously the largest project on the list. Most other projects are linked to our existing operated hubs. Some of these are a result of successful exploration, like Frosk, Skrekk, and Ørn. Trell and Trine and Alve Nord are examples of discoveries we have acquired in this period.
Meanwhile, the Kobra East & Gekko and the Valhall project are initiatives to unlock additional resources within our existing producing asset base. We will continue to systematically mature these project and will provide more information as we progress them through their decision gates. 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. 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 bbl we just talked about at breakevens 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 is 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 CapEx while reducing our leverage ratio. 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 status here in Aker BP, and I give the word over to our CFO, David Tønne.
Thank you, Karl, good morning, everyone. Aker BP's net production in the third quarter was 202,000 bbls 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, the sold volumes ended at 188,000 bbls per day. Both liquids and gas prices increased quarter on quarter, and the realized average hydrocarbon price was up approximately 41% and ended at $38.80 per bbl of oil equivalents.
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 touchly brief upon the breakdown of liquids price realization. We observed a decent recovery in Brent prices from April to June and a convergence of Platts Brent Dated and the front-end Brent contract traded in the financial market.
In the third quarter, the recovery slowed down. Brent traded in the $40-$45 range, and the average Brent dated in the period was $42.90. Aker BP realized a positive differential of $0.80, and together with a small positive timing effect, the realized crude price ended at $43.80 per bbl. The positive differential in the third quarter stands in sharp contrast to the - $1.80 experienced in the second quarter. Although this is a clear indication that the physical market has improved over the last three 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 markets in the fourth quarter. Adjusting for NGL, Aker BP's average liquids price was $42.70 per bbl. Now, moving over to the income statement.
As mentioned, total income was $684 million. This is an increase of 16% from the second quarter. Production cost of sold volumes were $134 million. The production cost related to the produced barrels amounted to $136, or $7.30 per bbl. 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 on 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 cost, 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 as spending related to early phase project development, including NOAKA, are accounted for as field evaluation expenses, also expex, before concept 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 $14.50 per bbl, 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 was 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 at $ 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 NOK 43 million. We had additions of NOK 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 NOK 17 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 NOK 661 million is the net of the NOK 1.25 billion in bond issuance in September and the repayment of the debt note 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 potential in Aker BP going forward. We have the opportunity to double the company's production over the next seven to eight 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.
Seven months into one of the most dramatic 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 2nd, 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 market 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 spend categories, with CapEx being over 80%.
Free cash flow before financing was thus $ 195 million, and the other cash flow to financing here mainly consists of a realized loss on the cross-currency interest rate swap related to the DETNOR02 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 calling the 2022 bond in October. Based on current oil price levels, Aker BP expect a tax refund for the full fiscal year of 2020.
This summer, we estimated the three tax installments to be refunded in the second half of 2020. In the third quarter, we received the first installment of $109 million. In the fourth quarter, we will receive two 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. 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, provide some initial flavor on what we currently expect for 2021. Production year-to-date is 206,000 bbls per day. In the fourth quarter, we expect both the Ærfugl project phase 1 and the newly drilled Kameleon Infill Mid well at Alvheim to come on stream. As we now only have two months left of the year, uncertainty is reduced, unless there are any unforeseen project delays or production outages, we expect 2020 production to end between 210,000 and 215,000 bbls 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 $8.40 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 bbl was $7.30, 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 cost to end at roughly $8 per bbl. The original guidance for the year was $10, but we updated this in the second quarter to $7-$8 as we reduced activity, accelerated cost reductions, and the Norwegian kroner significantly weakened. The updated guidance assumed a dollar NOK rate of 10.
Lately, the Norwegian kroner has been stronger. This is the key driver for why we now forecast to end in the higher part of the updated range. For 2021, I am 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 US dollars. CapEx year to date is roughly $1 billion. Our key projects are progressing as planned. 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 expex is NOK 166 million. We are currently drilling the Alvheim Northeast well, and in the fourth quarter, we plan to drill two non-operated wells, Baske and Merkes. Based on an assessment of spend so far and the planned activities for the remaining part of the year, we expect 2020 spending to end at roughly NOK 300 million, down NOK 50 million from previous guidance.
Abandonment expenditure year to date is NOK 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 NOK 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.
In addition, we plan to drill production wells in all our operated 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 concept 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 wells, 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 all CapEx in 2021 qualifies for the temporary fiscal regime. 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. 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 the next five years.
This means that if we, say, invest $2 billion in 2021 across the three spending categories, the after-tax cash flow of that spending is roughly $500 million in year one. The plan for 2021 will be further matured, also with input from our license partners up to year-end. 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 remarks before we open up for questions. Thank you.
Thank you, David, for a walkthrough 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. We will continue our relentless focus on operational excellence, which is basically about maintaining safe and efficient operations with good cost control. We will continue to focus on strong project management and to deliver our development project 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 large 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 bbls 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 bbl. 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. We are now ready to take your questions.
Thank you. If you would like to ask a question, please press star one on your telephone keypad. Please ensure the mute function on your telephone is switched off to allow your signal to reach our equipment. If you find your question has been answered, you may remove yourself from the queue by pressing star two. Again, please press star one to ask a question. We will now take our first question from Alwyn Thomas from Exane BNP Paribas.
Hi. Good morning, guys. Thanks very much for the questions. I guess if we just start off reasonably high level. You've got a bit of a war chest now after the recent bond raises. I wanted to ask you how you think about using that and whether M&A comes into it, particularly as you've got 500 million bbls of resource that you can put into action relatively quickly over the next couple of years.
Is that really the priority for that money at the moment? Perhaps, Karl, maybe get your thoughts. Maybe we're a bit too early here to ask this, can I get your thoughts on what you think about the dividend level at the moment? Like I said, if things are slightly improving and obviously the tax regime is starting to help as well on the cash flow basis, whether we can see an increase in dividend early next year.
Thanks, Alwyn. Excellent questions as always. 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. 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, a volatile oil price environment. 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 VUCA world, and now we're actually living one.
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. That, of course, also means that, as you probably realized from our presentation, our primary focus now is to realize the early-phase projects that are ongoing, roughly 500 million bbls. With the $30 breakeven, it's really difficult to see how M&A should compete. As always, we will be disciplined when it comes to M&A. We are a company that's all about value creation.
While M&A is not entirely off the table, it of course, will need to be more profitable than the alternative investment into organic CapEx. 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. We'll come back to that in more detail in February, Alwyn.
Okay, thanks very much.
The next question comes from Teodor Nilsen from SB1 Markets.
Good morning, thanks for taking my questions. Karl, you highlighted that in your investment proposition, low OpEx is very important. 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? Thank you.
Teodor. Well, I must admit that I actually expect some cost escalation as we increase our investment portfolio in the Norwegian E&P space. To some extent, this is actually desirable. If you remember back, the idea among this contemporary tax change was to ensure that the vendor industry, one, had a sufficient influx of, I would say, activities, and two, that these activities generated a positive result for these companies, right? It's not necessarily just about surviving, it's also about actually being able to run through that transition. I think that's my point of departure on that discussion. I think the primary strategy from an Aker BP perspective is along two main lines.
When it comes to how we deal with the vendor market, we've been, for a long time now, working within these alliance structures. I think around 95%, maybe, of our CapEx is currently passing through different alliances. The OpEx is similar or trending similarly. 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.
Now we're starting to, now that that is 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 procurement processes. At least there's a solid plan in place. 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. We'll come back to this in detail when we come to the capital market update in February.
Okay. Thank you.
The next question comes from Anders Holte from Kepler Cheuvreux.
Hi. Good morning, guys. Thanks for taking my questions. Apologies if there are some sound effects in the background here, 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 the increase in 2021 that you give on your slide is due to FX rate, and how much of it is due to underlying costs coming up. 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? Thank you.
Hi, Anders. I can do the question around guiding on cost level. The slight increase indicated for 2021 on OpEx per barrel is primarily driven by effects. If you refer to the footnotes on the slide, we are basically assuming NOK 9 per dollar as average for 2021 compared to the average what we've seen this year is more close to NOK 9.5. 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 per project as of now, but I assume we will provide some more details on the NOAKA project, Karl, when we get back to the capital markets update.
Absolutely, Anders. Also remember that before DG2, this is field evaluation cost, meaning OpEx. DG2 is planned for Q3 2021, right? There will be a limited CapEx spend for NOAKA and most of this field evaluation or study cost is now being projected as OpEx. Then maybe an additional comment to the 2021 OpEx per barrel. In his remarks, David also talked about the underlying cost performance. While the change in dollar per barrel is primarily driven by FX, the activity level is somewhat increased. The underlying cost performance, if you view it from a resource utilization point of view or an activity point of view, is declining.
Very well. Thank you.
The next question comes from Yoann Charenton from Societe Generale.
Good morning. Three 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 refunds has changed dramatically on the $50 scenario. Could 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 shore solutions across your existing hubs? And second, 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 Barents Sea in recent licensing rounds? Thank you.
Hi, Yoann. I can do the tax question, and then I'll leave the word over to Karl. On page 21, we illustrate the tax for the fiscal year 2020. Meaning based on the results in 2020, we pay six installments. Three of them are paid in second half of 2020, and three of them are paid in the first half of 2021. What we are indicating here on the slide is basically what the installments will be, basically here as a tax refund, depending on what the oil price will be in the fourth quarter this year.
We have, of course, now three quarters of actuals, and then depending on oil price in the fourth quarter, that indicates the total results for the year. We have already fixed the three first installments. The variable is the three installments in the first half of 2021. That's what the $50 scenario here indicates. Kjetil has an additional comment there.
Yes. Hi, Johan. One additional comment there 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. That's why the bars have narrowed in.
That's great. Thank you.
Thanks, Johan. For the other two questions, if you start asking these difficult questions, David and I may have to change roles so I can answer tax questions and he can do the more environmental discussions. Hey, David. Yeah. Power from shore. We are assessing power from shore concretely, of course, related to NOAKA, which will be powered using an onshore grid connection.
That is already decided. There is, of course, questions whether or not this could form some sort of system where offshore wind production is finding an offtake in the NOAKA area, maybe in addition to a power from shore solution, where the volatility or, I'd say, flexibility in the offshore wind production will be countered by power from shore. The discussions such as these are, of course, ongoing and also ongoing at other assets, both operated by Aker BP and other companies.
There are discussions related to existing operational assets, both of those who are now ramping up to be powered from electricity is, of course, Ivar Aasen already in 2022 as a part of the Utsira electrification that is ongoing at the moment. Ivar Aasen is already powered and doesn't really have a power production going on at Ivar Aasen. It is powered using gas turbines at Edvard Grieg, which when these gas turbines are decommissioned and replaced by power from shore, it will be entirely electrified. 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 FPSOs is a technology novelty, but we are assessing them.
When it comes then to, let's say, other possibilities in terms of offshore wind, Norway has released two areas for application of offshore wind. That is the southern North Sea, very close to Valhall, in fact, and it is the Utsira area, which is just in from the NOAKA field developments. It brings up discussions around how offshore operations can be utilized, current infrastructure offshore in oil and gas can be utilized to improve offshore wind installations. There is a 100 MW HVDC line out to Valhall, the longest HVDC line on the industry, empowering an offshore installation at 295 km. We are in the middle of all of these discussions, and as soon as we have more clarity, Johan will come back with more details.
When it comes to the Barents Sea, 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. Let me not leave any doubt about that on the table. It is entirely possible, as has been proven already, to do this in the Barents Sea. It's not a particularly difficult regime to operate in.
Yeah, it's dark and somewhat cold, but it's not more difficult than the Norwegian Sea. 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. To us, this is mostly about a commercial decision where we believe that our exploration cost is better spent elsewhere.
Two, that we have a really large organic growth hopper that we'd like to mature and don't necessarily see the need to go looking for long-in-the-tooth assets in the Barents Sea. Thirdly, this is also about a geological assessment of the opportunities we've seen in the Barents Sea. Let me go back and say that we entirely believe that it's doable and viable to develop operations in the Barents Sea, but we have chosen to allocate our funds elsewhere.
Thank you. That's very clear.
We'll now take the next question from Karl Fredrik Schjøtt from ABG.
Hi, guys. Thank you for your presentation. 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 NOA Fulla that you presented today. What should we look for in terms of news flow on these projects?
Thanks, Karl Fredrik. On dividends, I think I'll just reiterate what I've already said. It's of course helpful when we're now out financing that the board has made the changes to the dividend policy that we had in place previously. When it comes to a new dividend policy, we'll refer those discussions back to the Capital Market 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-phase project in somewhat detail at significant more detail than today, of course, at the Capital Market Update. I think that will be your first touch base in terms of news flow.
Then I stated in my presentation that we'll continually update the market along three main lines. The first one, of course, is the quarterly presentations. Of course, as we keep on passing decision gates, we will of course inform the market as to activities and performance of those decision gate passages. Thirdly, there will of course be contracts and other, I would say, market communication related to activities carried out by the project themselves. I think my best advice, Karl Fredrik, is to stay tuned.
Thank you.
The next question comes from James Hosie from Barclays.
Hi, good morning. I was just wondering if you could expand a little about what the new operating model actually entails. I mean, you mentioned standardization when answering an earlier question. Is that it? I am just wondering, is it investing in technology to increase automation or remote operations? Is it headcount reductions? Really just if you can give a bit more detail on what is actually going to be done differently.
Thanks, James. Just to be clear, I haven't paid James anything to ask that question. 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 in Aker BP. We've done that, I would say, along three main lines. The first one is to reshape the, I would say, the way we procure services and goods. We talked about that as an alliance model. We of course spend significant time, money, experience into digitalization, as you might have seen. In fact, we have now got the pricing on Cognite with the entrant of Accel into that company which also proved that this activity from an Aker BP perspective was actually value accretive as well as we've learned an awful lot.
We've been focusing on process optimization using the Lean program, and we talked a lot about flexible models. It is quite clear that this has been quite a bit of experimentation, and that means that different assets have different focus in the portfolio. 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. What we're doing now with the operation model is we're taking all of these pieces and we're putting them into a systematic framework and implementing them in a consistent way across our portfolio. We're using all these experiment and we're basically running that into a structured process now.
We couldn't have done that two years ago, to be honest because we didn't really know how digitalization, we're working with business processes, how alliances and insourcing and outsourcing would impact our data flow, et cetera. We are relying on those experiments and those, I would say, development programs that we've done. To me, the three 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. 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.
Basically the way to think about this is the application and the, I would say, implementation of all the improvement work that's been ongoing in Aker BP since, I would say 2016. 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 and gas operations into more similar to onshore operations in terms of consistency, performance, and cost efficiency.
We'll now take the next question from James Carmichael from Berenberg.
Hi. Morning, guys. 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 chalk influx that you mentioned at the new wells at Valhall. Just how significant is that, and are there any measures you can take to mitigate that in future drilling programs? Then also, just quickly on Johan Sverdrup, I'm just wondering if you could provide any sort of indications of the potential upside you're targeting in phase one facilities. Thanks.
Yeah. Okay, good. Let me start on Valhall. Currently, we have chalk influx in, if memory serves me right, four wells at Valhall. The chalk influx at Valhall is really nothing new. It's been a problem since the field was put on stream. Usually, we clean out these wells using coiled tubing pretty much immediately. The reason this now becomes a bottleneck is that we're also stimulating wells using the same coiled tubing 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, us as 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 placed to prognose and predict, which is the key to avoiding the chalk influx.
We are investigating other lower completion technologies, that is different frac pumps, different binders, different liquid trains when pumping the frac trains, et cetera. Also different solids screen out. It's not really screen, but it's more about solids control downhole. Thirdly, we are assessing different chemical properties to re-solidify the chalk after you've seen a chalk influx. There's quite a lot of activity going on. To us, this is really important because getting the system under control would reduce cost because all this coiled tubing work is, of course, OpEx.
It'll also allow us to drill other wells, simpler wells, to realize a 1 billion bbl at Valhall. Now, when it comes to Johan Sverdrup, I'll leave it to the operator to disclose details on that testing program. It, of course, means that we are step testing and looking for new bottlenecks. 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. It's a more complicated testing regime that we've seen in the past.
Thanks very much.
The next question comes from James Thompson from JP Morgan.
Hello, great. Thanks very much. Questions, you 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 you're focused on NOAKA and getting that done first, but you just really want to just tick the other bits off, too, before you pursue significant development CapEx on them. Also just thinking about the investments there, three going into Skarv, another three 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 five or six years? Thanks.
If I said things that sounded like an ambition, then let me clarify that immediately. While it certainly is an ambition, we're staffing all of these projects for execution. Right? We're not playing a game here where we throw up a lot of projects and then some way down the road discover that they will end up different. We're really running very hard now to execute these projects in accordance with what we set out to do in the summer with the temporary tax changes. We're not playing a game here. Not at all. That means that we're also working really hard to staff these projects. You're right, it is a stretch to staff all of this.
Gardar, of course, is an Equinor-operated project, and Ørn is also an Equinor-operated project, but we are collaborating with Equinor in this area to do a field development of four tiebacks to Ørn and Skarv in the area. Ørn is a part of that. These are the projects. If you think about this from an Alvheim perspective, it's almost run-of-the-mill. It's not that it's easy. None of these projects are easy, but we know how to do it. There's not a lot of, say, new concept developments that needs to be done. We're kind of putting them into an already, I would say, robust execution machine. Valhall NCP is a little bit of a new one to us, depending on solution. Again, the alliance is already on it.
We're working really hard, and if we end up with a solution that's more, I would say, industrial in nature, we can also rely on copying effects. Each of these projects have their own dedicated team, their own dedicated project lead. We follow them up every month in my executive management team. To us, this is actually fundamental to the value creation potential of Aker BP. 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 do FID by 2022.
To us, execution is a part of getting these projects phased in to our rig lines, our production lines with the alliances and on yards, particularly in Norway. Execution in terms of detailed timelines will be a part of the total activity level on the Norwegian Continental Shelf. Right now, I feel that we have very good control over these projects, particularly with the alliances now working on them. That also gives us a huge muscle, right?
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 with the alliance model now, I'm actually without a doubt that we will be able to execute these projects. That also talks volumes and speak volumes to the strength of the alliance models, in addition to kind of keeping cost under control, keeping quality under control. It just gives us a huge muscle in terms of execution of these projects.
All right. Okay. Good. Look forward to the FIDs. 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 or improvement work you've done over the last three or four years means in terms of that kind of operating cost per barrel? Is it kind of worth a sort of $1, $2 a bbl to you over the long term? Is that the ambition?
It's a good question, and it's something we're asking ourselves all the time, right? It's a question of how do you actually value or put a cost and a value and an income on each of these activity programs and improvement programs, right? The way I think about this, it's more in terms of development. We are basically now seeing activity levels at or higher than we saw two years ago, but we are seeing decreasing underlying cost 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.
While there is no doubt that these improvement programs have provided meaningful reduction in cost per barrel, allocating, I would say, $1 per bbl to each of these activities is more difficult. What we're trying to do now, and we've set ourselves quite ambitious targets internally, and we'll communicate those to the market in the capital markets update and give you a lot of transparency, both in terms of program, financial ambitions. They're quite significant in nature, so they're not incremental in nature when we think about the improvement program. It's basically a continuation of a trend that we've seen over at least the last three or four quarters.
Okay, great. Look forward to it. Thanks. Hand over.
The next question comes from Sasi Chilukuru from Morgan Stanley.
Hi. Thanks for taking my questions. I had two, please. Apologies if you have 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 break-even price for 2021 is? Before the dividends, I suppose if you can give an indication, that would be helpful. The other one was also related to the break-even oil price, but for the projects. You mentioned less than $30 of break-even prices. I was just wondering, the field evaluation cost that you mentioned in 2021, particularly for NOAKA, is that included in that break-even oil price that you highlight, or is it post-FID? Thanks.
David, you can answer the first question.
Yeah. Thank you for that. Probably a bit too early to go into too much detail on this, but I think with what we have presented today, we're talking about a free cash flow break even at or below $30.
When it comes to break even and NPV10 break even, so the way that is calculated is simply all costs into the project. We don't really differentiate between CapEx and OpEx and all these other cost elements. Of course, field evaluation leading up to DG2 is a part of the breakeven. It is a cost that is incurred because of the project. Of course, it's included in the breakeven. This is also why we talk about full life cycle breakeven and not post FID breakeven, which is a very different number. Of course, all of these projects, as you trend towards production startup, will be lower than $30 breakeven. That becomes a little bit of a meaningless game. To us, this is about capital allocation, and therefore we need to see the entire cost picture on these projects.
Very helpful. Thank you.
The next question comes from Michael Alsford from Citi.
Hi there. Thanks for taking my question. I've just got one left, please. Karl, you made a clear rationale of why you're prioritizing organic growth rather than chasing M&A. On the flip side, you're targeting around 60% of your contingent resource base for the next pipeline of development projects. Are there any non-core resources in the portfolio that we might see you dispose of in the short term where others maybe haven't got the resource base that you have blessed with? Thanks.
That's an excellent question, Michael. We have around 915 million bbls in 2 C resources. Of course, we are receiving a lot of incoming, I would say, requests for 2 C resources. I also stated that this is probably the most interesting investment environment in E&P right now, which also has an effect on pricing and willingness to pay for these 2 C resources. Most of these 2 C resources that are now residing in the hopper were either, I would say, 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 levels.
Yes, there is a discussion whether or not some of these resources could be divested, but 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 capital allocation. This question also allocated to M&A. You're quite clear that organic growth is a priority at this point in time. While M&A is not entirely off the table, we'll be rather disciplined to see that kind of activity, at least when it's portraying CapEx for the time being.
I think we have time for only one more question now before we have to close the discussion.
There is no further questions in the queue at this time.
Okay. That is good. I hope that you have all got 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.