Good morning, everyone, and welcome to Aker BP's first quarter 2020 presentation, which will be given today by CEO Karl Johnny Hersvik and CFO David Tønne. My name is Kjetil Bakken, and I am the Head of Investor Relations here at Aker BP. Before we start, I would like to refer you to the disclaimer included on slide two in the presentation deck. Assuming that you have already read that, I now leave the floor to Karl Johnny to kick off the presentation.
Thank you, Kjetil, and good morning to everyone. I guess most of us agree that we are living in pretty extraordinary times. The combination of the COVID-19 pandemic and the collapse of the oil price has created a situation which is, in my view, totally unprecedented. There is no doubt this is a highly dramatic situation, a situation which holds the potential to destroy companies, but it's also a situation where companies with robust strategies will be rewarded. I believe Aker BP is such a company, and it makes me very proud to see how the Aker BP team has handled the dual challenge of the situation.
We have been able to keep our people safe and to keep our production running without interruptions, despite all the invasive measures taken to combat the effects of the coronavirus. We have also been able to rapidly adjust our investment plans, making sure that we not only survive the crisis, but that we position Aker BP for the opportunity to build an even stronger company for the future. The building blocks for this is already in place, and these building blocks will be familiar to everyone who has been following Aker BP over time.
Our comprehensive improvement program, which aims to reshape our industry with a focus on higher efficiency and lower cost. Our flexible portfolio, where we have systematically been building a large opportunity set around our operated assets. A robust financial platform to make sure we have the space to maneuver and the ability to control our own destiny. A unique shareholder structure, which gives us access to world-class industrial competence and resources.
These elements have all played a part in our tackling of the current crisis, and I am convinced that these qualities will play an important part in defining Aker BP in the future. I will talk more about the future shortly, but let me first give a few comments to our actual performance in the first quarter. Firstly, let me share a few words on how we are dealing with the actual COVID-19 situations. Our main priorities with regards to COVID are pretty simple. The first priority is to keep our people safe. The second priority is to keep production running and ensure business continuity.
Early on, we established a COVID task force to coordinate our COVID-19 response. The task force has been converted to a dedicated project team in accordance with our well-established procedures for emergency response. We are collaborating with other oil and gas operators and industry partners to share, learn, and standardize based on best practices. Operationally, this involves a series of practical measures. The offshore manning is reduced to the minimum required to deliver the production volume in 2020.
We have implemented strict travel controls to keep the virus away from our installations, and those include charter flights where commercial flights are deemed unsafe or unavailable, and even a quarantine hotel to ensure that our people have a safe place to stay prior to going offshore. We have established procedures for isolation and quarantine and to handle potentially infected personnel, and our onshore personnel are largely working from home. This has worked well so far. Our people remain safe, and our production has continued uninterrupted.
Looking forward, we are not speculating in how long the COVID-19 restriction will have to remain in place, but have focused on building a robust system that can last for the duration. In the meantime, we have also acquired state-of-the-art testing equipment, which we will use to further reduce infection risk and avoid unnecessary quarantines. Finally, we have established contingency plans now to cover all realistic and some pretty unrealistic scenarios. In short, I think we have handled the COVID situation well, and we are well-prepared for the continuation.
Let us have a look at the underlying business of Aker BP in Q1. The title on slide number six, I think sums it up pretty nicely. In Q1 2020, we delivered fantastic operational performance. In fact, this was our best quarter ever. The only downside was the oil price was not as high as you could have wished for. Our safety record has zero incidents. This is obviously an area where there's never room for complacency, but it's still very good to note that we operated safely in Q1, as this is our primary priority.
We have set a new production record in the quarter, driven by continued ramp-up of Johan Sverdrup and the Valhall Flank West, as well as general strong performance across the rest of our portfolio, illustrated in no small terms by the record high production efficiency of more than 95%. This is a number which includes Valhall and Ula. Production costs continued to move down and ended at $8.70/bbl in the quarter, continuing the downward trend from the previous quarters.
Finally, our CO2 emissions ended below our targeted 5 kg/bbl , firmly positioning Aker BP among the very best oil companies globally with regards to CO2 emissions. I'm also very pleased to see the progress of our field development projects. In December 2017, we submitted PDOs for these three field developments. That is Valhall Flank West, Ærfugl, and Skogul. Now, less than two and a half years later, we have started production from all three on or ahead of schedule. Valhall Flank West started production from the first well in December.
The drilling and completion campaign is continuing through Q3 this year and contributing to continued growth in production through the year. The total number of wells have increased from six in the PDO to currently nine, and the reserves have also been upgraded along the way. The Ærfugl project has also been subject to significant improvements since the PDO was submitted. Reserves have grown, and while phase I of the project remains on schedule for production start towards the end of 2020, phase II have been significantly accelerated compared to the original plan for a 2023 start-up.
The first well in phase II has already been put on production, and the two remaining wells are now scheduled for start-up in 2021. The smallest of these projects, Skogul, was put in production in Q1 and is performing very well so far. In sum, our project organization, together with our alliance partners, have done a fantastic job and demonstrated a set of capabilities that you would normally only find in significantly larger companies. Now, with that performance in mind, let's turn our eyes towards the future.
Back in March, we announced several important adjustments to our investment program to account for the effects of the drop in oil price. The most significant element was that all non-sanctioned field development projects were put on hold. For 2020, this represent a CapEx reduction of 20% compared to previous guidance. We have also said that we were reducing our 2020 exploration spend by 20%. Since then, we have decided to postpone two additional wells, and the reduction has therefore been increased to 30% of the original guidance. Our estimate for production cost was reduced to $7- $8 a barrel, down approximately 20% from the original guidance for 2020.
This is driven partly by a reduction of all non-critical activities and partly by a weaker NOK, which have favorable impact on our cost level. Since then, we have also announced and launched a reorganization project. The purpose is to adjust our organization to a new and reduced activity set and ensure that Aker BP retains important competence and build a flexible and lean organization. The project involves both contractors and our own employees and will be concluded by the end of this quarter, with full implementation from October this year.
We understand, of course, that this is a hard process for everyone involved, but it is necessary, and we'll do everything in our power to ensure that everybody is treated with equality and respect. In my mind, the swiftness of these actions demonstrate determination, and it also illustrate another important quality of Aker BP, the flexibility of our portfolio. I believe that our portfolio project is one of the company's great strengths. We have systematically been building a huge opportunity set around our assets.
The fact that we are also the operator for most of these mean that we have a lot of flexibility and control when it comes to timing, planning, and execution. This is one of the reasons why we've been able to reduce our spending forecast very quickly. In light of the challenging market conditions, and as we communicated in March, we have now moved to a sanction-only scenario. As presented in our Capital Market Updates in February, our sanction-only scenario implies stable production around 200,000 bbl for the years going forward, coupled with a steep decline in CapEx.
At the same time, it's very important for us to maintain the optionality for the future growth so that we are ready in the event that the market conditions improve. Government initiative may also improve the economics of the future growth opportunities, it's very interesting to see the recent initiatives from the Norwegian government. Let me attach a few comments. On April 29th, the government announced the decision to reduce the country's total oil production from June- December 2020 in order to contribute to a fast stabilization of the global oil market.
While it's too early to say something very exact about how this decision will affect Aker BP, as the distribution per field is yet to be concluded on. However, a pro rata impact on Aker BP would imply a production reduction of somewhere between 5,000 bpd-10,000 bpd for the full year. However, let me be clear on this, due to the strong performance so far in 2020, combined with the recently announced increase in plateau rate in Johan Sverdrup, we remain comfortable with our 2020 production guidance of 205,000 BoE- 220,000 BoE today.
That is, we are retaining our original production guidance despite the announced decrease. The other initiative from the government is a proposal of temporary changes to the tax system in order to support the oil and gas industry and the supply industry. The government is planning to submit a formal proposal to the Norwegian parliament on May 12th. After that, the parliament will consider the bill. We think it's very positive that the Norwegian government is proposing measures to support the petroleum sector and not in the least, the vendor part of the petroleum sector.
However, the initial proposal has important weaknesses, which are likely to limit the impact on our future investment levels. In its current version, the proposal will only lead to marginal changes in Aker BP's investment plans as previously communicated in March. However, our liquidity position for 2020 and 2021 will be significantly improved. The Norwegian Oil and Gas Association has forwarded an alternative proposal, which will increase both liquidity, but also reduce break-even on project and increase activity in the Norwegian oil and gas industry. Before I leave the floor to David for the financial section, I would like to say a few words about dividends.
Aker BP has always been willing to pay attractive cash dividends, and we have also been very explicit in quantifying this ambition. We have paid quarterly dividends ever since the merger with BP in Norway in 2016. This ambition remains firm. However, under the prevailing unprecedented market conditions, we have concluded that it's most prudent to cancel the old dividend plan.
One important driver of shareholder value for Aker BP has been our ability to seize value-accretive growth opportunities, both organic and inorganic. One of the hallmarks of Aker BP is our strong financial capacity, which is a key enabler for an opportunistic and counter-cyclical growth strategy. The purpose of the dividend reduction is to further strengthen this capacity.
The board has therefore decided to pay $71 million in dividends in May. This represent 1/3 of the old plan for 2020. Going forward, the board will make a new assessment each quarter, but the ambition is to maintain this level for the remaining quarters of 2020. We have already paid $212.5 million in Q1, this would imply a full year dividend of $425 million, which is 50% of the original plan. We will revert with a new long-term dividend policy at a later stage when the oil market conditions allow. With that, I leave the floor to David to walk you through the financials. David, the floor is yours.
Thank you, Karl, and good morning, everyone. Aker BP's net production in the first quarter was 208,000 bpd . With a small underlift, the sold volumes ended at 207,000 bpd . Commodity prices decreased throughout the quarter, and the realized average hydrocarbon price was $41, which is 28% lower than in Q4. Total income ended at $ 872 million, which consisted of $ 779 million in petroleum revenues and $93 million in other operating income. The latter includes gains on commodity derivatives, where $ 14 million is realized gains, while $ 68 is unrealized gains on put options with maturity later in 2020.
For Q2, we have roughly 55% of oil production hedged at an average strike of $54/bbl. After the quarter, we also put in place hedges for roughly 50% of Q3 and Q4 volumes at an average strike price of $26. Revenues in Q1 were obviously impacted by the fall in oil price. Realized liquid prices were also negatively impacted by the timing of liftings. Cargoes are priced based on Platts Dated Brent in the five days after lifting, and we had few liftings in January when prices were relatively high, but relatively more liftings in February and March when prices were lower.
Comparing realized liquid prices to average Dated Brent in previous quarters. We note that Aker BP typically has realized prices slightly above Dated Brent. In Q1, this timing effect was quite noticeable. Given the current market conditions, it's worth deep-diving a bit further into realized prices, bridging this back to observed market prices. If we start with the average Dated Brent price in the quarter of $50.1, the estimated negative timing effect was roughly $6.7/bbl for Aker BP.
This was partly offset by the trading team realizing an average positive differential on Aker BP's crude qualities of $1.9/bbl . If we then subtract the negative effect of lower price of NGL, the realized liquid price ended at $44.7. For transparency, we have also here shown the effect of the realized gains on our put options in the quarter. In total, this was roughly $14 million, and after adjusting for the difference in tax rate on financial derivatives versus petroleum revenues, the positive effect per barrel sold was roughly $3.2/bbl .
When underlying market conditions have deteriorated to the extent they have in Q1, with supply-demand balances highly misaligned, oil trading strategy and execution becomes much more important. One reason is that the relative size of margins becomes larger when Brent prices are low, but more importantly, because in the current distressed market, some sellers could in fact have difficulties finding a buyer for their crude. This could have an impact on crude quality differentials, and we have observed that cargoes that typically would sell at a premium are now sold at a discount to Brent in the market.
This is also the case for some of Aker BP's crude qualities, and we could in fact see average differentials turn slightly negative in the second quarter. In the current stressed physical market, Aker BP is benefiting from a close collaboration with BP's global trading team. This collaboration is based on a marketing and offtake agreement where BP is trading Aker BP's crude, treating it as their own equity oil. Aker BP benefits from the capabilities of a global organization, trading billions of barrels on a yearly basis, and that has access to its own downstream network.
Aker BP's own trading personnel is seconded into BP's trading organization, together they have established trading strategies for each crude quality. If we now move over to the income statement. I have already covered total income quite extensively, worth noting that other income also includes unrealized gains on commodity derivatives of $ 68 million. Simply put, the unrealized gains for Q2 hedges are reflected in the P&L for Q1, while the cash flow effect will come in Q2 if market conditions persist.
Production cost of sold volumes were $ 156 million, the production cost related to the produced barrels amounted to $ 165 million, equaling a cost per produced barrel of $8.7, as Karl has already mentioned. The low production cost per barrel in Q1 was mainly driven by increased production from Johan Sverdrup, as well as generally lower activity level and the weaker Norwegian kroner. The estimated production cost for the full year 2020 has been reduced to $7- $8 per barrel, using an FX rate of NOK 10 per dollar.
Exploration expenses amounted to $ 50 million in the quarter. $29 million was related to dry well costs on the Nidhogg well, which was concluded as a non-commercial discovery. Total cash spend on exploration activities in Q1 ended at $53 million. The forecasted exploration spend for the full year is, as Karl mentioned, reduced to $ 350 million, compared to the previous guidance of $ 500 million, reflecting the reduced activity level as we have now postponed four of the original 10 wells planned.
Summarizing the items discussed so far gives us an EBITDA of $ 666 million for the quarter, down 11% from Q4. Depreciation was $ 277 million in the quarter, or $14.6/bbl . Furthermore, this quarter, we recorded an impairment of $ 654 million. These impairments are triggered by the lower oil prices, which has had a negative effect on investment plans and asset valuations. $ 360 million of the total impairment is related to the producing fields Ula, Tambar, and Ivar Aasen, and $ 294 million is related to exploration assets, including Gohta and Filicudi in the Barents Sea and parts of Trell and Trine and the King Lear discoveries.
Hence, operating loss was $ 266 million for the quarter. Net financial expenses were $ 149 million, and the main reason for the increase from Q4 is the change in fair value of derivatives, mainly related to FX forwards and interest rate swaps. Further details are included in note eight in the quarterly accounts. Loss before tax was $ 414 million in the quarter, and tax income amounted to $ 80 million and was largely caused by a reduction in deferred tax. The P&L tax rate in the quarter ended at 19%. The low effective tax rate mainly reflects the impairment of goodwill and intangible assets with no associated deferred tax, in addition to negative impact from currency movements.
The actual tax payments in the quarter amounted to $ 48 million, representing the fourth tax installment of the 2019 tax payable. The last two installments for 2019 are expected paid in Q2 and amounts to roughly $ 90 million. If commodity prices remain at current levels, Aker BP does not expect to pay cash taxes in the second half of 2020. Finally, net loss in the first quarter ended at $ 335 million. Moving quickly over to the balance sheet. Goodwill decreased by $ 65 million, and other intangible assets decreased by $ 536 million, both mainly due to the mentioned impairments. Property, plant, and equipment increased by $ 37 million.
We had additions of $361 million, where investments at Valhall and Ula made up roughly 65%. Depreciation amounted to $ 245 million, and impairment was $ 78 million. On the other side of the balance sheet, equity was reduced by $ 554 million, which is the sum of net income, dividends, and the purchase of treasury shares for the employee share program. Bonds and bank debt increased by $307 million. In sum, total equity and liabilities amounted to $ 11.7 billion at the end of the quarter. A couple of things to note if we look at the first quarter cash flows. We started the first quarter with cash of $ 107 million.
During the quarter, we drew debt of $ 337 million, cash flows from operations amounted to $ 572 million. We had the mentioned tax payments of $ 48 million. Cash flows to investments in total was $ 395 million across the various spend categories. Dividend amounted to $ 212.5 million. At the end of the quarter, our cash balance had increased with $ 216 million-$ 323 million. The book value of net interest-bearing debt, excluding lease debt, was roughly $ 3.3 billion. Our leverage ratio net debt over EBITDAX was 1.2x, the same as end of Q4 2019. In a low oil price environment like we're experiencing today, debt levels and leverage ratios are important.
Even more important is the financial capacity and liquidity position. Aker BP has, over the years, worked persistently to optimize the capital structure and create a robust balance sheet with ample liquidity and financial flexibility. In January this year, we continued that journey when we issued our first investment-grade bonds in total of $1.5 billion. In April, we utilized the first of two extension options on the liquidity facility of the RCF, extending the maturity from 2024 to 2025. We find the unanimous support from the loan syndicates to extend the commitments on existing low margins in these unprecedented times as a clear confirmation of our strong balance sheet.
As mentioned at the end of the quarter, net debt was $3.3 billion, a slight increase of $100 million from Q4 2019. At the same time, we had total liquidity and committed debt capacity of $7.3 billion. This means that Aker BP at the end of Q1 had $4 billion of available liquidity, where $3.7 billion was committed undrawn capacity on our RCF, and roughly $300 million was cash on account. At our Capital Markets Update in February, I talked extensively about our financial priorities and how we work to balance investing in profitable growth, returning parts of our value creation to shareholders, and maintaining sufficient financial capacity.
These three priorities remains the same, but the weak oil market and the high uncertainty in the global economy has prompted the need for decisive action to rebalance each of these elements. Karl has already walked you through the immediate reductions in investments and spend, which we currently estimate in total to roughly $ 600 million across the various spend categories in 2020. He also explained how the board is retracting the previously communicated dividend plan and reducing the quarterly dividend for May to 1/3 of the previously guided amount.
As we have the ambition to maintain this level for the remaining quarters of 2020, this implies a total dividend reduction of $ 425 million for the full year, or 50% of the guided amount. Lastly, I've touched upon the timely bond issue of $1.5 billion in January, increasing our financial capacity significantly. Broadly speaking, have these three actions increased our liquidity position end of 2020 by roughly $2.5 billion compared to our starting point in the beginning of the year. The purpose is to retain our financial flexibility not only to weather this current storm, but to best position the company for future value creation, including enabling us to be counter-cyclical if the right opportunities arise.
Now, before leaving the word over to Karl for some concluding remarks, I will quickly walk you through the updated guidance for 2020. As Karl has already covered, the production curtailment announced by the Norwegian state are likely to have a certain negative impact on our production. However, due to the strong performance so far this year, combined with the recently announced increase in plateau at Johan Sverdrup, we remain comfortable with the guidance range of 205,000 bpd- 220,000 b p d.
Our CapEx plan for 2020 is now $1.2 billion, down from originally $1.5 billion, and the CapEx for 2020 now mainly reflects investments in project that has already been sanctioned, including Johan Sverdrup phase II and the completion of Valhall Flank West and Ærfugl. As Karl mentioned, there is a debate ongoing in Norway about temporary adjustments of the petroleum tax system. In a best-case scenario, this could trigger additional investments already in 2020, this is way too early to quantify now.
As we have now reshaped the exploration program and reduced the plan from 10-6 wells, we are also reducing the estimated spend level accordingly. Updated guidance for 2020 is $ 350 million pre-tax, down 30% from the original plan. Most of the planned abandonment expenditure for 2020 is deemed safety-critical, we currently do not plan to change the activity level for 2020. We keep the original guidance at $ 200 million. We guided production cost per barrel roughly at $10 for 2020. This was based on an FX rate of NOK 8.5 per U.S. dollar. In Q1, we realized a production cost of $8.7.
For the rest of the year, the reduced activity level offshore due to COVID-19, acceleration of selected cost and improvement initiatives, and the weakening of the Norwegian kroner all helps drive down the expected cost level. We therefore update our guidance for the full year to $7-$8 per barrel. In sum, with these updated guiding figures, we estimate the company to be cash flow break even at a realized oil price of $30 Brent for the rest of the year, pre the expected dividend payments of $425 million. I will now hand over the word back to Karl for some closing remarks before we move on to Q&A.
Thank you, David. Very clear and concise as usual. Just a few concluding remark. I believe that the unprecedented crisis we're in will create winners and losers also in the E&P space. So far, we've been focused in Aker BP on managing the COVID-19 situation, and I think we've been quite successful so far, retaining safety for our people and undeterred production throughout this crisis. We are now positioning Aker BP for the future and will continue to stick to our strategy. First and foremost, efficient operations and excellent execution continues to be a top priority and is of paramount importance in the situation we're in.
We have, as I said, managed the COVID-19 situation without any disturbances. In addition, we've continued to increase production efficiency and set new production records in the last quarter. Excellent execution is also the very foundation for continuing our improvement efforts. Just before the crisis hit, we had started to implement a new operating model across assets. This work will continue with increased pace. The current market demonstrate just how important it is to drive down cost through continuous improvement, digitalization will continue to be one of our pillars in our improvement program.
The financial flexibility that David talked you through is another important enabler for future growth, we are continuing to assess growth opportunities, organic and inorganic. Let me be clear, our ambition is not only to survive this crisis, our ambition is to come out of this crisis as an even stronger company for the future. We aim to be the leading E&P company. With that, we will conclude the presentation and open up for questions.
As a reminder, ladies and gentlemen, to ask a question, please press star one. We will now take our first question from Michael Alsford from Citi. Please go ahead. Your line is open.
Good morning. Thanks for taking my questions. I've got a couple, please. Firstly, thanks for your presentation. Could you elaborate a little bit more on what you see as the weaknesses to the current tax reform proposals in Norway? Also, how would it increase your liquidity in 2021 based on the current plans, would be the first question. Secondly, as you mentioned a couple of times in the presentation, you've had a track record of being counter-cyclical, and obviously have significant financial flexibility.
What are the right opportunities for you going forwards? I'm thinking what type of assets, maturity profile you'd be looking for to build out from the current portfolio that you have. Just finally, with the acceleration in your improvement plan, should we see a material reduction further in production costs as we head into 2021? Thank you.
Thank you, Michael. Let's start with the discussions on temporary tax adjustments. Just to be clear on the storyline here. The Norwegian Oil and Gas, which is an association with oil companies and vendors, coupled with both the Norwegian trade unions and the Norwegian organization for employers, forwarded a proposal which contained four key elements. The first one was direct expenses of CapEx in 2020 and 2021, and ability to use direct expenses for new decisions on capital expenditure in 2020 and 2021.
Ability to use direct expenses for PDOs and likewise for topsides that were submitted before the expiry of 2022. Of course, in total, this would mean that the companies were given higher liquidity, but also that the break evens on the CapEx project would go down. The state net taxes would stay identical over time to the existing model. That was the original proposal from the industry. The whole idea here was actually to make sure that the activity stayed up and that we retained employment, capacity, and competency in the Norwegian Oil and Gas industry throughout this crisis, while it came with no extra burden to the Norwegian taxpayers.
The proposal from the government largely followed the same line. However, there are a couple of important adjustments. As the uplift is now significantly reduced, coupled with a reduction in time where the measures are only applicable until 2024, and it only applies to PDOs that are delivered inside 2021 and approved inside 2022. It means that the reductions on the break even on the CapEx programs is only marginally reduced from the existing regime. Of course, the direct expenses of capital expenditures in 2020 and 2021, even if the uplift is reduced, is, of course, giving a huge liquidity.
The exact number of liquidity will, of course, depend on the capital expenditure in those two years. Moving on. What are the real opportunities? Well, from an inorganic perspective, the market has been quite slow, I would say, and quite for obvious reasons. As the oil prices dropped and people are struggling to make head or tail of the future prices, it's very difficult to set a price for an asset transaction or a corporate transaction in the current market. We are, of course, continuing to assess the situation. As I said, we have had a history of being counter-cyclical. You should expect that we will continue that strategy.
That being said, we will retain discipline as we've also done in the past few years, and only act when we can see value accretive opportunities. By value accretive, I mean value accretive to the shareholders of Aker BP. In terms of types of assets, I think we'll stick to the strategy we talked about at the Capital Market Day. That is that the key quality for us is the quality of the asset acquired. We need to be able to understand, we need to be able to operate. I think that's been even more important throughout this crisis, that we're able to apply our business model. We are obviously not looking for tail-end assets, at least not, and certainly not from a standalone basis. Then your final question.
Improvement.
Yeah, improvement plans. Yes. In parts, I would say that the cost that you are now seeing in Q1 is impacted by three factors. It's impacted in parts by a significant reduction in activity program. I think we exited January with about 1,200 men in total working on our assets offshore. I think the current numbers as I said this morning was 772. It's a radical reduction in money. Second, it's also been increased somewhat by lots of measures to combat COVID-19. Of course, you've had an effect of the FX. This picture is not really for the full quarter, right?
This shutdown hit us mid-March. You should expect to see the impact of cost reductions even stronger in Q2 than you've seen so far in Q1. Also, you should expect to see a lowering of cost. Remember, at the Capital Market Day, we announced a target of setting a cost at $8.5, no seven, in 2023. That was done at an FX number of $8.5. Yeah, that's a long answer. The short answer is yes, you should expect to see lower cost going forward.
Great. Thanks very much.
Our next question comes from Alvin Thomas from Exane BNP Paribas. Please go ahead. Your line is open.
Hi, good morning, guys. My first question, I'd like to start with a little bit more detail on the marketing relationship you have with BP, that you talked a little bit about in one of the slides. Could I just ask whether you still own the barrel through to the refinery, or do BP directly buy the barrels from you? I guess, just a little bit more detail on the relationship as to how you ensure the best possible prices for your barrels from BP.
My second question is perhaps a little bit more broadly. The strong operational performance in the first quarter. I wanted to ask Karl whether you could shed a little bit more light into what might happen in the second and third quarters due to the restrictions with personnel and things. I think in the report you talked a little bit about Valhall potentially being impacted by restrictions on personnel and activity levels. Maybe just a little bit more detail on what you expect to see on a day-to-day basis in terms of activity across your main hubs. Thank you.
Sure. Do you want to do the marketing question?
No, I can start, then you, Karl, could add on to it. We have an agreement with BP where they are marketing our oil. We, as I mentioned, have our own trading personnel seconded into that organization. It's a joint collaboration. When it comes to if we are owning the barrels, it depends a bit on the different cargoes and the commercial agreements related to it. I will not go into detail and comment on that. When it comes to how do we work the relationship in order to make sure that we get the best prices.
I think it's very much a collaboration which is built on the foundations of our alliance models and working together as one team. BP, of course, being a large shareholder in Aker BP, has, of course, incentives also to make sure that that arrangement works well. Very supportive of the work that they are doing for Aker BP in these troubled times. I don't know, Karl, if you want to add something specific.
First of all, I think we're very grateful for the support on marketing from BP. I think this would have been a very different story in Q1, selling these barrels if that had not been the case. How much direct economic impact that had, we'll have to come back when we see the exit point of this crisis. Just let me be very clear on that. Second, if you are inferring to that we have an agreement with BP, which they buy our barrels and then resell, that's not the shape of the arrangement. The actual cargoes will either be sold as an FOB, which is at some of our asse t, or delivered to refinery or other delivery points.
That depends on the sale agreements of that specific cargo. Second, impact on our operations. What we've done so far, we have not gone to minimum manning. We have gone to a manning level where we felt that we could deliver the production guidance for 2020. That means that we are still executing necessary maintenance. We are still executing well operations. We are still stimulating wells. We're still running wireline, et c.
The whole idea here was not to go into full emergency mode, but to reduce the manning to a level where we could better control the flow of personnel and materials offshore. My assessment is that we will be able to sustain this activity level throughout 2020 if necessary. Obviously, going from 1,200- 772 has an impact on our ability to carry out work. What has been now postponed is mostly non-production and non-safety-critical maintenance. That can't be postponed forever. At some point in time, we'll need to normalize that situation. However, what we're also seeing is that throughout this crisis, our plant attainment has gone up, our ability to execute work has gone up, et c.
We are actually seeing throughout the period now from March to end of April, a quite interesting increase in productivity. One of the issues that we will focus on now going forward is how do we actually make sure that that increase in productivity is also a part of what happens when we increase the activity level, so that we don't necessarily plan to go back to the 1,200 originally, but we need to increase maintenance somewhat. This won't have any impact on production in 2020. We've set the level at such a level that we can actually sustain production without a doubt.
Just one comment from my side, Alvin, when it comes to the marketing of the oil. Just to be very clear, so of course, we are marketing the oil out in the open market, so we are benefiting from the trading capabilities of BP in that market. It's not that they are buying the oil from us.
Okay. Could I maybe just ask David just very quickly on that. How far forward have you been able to sell cargoes, specifically, with regards to 2Q, being probably the most difficult quarter?
We have sold quite a lot of the volumes for Q2. We are very comfortable with offsetting the volumes for Q2. All of May is done, we are working on June as we speak. Quite comfortable on that. I think another point which is worth mentioning, of course, with regards to the broad set of capabilities that the BP trading organization has, means that we do have various offset mechanisms. I refer to the downstream networks of BP, which definitely is also an offset that we could use if markets are distressed. As mentioned, we market the oil in the open market and then get the best prices possible.
Great. Thank you both for the answers.
Our next question comes from Teodor Sveen-Nilsen from SB1 Markets. Please go ahead. Your line is open.
Good morning, Karl and David, thanks for taking my questions. I have two questions. The first is on production and production guidance, given the fact that you most likely will reduce some of the production in some fields after the government's announcement. When should we expect you to provide an updated production guidance? Second question is a follow-up on the sold volumes you talked about in second quarter. David, how has the realized prices been on those volumes compared to the benchmark prices that we can observe?
First question, we are expecting to get revised production allowance letters within one week or so. At least that's the previously communicated timeline. We are, of course, in dialogue with the relevant authorities on this issue. If there are changes that will require changes to guidance, we'll forward that to the market immediately. Based on the current analysis, and as we said, the very strong performance both in Q1 and in continuing into Q2, we're now actually quite comfortable with the existing guidance. Prices for realized prices, David?
Yes. As I mentioned, in quite some detail during my report. For Q1, we saw premiums of roughly $2 per barrel being realized. In Q2, we do see that more cargoes have been sold at zero or negative premiums. We do expect, on average, to see slightly negative premiums for the second quarter.
Okay. Thank you.
The next question comes from Anders Holte from Kepler. Please go ahead. Your line is open.
Yeah, good morning, guys. Thanks for taking my questions. Congrats on a quarter. At least operational cash flow was very good, which is good to see. Just a couple of questions that I have. Firstly, I saw that you mentioned yourself that you're secure now with options for $26 for half of the production for the second half of this year. I mean, how should we put that in context? It's where the Brent is trading at the moment and sort of your own view of oil prices for the rest of the year.
Also, I see that you're now saying that you are moving to the sanctioned-only scenario for your production and for your CapEx spends. As you expect, CapEx kind of comes off sharply. Even if you look into 2023, for example, on your slides here, it seems that there is virtually little maintenance CapEx in those numbers. Is that something we should add on top of your regular CapEx, or how should we think about the maintenance on the sanctioned-only part of your production? Thank you.
Okay. You wanna talk about the put options and how that relates to the-
Sure.
...forward prices?
Sure, I'll definitely do that. We use put options to protect downside, and that's been part of our prudent financial policy for years. We typically put in place put options half a year, a year in advance. That's what we did also before 2020. When it comes to the put options that we put in place. Now in Q2, we definitely hope that we will not be utilizing those put options. Of course, we need to also consider the difference between the Brent First screen oil price that typically are being looked at by market participants showing today an oil price of, I guess $ 30, $ 31 closed yesterday, and what the Dated Brent plus price is out in the physical market, which for the past couple of weeks has been trading significantly lower.
Platts Dated Brent closed yesterday at roughly $23, and the put options that we have in place for the second part of the year is with a strike price of $26. I think this is part of our prudent financial policy to protect downside, and given the fact that we now with the revised plans that we put in place, expect to be free cash flow neutral at $30 oil price for the remaining parts of the year. I think we've set ourselves up for success in even a very volatile market going forward.
Remember, Anders, this is also a part of this strategy that we've followed for a long time now to retain financial flexibility, and not end up in distressed situations where we do not control our destiny. I think it's also a very important point David asked, is that the difference between the Brent First position that you normally see on your Bloomberg terminal or whatever, and the actual realized prices, which we sell oil on, which is a five-day average of dated Platts following the last or the bill of lading, as you said, or the last drop of oil going over to the tanker has been significantly different.
Platts Dated has been down to $8-$10 lower than first position. I think it actually bottomed out at $13 lower, which means that these put options should not be viewed directly linked to the Brent First position but should be viewed linked to Platts stated. You can of course, find different ways of actually assessing that Platts stated if you want to. When it comes to the sanctioned portfolio, David?
Yeah. When you look at the CapEx profiles that we show that the Capital Markets Update, that is the total CapEx that we expect. We don't separate between sort of maintenance CapEx and other CapEx in those charts. Normal operational maintenance is included in part of the production costs. This is the total amount of expected CapEx in a sanctioned only scenario.
Yeah. The production corresponds to the investments.
Yeah. Of course, as Kjetil is reminding me here, of course, the production corresponds, of course, to that investment level also.
Okay. Yeah.
Our next question comes from Karl Fredrik Schjøtt-Pedersen from ABG Sundal Collier. Please go ahead, your line is open.
Hi, guys. Thank you for your presentation and all your remarks. The question or going back to the proposal for tax exemptions or temporary tax relief. Starting off with a question on what type of projects or what concrete types of projects would you sanction given the Norwegian Oil and Gas Association's proposal, and what will then fall out in this proposal from the Norwegian government? That's the first question. The second question is what do you estimate as your liquidity boost in 2020, 2021 from the Norwegian government's proposal? If so, that you would rather forgo that liquidity boost to better the economics on new investments.
Okay. Thank you, Karl Fredrik. When it comes to your first question, when we have looked at our portfolio, most of the projects that are in our current portfolio, inclusive Hod, East Kameleon, Gekko, and not insignificantly NOAKA, will be executed under the Norway proposal. That's the whole idea, right? Is to create a proposal which had no negative effects to Norwegian society while improving activity in the vendor industry.
If you move over to the current proposal, the time limits combined with the other elements means that this will probably be linked to projects that have either a very short duration, which is normally infill wells or short tieback wells or have already been very close to PDO. My guess when I said that we're not making any changes as of this moment, is that it will have limited impact on our activity. There might be a few more infill wells and then what might be a few tiebacks that we would reconsider. The changes in breakeven are so small
That even this project will have to fulfill a requirement which is significantly stricter than the usual 35 that we've used as a benchmark for a long time now. When it comes to a liquidity boost, I think we'll come back to that in numbers when we see the actual proposal. You could, of course, make a calculation based on the CapEx and the proposal from the government that you can find on the government website.
Is it so that you would rather forgo the liquidity boost than have a higher preference for incentives towards new investments? Is that the understanding?
The whole point is that this is a combination, right? The key issue here is to make sure that we retain value creation in the entire portfolio. The thing that we have managed to achieve with the NOROG proposal is the combination of a liquidity boost that allows the companies to invest and a reduction in break even that makes it attractive to invest while not hampering the Norwegian taxpayers with an additional bill for that boost. It's very difficult to judge these elements up against each other. This is a total package.
One comment from my side also, I hope it's clear from the presentation today that currently we don't have an issue with liquidity.
Yeah, absolutely fair. Thank you.
Our next question comes from Yoann Charenton from Société Générale. Please go ahead. Your line is open.
Good morning, gentlemen. Thank you for the presentation. I will have three questions, if I may. If you were to sustain the current activity level during this year, but still allowing for maintenance, could you please provide some more color on the impact on next year production? Are we really looking at a flat-ish output trend as we move to 2021? Maybe I should add the two other questions.
Yes.
For 2020 investment and production guidance, are you able to say what is, broadly speaking, the scheduling of spending and production throughout the year? Last question on NOAKA. Have you had any time at all to achieve progress on the NOAKA negotiation with Equinor in the [TMB]? Thanks.
Thank you, Yoann. Well, the simplest question first. When it comes to next year production, as I said a couple of times now, we actually do believe that the current activity level will be sustainable at least throughout 2020. We might have to increase it slightly in 2021 to pick up some more of the backlog that we're now building on maintenance.
As I said, the backlog is lower than we expected because productivity and plan ahead has gone up. I'm not, at least not today, anticipating major changes in our plans for 2021 either. I think the guidance we provided in the sanction only scenario in the Capital Market Day is a good proxy also for the 2021 year. When it comes to scheduling of investment, David?
No, I don't think we can add too much color on sort of the phasing of investment spend over the next couple of quarters. I think for sake of good order, you could probably think of it as really flat when it comes to CapEx. Similarly, I think we already gave some guidance with regards to production development throughout the year in our Capital Markets Update, and that remains fairly the same, although that some of the turnarounds that were scheduled during summer is not going to be executed due to the COVID-19 situation.
Finally, NOAKA. I think most of our minds in the entire industry have been on managing COVID-19 and also we've had an excellent collaboration with all participants in this industry while preparing for the proposal from the industry on short-term tax changes. The NOAKA discussion is where we left it in March. However, I'm looking forward to picking up that ball again as soon as possible.
Thank you. That's good to hear.
Next question comes from Chris Wheaton from Stifel. Please go ahead. Your line is open.
Gentlemen, good morning. Thank you very much for your presentation. Two questions, if I may. Firstly, Karl Johnny, to you, has the corona crisis changed what you think the right level of debt that the company should have in the future in terms of net debt/EBITDA or a function of the asset base? I'm interested if it's changed that, because to me, that seems the balancing item in those two.
How much you can pay as dividend versus how much your investment plan is going to cost you. Secondly, if I may, a question for David on the impairments. I was surprised to see Ivar Aasen in the list of impairments. Could you perhaps explain a little bit more why a field so new as Ivar Aasen and is clearly a technologically very advanced field, had to have impairments at the current oil price? Thank you.
Thank you, Chris. Of course, we are discussing the whole capital allocation framework in the midst of this. That is the balance between what we do with dividends, what we do with organic investments, et c. I'm not going to conclude on that discussion, but this is obviously a topic that is front and center of the discussion currently. Of course, the current level is based on our historic assessment, both of the market and the activity program. At least we felt that that was correct in the previous scenarios. Whether that's correct also in the future, we'll come back to that.
Just one comment from my side as well, Chris, is that we're definitely now seeing the benefit of the prudent financial policy that we have had in place with not taking on too much leverage and of course, having a lot of liquidity in the balance sheet. We're very happy about that. Of course, the bond issuance in January was maybe a bit by luck, perfectly timed just ahead of the crisis, and that puts us in a fantastic situation now, not having to run to the market and get additional liquidity when credit spreads have drastically widened. I think that's an important element.
When it comes to your question around Ivar Aasen, I understand the rationale for your question, of course, we need to consider also at what time Ivar Aasen was bid. That was a field which we bid in a very different oil price environment. Yes, at the time of PDO, the break-even for that project was $60. The reason for why Ivar Aasen is now slightly impaired is just due to the fact that when the oil prices dropped, and then you do the impairment testing with the three-year forward curve, a lot of the value is in the production in the coming years. It's simple math, basically.
Great. Super. Thank you very much indeed. I hope you and family stay safe, stay well. Thank you.
Next question comes from James Carmichael from Berenberg. Please go ahead. Your line is open.
Hi. Good morning, guys. Thanks for taking the questions. Just a couple of quick ones. Appreciate these details are still being worked through, but I was just wondering, given the MPE seems to have indicated that it wants to maintain Norway's overall asset export levels, does that suggest that fields like Skarv will be insulated from the production cuts when they're sort of fully worked out? Just secondly, on the dividend point, I think in the AGM, you approved the possible issuance of shares in lieu of cash dividends at the request of investors. Just wondering if you can talk us through the thinking there and whether you anticipate using that this year. That'd be great. Thanks.
Skarv, if we take that. Skarv is actually consisting of two petroleum regions, one gas region and one oil region. The production containment, the way we see it, is directly linked to oil and oil assets. For Skarv, this will mean a reduction in oil, but it won't necessarily mean a reduction in the gas production. A little bit based on how the associated gas and the pure gas production is evening out and optimization across the asset.
This will have less, but it won't mean that Skarv is excluded from the current containment. In the AGM, as you put, we included the option of a possible share scheme when it comes to dividend. The currently communicated strategy is to stay with cash dividends to a total amount in 2020 of $425 million. I think that's the communicated plan when it comes to dividend this year.
Okay. Thanks a lot.
Next question is from James Thompson from JP Morgan. Please go ahead. Your line is open.
Good morning, gentlemen. Thank you very much for taking my questions. I had a couple, if that's all right, Karl. Firstly, I just wondered if you could update us on your alliance structures that you have in place with your field service companies. How are these, I mean, it's early days, obviously, in this low oil price environment, but could you maybe give us a bit more of an update on how these are performing, these structures, and whether you need any changes at all there?
My second question just involves the Nidhogg that you have pushed the appraisal of that well out. Just interested, I guess, my view, Aker BP seems to be one of the primary targets for the Norwegian government in terms of continuing to keep development activity high on the Norwegian Continental Shelf. Surprised that you are not going to appraise that, given the complexity of the discovery. I thought that would form a core part of the NOAKA field development, at least in the first phase.
Finally, obviously, you've done a good job on OpEx. Group OpEx is coming down nicely. Just wondered if there was any fields or any of your satellites that may be at risk of an early shut-in or cease production, just through this very low oil price environment. I guess I'm thinking the fields around the Ula area, things like that. Just any color there on fields which might be at risk if $30 oil persists in the short to medium term. Thanks.
Okay, thanks. All good questions. Let me start with the alliances. I think if we were grateful for the alliances before the COVID-19, I think we're extremely grateful for the alliances now. This is both allowing us flexibility, it's allowing us a framework to work within where we share trust and we share information. It's also allowed us to move extremely quickly to change our activity sets and activity levels. I think this alliance structure had even more robustness to it than we originally thought when we initiated the project. That, of course, doesn't mean that it's not without issues.
Particularly the well head alliance, facility alliances, of course, struggling when projects such as Hod, which were planned to be delivered on PDO, is now suspended. This is not only hitting the alliance, this is hitting the entire vendor industry. I think as a setup and as a strategy, I think the alliances have performed even better than we expected. I think the other key comment to make here is that given that you have an incentive element in these alliances, where all parties are incentivized to reduce cost and increase performance.
One of the things that pretty much happened after the COVID-19 situation broke out was that a lot of cost reduction initiatives popped up pretty spontaneously in these different alliances. These were initiatives which otherwise we would have to coordinate and drive and change, et c. Now it happened spontaneously at the front end of the business. This also happens to plan attainment, productivity increases, et c. Both the way of organizing work, but also the commercial model is driving the right behavior when you have these kind of crisis and these kind of radical changes to the environment.
Now, Liatårnet, which was your second comment. First of all, there is plenty of oil in the NOAKA area. There is no lack of oil. The original field development will stand very nicely on its own, even without the Liatårnet volumes. That's one of the commercial reasons for pushing out this. From a technical perspective, this is a rather complicated test. It's a shallow reservoir on consolidated sands, which means that the original delineation was set in place to do a PVT sample, and to address the top surface. Now, with recent processing of seismic, I think we have pretty good control over how that reservoir is distributed and the contours.
As I said, with the sufficient amount of oil in the NOAKA area, there is no reason to push forward this delineation. Of course, it also gives us more time to both do a production test and a PVT sample in the same well, and thereby potentially saving one appraisal well. Now, OpEx, and of course, if this continues for a long, long time, we need to reconsider lots of things. In the short to medium term, this hasn't really impacted the way we think about our assets, and the way we think about early shut-in. We're continuing the program as we set out in the Capital Market Day in the sanction only scenario. I think that's a good reflection of the strategy that we have today. If you want to add anything, David?
Just on production cost. If we look across the portfolio now, all our assets has a production cost of roughly $10/bbl or lower. Of course, Johan Sverdrup being the lowest with roughly $2/bbl , apart from the mentioned Ula that you mentioned. I think it's also important to think about, or when you think about Ula, is that a large part of the OpEx and production cost at Ula is linked to well maintenance work.
Actually in 2020, almost as much as 50% is linked to that. That's, of course, well maintenance work that we do to sustain production, but given that it's not adding new reservoir, it's not booked as CapEx. That's an important element and a driver for high production cost at Ula compared to some of the other assets. Of course, in a scenario that you're talking about, you would probably defer some of that well maintenance work before shutting down production and the asset in full.
Okay. You're not deferring any of the well maintenance work now? It's all still planned in OpEx this year, even with the reduced headcount?
No. We're not addressing any of that. What we're basically taking out when it comes to Ula is mostly activity that were related to Ula redevelopment project and a long-term duration of Ula. That means that if market prices come back and there's another investment, how to say, environment, we have plenty of time to come back and redo these projects.
Okay, perfect. Appreciate your answers on all the questions. Thank you.
Next question comes from Al Stanton from RBC. Please go ahead, your line is open.
Yes. Good morning, folks. I appreciate it's late, and thank you for sticking with us. Karl Johnny, I was just looking for some clarification on your closing remark about Aker BP being a leading E&P company. I was wondering if you could just address two issues. One is your definition of leading. How important is growth to you? When we look at the majors, they're all rowing back from growth targets. I was interested in how you define leading. Also, I was wondering if you left out the geography. I was perhaps anticipating comments of leading E&P company in Norway or the North Sea. I was just wondering if we should read anything into the lack of defined geography in your statement.
Thank you, Al. Well, it's always a pleasure to take questions, so don't worry about that. I didn't say that we were the leading, I said we aim to be the leading. Which is not necessarily a change from our current vision. The point I'm trying to make is that as these kind of crises evolve, they create winners and losers. I've said this once before, back in 2014, for those who followed the story back then, that I thought Det norske, at that point in time, was ideally positioned to take benefit of the low price environment back in 2014 and 2015. I got a little bit of flak for that statement, I think history has demonstrated that we were, in fact, ideally positioned to take benefit of that crisis.
Now, with the management that we've seen in this team, I'm extremely proud of my team through this COVID-19 situation, I think we're already starting to discuss how are we going to take benefit of this crisis. The good saying that never waste a good crisis. I don't think you should read too much into this. This is not a semantic game. For us, it's more a directional statement, that we are not worried about our survival. We are worried about coming out of this crisis as a stronger, more robust, and even more productive company.
Focused on Norway exclusively?
I think what we said also in the Capital Markets Update is that when we look back on the inorganic moves we've done, the big driver is the quality of the assets. That, I think, is a pretty clear statement. I've been trying to do business development internationally for a long time, and I know how difficult it is. I also want to be clear that we are going to be extremely disciplined also in this crisis, and only act when we see opportunities that we firmly believe can create shareholder value and are able to articulate that in a very pronounced matter. Where we fundamentally understand how we as a company can create a sustained competitive advantage over the other players in the area.
Okay. Thank you.
Our next question is from Teodor Sveen-Nilsen from SB1 Markets. Please go ahead, your line is open.
Thank you for taking my questions again. Just one follow-up on tax. Now that you said that you don't expect to pay any cash tax in the second half of 2020, which should be expected. Is it now that you actually will get repaid some of the tax loss in December 2021, and at which oil price to see a pay out in 2021?
Yeah, you broke up a bit, Teodor. Yes, of course, there is a chance that you do get exploration refund in 2021. That's definitely clear.
Okay. Thank you.
Our last question comes from Halvor Strand Nygård from SEB. Please go ahead, your line is open.
Thank you. Hi, guys. Understanding now the move to the sanctioned only scenario, what that includes in terms of CapEx and production. I'm just wondering in returning to the CM D presentation. You state that you have around 200 MMbbl or some 20% of your contingent resources that have a breakeven below $20. By not sanctioning those projects now, is that a reflection of being prudent in terms of CapEx and balance sheet, given the high volatility or other considerations? Follow up on that with the sanction-only scenario, it looks like you will roughly save some $4 billion in CapEx next three, four years.
Considering organic versus inorganic activity, how would a potential M&A deal look like and stack up against the attractiveness of your current portfolio of opportunities that you now have postponed? Lastly, on dividend. With the current market conditions, the board states that the dividend would be $70 million per quarter for the remaining of the year. I'm just wondering, and I know it's the board and not you deciding the dividend. Given current market conditions, your cash flow over the next years would improve as CapEx then falls off a cliff. In your opinion, would that open for higher dividend payments over the next years, or would the current run rate serve as a proxy?
Yeah. Let me start with the project that are in the hopper with very low breakevens. The reason we have now moved to a sanction-only scenario is that, and I'll come back to my statement about moving swiftly and with determination. It wasn't like we were completely unprepared for this event, right? We had established in Aker BP scenarios for a lot of these events, including a low oil price scenario. The easiest thing to do when the crisis hit was to pick out that scenario and just run down the action list. That got us moving extremely quickly on a lot of different workflows simultaneously and has brought us to where we are today.
With a controlled COVID-19 situation, a revised scenario on investments, and in control of our statements. Of course, there is a certain element of prudence in this. When we acted on this, we did not know where this oil price would end up. There were reports out there of $ 5-$ 10 in May. There were reports about tank top in June, et c. To us, it was prudent to move all the way down to the sanction-only scenario and then slowly open back up when we got more clarity on that. It doesn't mean that this project won't be sanctioned, given an economic environment that allows sanctioning. It means that we acted according to a scenario.
Again, we chose to be conservative and chose to retain financial flexibility over what could probably be seen as a little bit of an Excel exercise, maximizing value. Then stacking up against M&A and inorganic, M&A versus organic. This is always the discussion when you have 900 MMbbl in your hopper. Where do you actually create the most value? Is that through an inorganic move or is it through an organic move in your existing portfolio? I think what we've demonstrated over the last few years is an ability to not fall in love with these organic opportunities, but still be able to go out and execute inorganically when we can see that that is actually the most value-accretive move.
We are continuing to kind of benchmark the inorganic and the organic opportunities with one single mindset, and that's to maximize value creation to our shareholder. To us, we're pretty agnostic to where these barrels are coming from. If they're coming from the market, if they're coming from an asset transaction or a corporate transaction, or they're coming through some sort of PDO field development decision. The last one was this discussion on dividend. I think as we've stated previously or rather as the board have stated in their report, they will come back with more clarity on this going forward. I think it's important to also note that we are remaining firm on our ambition to distribute attractive cash dividends to our shareholders.
We are here to make sure that the shareholders have an interest in staying in Aker BP as a shareholder. That's a very clear direction also from the board. I think we've now almost run out of time. I want to say thank you for all those who have followed us. Thank you for excellent questions. If there are more questions, which I'm sure there are, I'm sure that Kjetil will be happy to spend the remaining part of his day answering all those questions in detail. Thank you all for joining us at this first quarter call in 2020. Guys, I hope you stay safe and your families stay safe and healthy. Thank you.