Aker BP ASA (AKRBP) Earnings Call Transcript & Summary

Good day, and welcome to the Aker BP Half Yearly Report 2022 Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Kjetil Bakken. Please go ahead, sir.

Thank you. Good morning and welcome to this Aker BP webcast, which is our first public event after the completion of the acquisition of Lundin Energy's oil and gas business. My name is Kjetil Bakken, Head of Investor Relations in Aker BP. Today's presentation has 2 main parts. We will start with the review of the second quarter performance and results, and this will be covered in tandem by our CEO, Karl Hersvik and our CFO, David Toenne. After that, Karl will give an update on the strategy for Aker BP. In total, we expect this to take a little more than 1 hour, and we will then have a Q&A session. Now let's start. Karl, you take it from here.

Thank you, Kjetil, and good morning to all of you listening in to this session, which as Kjetil has already said, will contain both the normal Q2 results and a strategy update after the acquisition of Lundin. We will start with a brief run-through of our second quarter results. Of course, the most noteworthy event this quarter is the completion of the Lundin transaction on 30th of June. This transaction set us up with more robustness through the cycle, a larger base of low-cost, low-carbon asset and a fantastic cash flow potential, and an even stronger team to take Aker BP one big step further. That said, the real work starts now and we are well on our way to integrate the 2 organizations into one team. More on that shortly. Turning to the operation. Production was impacted by the planned summer maintenance program, which has progressed according to plan. The major part of this program has now been completed and is setting us up for increased production in the second half of the year. Regarding the development project hopper, we are firmly on track to submit PDOs for the remaining project by the end of the year, including the addition from the Lundin portfolio. This means that we will sanction projects with -- in total of roughly 900 million barrels of contingent resources on the temporary tax rules. We've also had a high exploration activity in the quarter and last week we announced the Storjo East discovery in the Skarv area, which was significantly larger than the pre-drill estimate and represent a welcome addition to the resource base for Skarv. Now on the financial side, high realized prices contributed to strong cash flow generation. In fact, the high cash flow over the last couple of quarters gave us the opportunity to fund the cash consideration of the Lundin acquisition without adding new debt. I believe this is a testimony to the strong financial position of the company, and a fact also noted by the 3 main credit rating agency, who all upgraded their rating of Aker BP during the last quarter. And last but not least, in line with increased value creation, we today announced an increase in the quarterly dividend to $0.525 per share. This is up 11% from last quarter and bringing the targeted full year dividend up to $2 per share. Overall, this has been another strong quarter for Aker BP. And let me now first dive into a bit more details on the Lundin integration. Everyone that has been involved in the transaction know that for the organization at large, the work really start after the deal is announced and that the really hard work start after the transaction is closed. In Aker BP, we have done several large integrations before, first after the Marathon Norway transaction back in 2014, and then in 2016, after the merger with BP Norway. We use these learnings from both these transactions when we are now running the integration with Lundin. The transaction closed only 20 days ago, but we hit the ground running. We are currently in the process of onboarding the former Lundin employees into the company. We have established a new organization structure and appointed leaders. And we are on our way to build the best team in the industry. We expect the entire organization to function as one team from October 1. At the announcement, we indicated a yearly synergy potential of roughly $200 million. This estimate has now been verified and the current estimate is now closer to $250 million. In addition, we have identified another $150 million in one-off synergies and that is net of integration cost. However, the main rationale for acquiring Lundin is not the direct cost synergies. We believe by combining the 2 leading European E&P companies, we are truly generating the E&P company for the future, with low cost, low carbon barrel and unparalleled portfolio of growth opportunities, and a clear decarbonization plan. Our ambition is very simple, superior value creation and shareholder returns. I will, of course, talk more about this in the strategy's update session shortly, but let me first continue my review of the operational highlights for the second quarter. Turning to production, Q2 production ended at just above 181,000 barrels per day, which was down quarter-on-quarter, driven by the aforementioned planned summer maintenance program. This explains why the production efficiency was also lower in the quarter. And including on the left, we sold roughly 173,000 barrels per day. Please do note that these numbers do not reflect the Lundin production, which will be included in our income statement from next quarter. Our gas production was stable quarter-on-quarter at 35,000 barrels of oil equivalent, helped by production from Aerfugl and the first full quarter of production from a gas blowdown at Skarv. The one key unplanned event impacting production in the second quarter was the power outage at Edvard Grieg, starting in late March and also affecting production at Ivar Aasen. Production was first back at 15% in April before being fully restored in May. Both Ivar Aasen and Edvard Grieg worked well to minimize the impact of the shutdown by using the opportunity to perform maintenance that was originally scheduled for a shutdown later in the quarter. Now moving on to HSSE performance. And as I've stated before, safety is always our first priority and I'm happy to see that we are continuing the positive safety trend. This year, we have had 0 process safety events and only 1 minor injury recorded. That is of course one too many, but it's still a good representation of our strong safety culture. However, the only good HSSE day was yesterday and we are working relentlessly to continue the improvement. Turning to CO2, our CO2 intensity was slightly down quarter-on-quarter to [ 4 point ] kilograms per barrel, below our target of 5 kilograms per barrel and slightly less than 1/3 of the global industry average. We continue our efforts to drive emissions down, both through energy efficiency improvements, electrification of fields, and close cooperation with our suppliers to address emissions upstream in the value chain. The next big event is the electrification of Edvard Grieg and Ivar Aasen, which will take place in the fourth quarter this year. And while we will never stop focusing on gross emissions, I'm extremely happy to also launch a decarbonization plan with a clear pathway to net zero. We'll come back to this in the strategy update. Now before moving on to the progress of our project, let me first briefly comment on Lundin's first half performance. Because the transaction closed on 30th of June, we do not consolidate production revenues and costs before 1st of July. So the numbers I've presented so far have been Aker BP only. The acquired business from Lundin is consolidated into the balance sheet, which I'll leave for David to comment on later on. That said, I still feel it's appropriate to say a few words about Lundin's operational performance for the first half of the year. And the highlights include 181,000 barrels of oil equivalent of production per day, almost identical to Aker BP's production, 86% production efficiency, an OpEx of $4.5 per barrel and only 2.9 kilos of CO2 per barrel produced. And while both the production efficiency and operational costs were slightly impacted by the previously mentioned power outage on Edvard Grieg, the overall production was in line with plan. Now these metrics speak volumes to the world-class assets and a strong organization we are onboarding through the transaction and we have already started working as one team to drive performance across all our assets even higher. I must say that I'm impressed by the way the Lundin team has managed the power outage. And to me, there is no doubt that together with the existing Aker BP organization, we now have the best team in the industry. Let's now turn our attention to the development projects. And so far in 2022, we have continued to make good project -- progress on projects under development and in the execution phase. Starting with projects under development, we remain firmly on track to deliver PDOs for all planned projects by the end of the year. And this quarter, we selected concepts for all the remaining projects, including the Lundin project at Lille Prinsen, Rolvsnes Full Field and Solveig Phase II. As for Johan Sverdrup Phase II, it has progressed safely according to plan and on cost and remains on track for startup in the fourth quarter. Now in addition to maturing the current project hopper, we are also exploring for what should become after. And this year we have had a very active exploration program. And last week, we announced a sizable discovery at Storjo in the Skarv area. Preliminary estimates show between 25 million and 80 million barrels of oil equivalent, which is substantially higher than the pre-drill estimates of 16 million to 45 million barrels of oil equivalents. Aker BP also had a relatively high working interest in discovery or 70% after Equinor pulled out. The well encountered gas in several geological formations, and we will have to do further appraisal of the discovery next year. The Storjo discovery opens up for even more discoveries in the area, and this to me a very exciting prospect. Now this type of discovery fits perfectly into Skarv area strategy of finding and adding tie-back candidates, to build yet another wave of developments post the Skarv satellite project, which is currently ongoing in the development phase. And the Skarv Satellite Project is, of course, scheduled for final investment decision this year. And thus we are well on our way to replicate the Alvheim area strategy also in the Skarv area, a topic we've discussed in these presentations earlier. Now we are not done exploring in the Skarv area for the year. 3 additional prospects are lined up to be drilled in the third quarter. And in addition to the 3 wells in Skarv area in Q3, we plan to drill another 8 wells for the combined company in the second half of the year. Currently, we are drilling Newt and Poseidon, the latter is operated by Equinor and has a sizable pre-drill estimate. And the first one is the second well in the Skarv area. With that, I'd like to turn the floor over to David for the financial review of the quarter.

Thank you, Karl, and good morning, everyone. The second quarter has been another eventful quarter for Aker BP. And the main event, as Karl has mentioned, has of course been the closing of the Lundin acquisition. The acquired business is now consolidated in Aker BP's balance sheet on a fair value basis per 30th of June and reported today, while the income statements will be consolidated from July 1st and reported for the first time at our third quarter presentation. This means that unless otherwise stated, it is only the balance sheet and forward-looking statements that includes the acquired business in this part of my presentation. Moving onto the financial highlights of the quarter, as Karl has already covered, production was down due to planned maintenance shutdowns on several fields, however, the strong price environment and price realization led to a continued strong cash flow generation in the quarter. Free cash flow in the second quarter was $803 million, and at the end of the quarter, we paid a net cash consideration of $1.2 billion for the Lundin acquisition from cash on account. We ended the quarter with a net debt of $3.7 billion on a consolidated basis, and during the quarter we also paid a dividend of $0.475 per share. And today, we announced an 11% increase in the quarterly dividend up to $0.525 per share, bringing the expected total dividend paid for the full year 2022 up to $2 per share. If we then move on to revenues and the key drivers behind, total income was right above $2 billion in the quarter. We had a net production of 181,000 barrels of oil equivalents per day and an underlift of 8,000 barrels, which means that sold volumes ended at [ 173,000 ]. The realized crude price was roughly $119 per barrel. The price was positively impacted by strong differentials across our crude qualities, on average approximately $3.1 per barrel. The average realized price for natural gas was $152.6 per barrel of oil equivalent, down from $171 last quarter. Combined, this gave us a realized average hydrocarbon price of $126.8 per barrel of oil equivalent, up 10% quarter-on-quarter. Now shifting focus over to capital spend, total capital spend was flat quarter-on-quarter, but with variations between the categories. Overall CapEx is down and spending year-to-date is slightly below budget, mainly driven by in-year phasing. We expect CapEx spending to catch up in the second half of the year. Exploration spend is up from the first quarter with the drilling of several wells, including the Storjo discovery. Abandonment expenditure is in line with plan. The main activity in the quarter was the removal of the Valhall DP platform, which was executed on plan and budget. Moving on to production costs, absolute production cost was down 9% quarter-on-quarter with lower tariffs, transport and environmental taxes, driven by the lower production. Base production cost, which is dominated by operations and maintenance, were fairly flat quarter-on-quarter, with high activity during the planned maintenance shutdowns. As production was lower in the quarter, the production cost per barrel is relatively high. However, we expect cost per barrel to trend down as production ramps up in the third quarter. With this as a backdrop, let's take a quick look at the P&L. When we subtract production cost of $190 and other operating expenses of $20 million from total income, we get an EBITDAX of $1.8 billion, a margin of almost 90%. Exploration expenses amounted to $67 million, of which $34 million was dry well costs and $19 million was seismic. Depreciation was $199 million or $12.1 per barrel. In the quarter, we also recognized a non-cash impairment charge of $422 million. $411 million was related to an impairment of Ula, driven by a negative revision of the production profiles and associated acceleration of expected shutdown of the field from 2032 to 2028. Net financial cost was $62 million and profit before tax then ended at $1.066 billion. Tax expenses amounted to $878 million, and the relative high tax expense for the second quarter is driven by currency movements. The dollar strengthened significantly against the Norwegian kroner in the quarter, reducing future tax depreciations, measured in dollars and thereby, increasing deferred taxes. Consequently, net profit ended at $187.5 million or $0.52 per share. Now although net profit in the quarter was impacted by both the non-cash impairment and the currency movements, free cash flow in the quarter was still strong. Operating cash flow after working capital and taxes ended up almost $1.2 billion in the quarter. Taxes paid in the quarter was $748 million, below guidance of roughly $800 million. This was driven by the weakening of the Norwegian kroner against the dollar. Investment activities excluding payments on lease debt amounted to $383 million and free cash flow then ended at $803 million or $2.2 per share. At the end of the second quarter, we paid a net consideration for the Lundin acquisition of $1.243 billion. This was the agreed cash consideration of $2.22 billion adjusted for the acquired cash and some minor currency adjustments. Dividends paid in the quarter was $171 million. Interest paid, payments on lease debt and other finance items was $39 million. We then ended the quarter with a cash balance of almost $2.2 billion, a decrease from $2.8 billion at the end of the first quarter. As of June 30, we have consolidated the acquired business from Lundin into the balance sheet on a fair value basis. And consequently, there are material changes to note. On this slide, we have included 3 columns for comparison. Aker BP per end Q1, Aker BP per end Q2 before consolidation of Lundin, and lastly, Aker BP per end Q2 after the consolidation. And before the consolidation, the main changes from the first to the second quarter were that property, plant and equipment increased by $222 million, where $814 million was additions and we had $181 million in depreciation and $411 million in impairments. On the right-hand side of the balance sheet, the main changes worth noting before consolidation are driven by the approval of the new cash-based tax system in Norway in June. Due to accelerated tax depreciations in the new system, on a like-for-like basis, tax payables decrease and deferred taxes increase. As the change is effective from January 1, 2022, there is also an adjustment for the first quarter, including in the -- included in the variance between the first and the second. For more information on the effect of the change in the balance sheet, see Note 10 in the financial statements. The biggest changes to the balance sheet have, of course, incurred because of the consolidation of the acquired business from Lundin at fair value. Note 2 to the financial statements includes detailed information about how the purchase price for Lundin has been allocated to the various items in the statement of financial position. Total non-current assets increased to $33.4 billion. Of this, PP&E increased to $16 billion with Lundin's share in the Johan Sverdrup and Edvard Grieg fields as the main contributors. Goodwill increased to $14.2 billion, of which $6.3 billion of the increase is related to technical goodwill, meaning that it rises from the requirement to recognize deferred tax liabilities for the difference between the assigned fair values and the remaining tax balances. This part of goodwill will be allocated to the cash-generating unit level for the purpose of impairment testing going forward and in line with the approach from previous business combinations in the company. On the other side of the balance sheet, total equity increased to $12.1 billion, as the main part of the consideration in the Lundin transaction consisted of Aker BP -- of new Aker BP shares. Bank and bond debt increased to $5.8 billion, mainly related to 2 new bonds from Lundin, recognized at fair value, amounting to $1.7 billion in total. Other long-term liabilities increased to $13.5 billion with deferred tax liabilities and abandonment provisions from the Lundin transaction as the main contributors. Tax payable increased to $4.3 billion with $2.2 billion coming from Lundin. Immediately after the transaction closed, several actions were taken to optimize the capital structure of the combined entity. Lundin had a $1.5 billion revolving credit facility, which was canceled, as Aker BP's existing undrawn credit facility of $3.4 billion give sufficient liquidity for the combined entity and has better terms. Furthermore, Lundin had a $600 million term loan, which was repaid and canceled on July 1. This slide is therefore developed to give a fair representation of Aker BP's current capital structure, post the transaction. Here we have adjusted the cash and liquidity position and debt facilities to include the actions taken on July 1st, and therefore, it deviates from the representation in the quarterly report. As can be seen from the slide, even after paying the cash consideration at closing with cash, Aker BP's balance sheet and financial flexibility remains very strong with $3.4 billion in available credit facilities and $1.5 billion in cash. Net interest-bearing debt is $3.7 billion and the leverage ratio remains well below our internal target of 1.5x, and we have no debt maturities before 2025. Now we always believed that the transaction would be credit accretive, and during the second quarter this has been confirmed by all 3 rating agencies with credit upgrades to BBB-flat by S&P and Fitch and Baa2 by Moody's. If we then move on to tax, as mentioned in June, the Norwegian Parliament approved the proposed new cash based tax system. The tax system replaced the old permanent system with effect from January 1st. Most of the characteristics of the tax system is not changed, including the marginal tax rate of 78%. However, the key changes for Aker BP, who has exploration, development and production can be summarized in 3 points. One, immediate tax depreciation of investments within special petroleum tax. And 2, refund of potential tax losses within special petroleum tax. And 3, this is done combined with the removal of the so-called uplift, which has been an extra tax deduction for investments to account for the delayed depreciation in the old system. The new system will work in parallel with the temporary system put in place during the pandemic. This means that projects with PDOs delivered before end of year and approved in 2023, will be covered by the temporary system with immediate deductions, plus an uplift of 17.7% for special petroleum tax. In Aker BP, we believe that the new system, in combination with the temporary regime, provides important predictability on fiscal terms and a good foundation for investing in profitable growth that creates value for all stakeholders. Going forward, with increased size and profitability, Aker BP will be an even more important contributor to the Norwegian society with the taxes we pay. And as normal, in June, we fixed the first 3 tax instalments for the fiscal year 2022 to be paid in the third and the fourth quarter this year. The installments shown here on the slide are for the combined Aker BP and includes the tax payments for Lundin Energy's oil and gas business accrued in the first half of 2022. The sensitivity for the payments in the first half of 2023 are based on an average oil price for the second half of 2022 and a fixed gas price of $25 per MMBtu for all the scenarios. If we then move on from tax guidance to operational guidance, we on this slide show the expected performance for the combined entity for the second half of 2022. On production, the combined entity have produced roughly 376,000 barrels of oil equivalents per day in the first half of the year. We expect the production in the second half of the year to ramp up to between 410,000 and 435,000 barrels per day as we have summer maintenance behind us and Johan Sverdrup Phase II starts up. The main driver for where in the range we will end up is of course the timing and pace of ramp-up on Johan Sverdrup Phase II in the fourth quarter. On total capital spend, the combined entity has spent roughly $1.2 billion year-to-date. We expect to spend another $1.7 billion in the second half of the year, which is in line with our plans at the start of the year. CapEx is ramping up on many of the PDO projects and we plan to drill another 10 to 11 exploration wells in the third and the fourth quarter combined. On production cost per barrel, both Aker BP and Lundin's year-to-date figures are inflated by the lower-than-average production, in addition to high electricity prices and environmental taxes, give some upward pressure on costs. However, for the second half of the year, we expect cost per barrel to trend down with the higher production, and with a bit of help from the weaker Norwegian kroner, we expect cost to end up at roughly $7 per barrel. Now turning to dividends. According to Aker BP's dividend policy, our dividends shall reflect the financial capacity through the cycle, considering the long-term financial outlook and the credit profile of the company. Our ambition is to provide a resilient dividend, growing by at least 5% per year. The Board of Directors has resolved to increase the quarterly dividend with 11% to $0.525 per share starting from the next payment in August. This brings the targeted total dividend paid in 2022 up to $2 per share, an increase of roughly 48% from 2021. The topic of capital allocation is something that I'm sure you Karl will come back to you as part of the strategy that we will now move on to. And with that, I conclude the second quarter review and give the word back to you, Karl. Thank you.

Thank you, David. I'm sure I'll come back to capital allocation. You can be sure of that. But now that we have covered the quarter that lies behind us and the Lundin transaction is completed. I think it's a great opportunity to talk about what we want to achieve with the new Aker BP. And let me first set the stage with a high-level overview of why I think this is a great company, probably not a surprise, optimally positioned to take benefit of the ongoing energy transition. First of all, following the Lundin combination, we have an asset portfolio that I believe deserves to be called world-class, with industry-leading positions on both cost and emissions and with a huge value upside potential. Second, the portfolio also provides us with a unique starting point for our new decarbonization plan, which will take us to net zero by 2030. And third, we have for some years now worked to reshape and transform our business, both through digitalization and through the alliance model. The result is improved efficiency and quality and reduced costs. The acquisition of Lundin inspires us to further strengthen these efforts with renewed energy and a larger asset base as a target. And fourth, we have a resource base that I believe is unmatched by our peers and which we intend to convert into profitable growth over the next 5 years. And finally, we plan to deliver this while maintaining financial strength and growing dividends. We will of course dig deeper into each of these topics, but let us start with a high-level perspective. And here are some key figures for Aker BP following the Lundin transaction. We have roughly 2.8 billion barrels of reserves and resources, a production of 400,000 per day, growing to over 500,000 in the next 5 to 6 years, production cost below $7 per barrel and CO2 intensity below 4 kilos. And last but not least, a strong cash flow that provides the basis for a sustainable and growing dividend. For any company, this is a highly impressive set of numbers. However, to us they represent the core of the Aker BP value proposition, and we'll now take a closer look at each of these, starting with the resource base. Aker BP and Lundin were relatively similar in size prior to the acquisition. And hence our resource base has nearly doubled. The 2P reserves represent of course the remaining oil and gas in our producing fields, while the 2C represent undeveloped resources or our runway for growth. As you can see on this slide, our 2C resources are almost equal to the remaining 2P reserves in our fields. When combining the 2C over 2P ratio across all companies active on the Norwegian Continental Shelf, I actually do believe Aker BP is a clear number one. In 2022, we are going to take investment decisions covering roughly 2/3 of these 2C resources under the temporary tax regime and as we bring them on production in the years to come, we will be growing our production from around 400,000 barrels of oil equivalent this year to around 525,000 barrels of oil equivalents in 2028, as of course illustrated on the right-hand side of this slide. And remember, this production profile does not include any upside from 3P reserves or new exploration or additional IRR measures. This represents purely the production from our named projects. The ultimate purpose of this growth is of course not to grow volume or value and therefore, we target all our investment to breakeven at $30 oil price using a 10% discount rate. We are also supported by a good tax system here in Norway, as David just around through, which after the latest modification is probably the most successful in the world when it comes to aligning interest between the state and the industry. For us, this means reduced capital intensity and shorter payback, and hence more financial flexibility to fund both profitable growth and return capital to our owners. And while we have a leading -- an industry-leading growth profile, we're also pre-occupied with the environmental footprint of our production and to be the leading E&P company of the future, we also need to be leading in the area of sustainability. And we are, of course, all aware of the climate challenges that the world is facing and that over time the world needs to reduce its dependence on fossil fuels. However, this energy transition will take a long time and in all scenarios, oil and gas will remain an indispensable part of the global energy mix for many decades. Until then, the challenge is to deliver this oil and gas in a way that's both affordable, sustainable and reliable, and Aker BP is uniquely positioned in this respect. We are a low-cost producer with operating cost of around $7 per barrel. We likely have the lowest CO2 footprint in the industry and geographically, we are placed in one of the world's most stable and well-regulated countries, which is an excellent starting point for providing a reliable supply of oil and gas. Now excellent performance does not come by itself, the starting point is of course the resources in the ground. But world-class performance requires hard work. Doing the right things right and always chasing improvements. And I wanted to be embedded in Aker BP's DNA to work relentlessly to improve the way we work. The purpose is to ensure that we operate the assets and deliver our projects faster, cheaper and more efficient. And this is the reason we, for many years, have been developing our alliance model, which in essence is a superior collaboration model with our vendors. And this is also why we have been investing heavily in digitalization. And digitalization is not about hardware and software as many believe, but rather about how we can improve and in some cases revolutionize how we run our business to become as efficient as possible. The Lundin acquisition provided us with an excellent opportunity to accelerate this transformation pace, and this is of course an opportunity we have not missed. Now digitalization is a race without a finishing line, but we are convinced that being at the front provides us with a competitive advantage. With a portfolio of high-quality producing asset and with growth from low breakeven barrels in a supportive fiscal regime, we are set to generate strong and resilient cash throughout the cycle. At $90 per barrel, we estimate an operating cash flow after-tax from 2022 to 2028 between 25 and $30 billion. Of this, around $5 billion will be used for investment and debt service after-tax deductions, of course, leaving roughly $20 billion in free cash flow available for debt reduction and dividends in the period. If the oil price drops to $65 average over the same period, the free cash flow available will be around $15 billion. I do believe that these figures speak for themselves and that the numbers demonstrate the robustness of our portfolio. But those of you who have been following us know, of course, that we don't plan for this type of price environment and that we are currently seeing. And we are working continuously to make sure that the company is in the best possible shape to withstand the volatility of the commodity market. This is why we have a financial framework, which clearly defined our capital allocation priorities. And in our opinion, the most important capital allocation priority for an E&P company is to have a strong balance sheet. For us, this -- maintaining sufficient financial flexibility through the cycle by protecting our investment grade credit rating, keeping the leverage ratio at a reasonable level and having sufficient liquidity to weather whatever storm comes our way. The second priority is to drive value creation, which in our case means delivering on our profitable growth plan. We have an attractive portfolio of growth opportunities and we will invest in these only because we believe that it will create tremendous value. Our investments have a targeted breakeven oil price below $30 per barrel using a 10% discount rate. This means that they typically have about 30% unlevered internal rate of return, at an oil price of $65 per barrel and a payback time from first oil of less than 1.5 years. And finally, and let me be very clear on this point, all the value created in this company will be returned. And with the strong underlying cash flow generation, we are able to return a resilient and growing dividend while we invest in profitable growth, as demonstrated on the previous slide. And today's announcement of an 11% increase in the quarterly dividend is a good illustration of this point. Now so far, we've talked mostly about Aker BP and what our ambitions are. What's equally important is of course the question of how -- what is the strategy to reach our goals? We have recently updated our strategy framework to reflect the Lundin transaction, plus the fact that we are of course now moving into the execution phase of our large portfolio of growth projects. And in the following, I would like to share some thoughts on our 4 key priorities that will position us as the E&P company for the future. I will focus on efficient operations, on decarbonization, on delivery of our growth project, and how we work to establish the next wave of growth options for the company. And I will start with the first topic, the foundation for everything we do, safe and efficient operations. Many of you know our asset base well, or have heard me talk extensively of it in the past, so I will not spend a lot of time on details on each hub. What I would like to say is that with the acquisition of Lundin, the combined company has more scale and improved quality with a higher stake in Johan Sverdrup and inclusion of Edvard Grieg in the portfolio. Going forward, we will operate Edvard Grieg and Ivar Aasen as one area hub, under one leadership team in order to maximize the value creation for the whole area. We believe there should be synergies, not only in operation and logistics, but also in how production is optimized across the hub, and last but not least, how the projects in the area are executed. Now both Aker BP and Lundin have a very strong track record of operational excellence, which has been observed in a variety of performance indicators over the years, and this always starts with safety. Our goal when it comes to safety is crystal clear as it's always been. Anyone, and let me reiterate, anyone working with and for Aker BP should come home from work in the same or better condition than they arrived at work. At its core, this is of course an ethical and sometimes a legal responsibility. In addition, safety goes hand in hand with efficiency and quality. And safety is also important to attract and retain competence. So while our safety record is strong, and I'm thankful of that, we will never relax our target of 0 injuries. Production efficiency is another key operational metric. Our ambition is to deliver at least 95% production efficiency, which is way above both industry's average and top quartile, but within reach, given our high-quality asset base and really, really strong organization. 95% will put us firmly amongst the best companies in the industry, which is what we are, of course, striving for in all aspects of our business. And finally, low cost is pivotal to ensure robustness through the cycle. Our long-term target is to deliver barrels at less than $5 per barrel. Again, this is ambitious, but fully within reach with the portfolio we have. If we deliver on all of this, I'm confident that we are very well positioned to remain a relevant provider of much-needed energy for both end users and shareholders alike. Now let's turn to our second strategic priority, to decarbonize our business. The global energy challenge is to deliver energy that is both affordable, sustainable and reliable, and this is critically apparent today both in Europe and in the rest of the world. We know that we need to scale up investments in renewables to lower emissions, but we also know that we will need oil and gas for several decades. Therefore, at Aker BP, we believe that our most valuable contribution as a pure play oil and gas company is to help fuel the energy transition by returning maximum value to our shareholders and society through the energy we do produce, and to minimize our own emissions and finally, share technology and knowledge to help scale energy systems that the world will need. And Aker BP is well on our way to deliver on these ambitions. The E&P company of the future will naturally be leading also with respect to its climate footprint. Aker BP is one of the very top players with -- when it comes to carbon intensity and we have achieved this primarily through electrification. Valhall and Johan Sverdrup have both have power from shore and Edvard Grieg and Ivar Aasen will follow suit later this year. But we have also achieved significant effects through improving energy efficiency at our current asset, which is at the core of our operational philosophy, as in fact delivering on our annual energy intensity -- and in fact delivering on our annual energy efficiency target, it directly linked to the compensation of all employees and top management. And we experience a great drive to reduce emissions day by day. And finally, don't forget the denominator in the CO2 per barrel equation. Our DNA of continuously hunting the upsides in our assets, developing subsea tie-backs and infill wells has allowed us to maintain high production and deliver oil and gas at very low incremental carbon intensity. So with this great starting point, where do we go? Well, today we announced that Aker BP will be net zero across our own operations for 2030. We will leverage our low carbon intensity as a competitive advantage. Our decarbonization plans essentially follows 3 steps. First, to avoid emissions through electrification and portfolio rotation, that means retire high emissions assets and put greenfield developments on stream with power from shore. Second, we reduced the remaining emissions as much as we can through energy efficiency measures, and the residual hard to abate emissions unutilized through carbon removal projects outside our own oil and gas value chain. I will revert more to this shortly. But first, let us look at the trajectory when it comes to absolute emissions. Over the next few years, our carbon intensity is set to improve further, and already next year, over 80% of our production will be powered with [ hydro ] power from shore instead of gas turbines. We also plan to continue our energy efficiency journey, and we have so far managed a gross reduction of 20,000 tonnes to 40,000 tonnes per year and aim to continue this trend. These are small modifications and process optimization, which actually do have fantastic business cases at today's carbon cost levels. The result is that we forecast to stay below 4 kilograms of CO2 per BOE all the way until 2035. Now what does this emission look like in absolute terms? And this slide shows our gross operated emissions, measured in million tonnes and also including Scope 2 emissions. The graph shows that our current forecast is 38% lower next year than it would have been without any decarbonization measures historically. And in 2030, we forecast 55% lower emissions when they do nothing baseline. This corresponds to 800,000 tonnes of CO2 per year or about 2% of Norway's total CO2 emissions in 2021. I would say that's a good contribution for Norway to reach its national climate targets. As our old assets will be decommissioned and new greenfield developments will be added, our carbon footprint will drastically change. From 2040, our gross emissions will be close to 0, as more than 95% of our production will be electrified by then. So what then about the third step, the residual emissions. After we have done everything we can to reduce emissions, we commit to neutralize the residual emissions from 2030. That means that for every tonne of CO2 we emit, we will remove 1 tonne from the atmosphere. We have already covered our carbon capture needs until 2033 and have 50% of the cumulative needs until 2040. Most of this is through 2 proprietary reforestation projects acquired as a part of the Lundin transaction. And we are working to secure the rest of our neutralization with new projects and by reducing our own emissions further. It's also worth mentioning that we are currently evaluating entering carbon capture and storage. At the moment, we consider CCS potentially as an attractive standalone business opportunity, but in the longer run this may also be linked to our own decarbonization efforts, and of course, it's also a critical enabler for Europe to reach its climate targets. Now I want to change gear and move to the third strategic priority, delivering our project on time, cost and quality. The starting point is a world-class low cost, low carbon asset base to grow from. And we have plans in place to sharpen our performance even more along both dimensions. However, the big value driver that really sets Aker BP apart from other E&P is the substantial portfolio of growth projects. I think these projects have some very impressive aspects that we have highlighted many times over, but nevertheless, let's start with a high-level view of some of the numbers that our portfolio offers. Approximately 900 million barrels to be sanctioned by the end of 2022, an unlevered IRR of more than 30% at $65 oil, and less than 1.5 year of payback time from first oil across the portfolio at $65 oil, and less than 2 years across the portfolio if the oil price drops as low as $40 across the time period. I have yet to see any company that matches the magnitude and characteristics of this growth of value, which is another reason to get really excited about the future of this company. Now developing these resources is of course going to be capital intensive. And here we have included an illustration of the estimated CapEx, but we also included an after-tax flow effect of this CapEx which from a valuation perspective is far more relevant. After the recent modifications of the Norwegian petroleum tax, we get immediate tax deductions for a significant part of this CapEx. And the temporary tax changes that were introduced during COVID back in the summer of 2020, will remain in force for all projects that are PDO-ed by the end of 2022 and approved by the end of 2023. This means to be concrete that for every dollar we invest, we will get approximately 90% back with tax deductions, of which almost 85% of deductions is already in year 1. In reality, this represents a significant increase in our financial capacity compared to the old tax system. But tax is not enough to deliver on all of these investments, we need to work together with excellent suppliers. And a cornerstone of our operating model is our alliances. We have been developing and maturing our alliance model for many years by working systematically to improve our project execution process and supply chain efficiency. The model builds on some very simple, but yet powerful principles, including working as one team, establishing common goals and introducing shared incentive. It sounds really simple. So how does it really work? Well, most conventional projects are in fact run by several project organizations. The operator will have one, the EPC vendor one, some of the critical package vendors and other. In the alliance model, this is merged into one team, where we select the best person for the job, independent of home organization. Thus we created an organization with only one goal, which is to deliver the project on time and cost. Further, and as far as possible, we attempt to co-locate alliances in one place and we actually encourage the creation of an alliance culture where company borders are erased and focus in is on the task at hand. And finally, we have developed a model for aligning the incentives between the contractual group and the operator. In short, if the project is on time, budget and with the right quality, the contractor group should turn a healthy profit. On the other hand, if the project is delayed or the quality is lacking, the contractor group should expect to contribute. The totality of this principle working together is a significant improvement in time, cost, efficiency and quality. And while we have added significantly to our head count through the Lundin acquisition, it would still be impossible for a company of our size to take on the amount of projects we are about to without the support of our alliance partners. The alliance models also help us mitigate some of the supply chain issues that the world is facing these days. And this provides our key suppliers with more visibility and allows us longer-term planning. And let me show you one concrete example of how we are working together with our alliance partners to drive performance within one of our core activities, and I'll focus on drilling and well. Drilling and well is, of course, an absolute key activity for any of the E&P company, also for Aker BP. And over the coming years, it represents 30% to 50% of the total CapEx in a typical field development project. And we plan to drill almost 200 wells over the next decade. Drilling of a well is a highly complex process, involving many different disciplines and requires extensive planning. And we have for many years, been working systematically with our alliance partners to improve both time, cost and quality of this process. On the planning side, we have worked with our alliance partners to implement a state-of-the-art digital platform to improve the efficiency of the process with real-time simulations and collaboration across the different disciplines. This, of course, saves a lot of time, it actually allows us to plan a well in a day, and it also allows us to run many more simulation to optimize the design of each well at a far earlier stage in the field development process. In parallel, we have been working with our alliance partners to optimize the physical activities that are taking place on the drilling rigs to maximize the efficiencies of these expensive tools. This has resulted in strong and consistent performance and benchmarking data show that Aker BP is ahead of the game, both on drilling speed and on costs. Now with close to 200 wells in our plans over the next decades, the importance of this area cannot be overstated. This is definitely a key success factor in delivering our growth plan. But now let's zoom out to this plan. And this is in fact the latest illustration of our current project plan and we have also included Lundin projects with the Edvard Grieg tie-backs and Wisting. And as you can see here, we have now passed concept select for all these projects and we are on track to take final investment decisions for all of them by year-end. And of course, this is crucial for us to -- for the ability to deliver our ambitious production growth. As we deliver this growth program, production will climb from the current levels of around 400,000 barrels to 525,000 barrels per day in 2028. We expect this to be highly profitable barrels with NPV10 breakevens at or below $30. And while we deliver this massive investment program, we expect to stay financially strong, to maintain an attractive dividend stream to our shareholders. The projects that we just talked about are of course key to deliver these projects and a top priority in the years to come. But we also need to plan ahead and stretch to go beyond our current plans. As mentioned in my introduction, this production profile only includes the expected production from named project in our business. It does not include any 3P reserves, any upside, or any production from new discoveries. And this leads me to our final strategic priority, how we work establishing the next wave of profitable growth options on top of and beyond what is shown in this chart. Again, the starting point is, of course, our existing portfolio. This really shows that big fields get bigger, and we have several proud examples of this in our own portfolio, with Alvheim and the case in point, and with Skarv no chasing Alvheim. And we will continue to chase the upside in and around our existing fields. These upsides can be split into 3 categories. The first category is the 3P reserves, which represent upside potential in existing fields. We are addressing this potential with infill drilling, pressure support et cetera, to improve and increase recovery. The second category is the 2C resources. These are discoveries that have not yet been through the existing production hubs, and we include them in the overall plan for the hub. Finally, we have the exploration potential, near existing infrastructure, also called ILX. When we make discoveries here, they become part of the 2C resources just mentioned. And this brings me, to our next point, our exploration strategy. We will continue to be an active explorer on the Norwegian Continental Shelf, and we plan to drill roughly 10 to 15 wells per well -- per year going forward. And with the second largest portfolio on the Norwegian Continental Shelf with 189 licenses, we certainly have a lot of opportunity at our hands. The exploration strategy is the same as before. We will continue to focus most of our activity on near-field opportunities. And that is to maximize the utilization of our facilities and hence also keep production costs lower for longer. Around 80% of our exploration activity is geared towards the same. The rest is focused on new areas where we typically are targeting larger prospects, where there are both the risk, but also the potential reward is higher. After the combination with Lundin, we have an extremely strong exploration team. And we're also investing in technology and digitization to further strengthen our capacity and improve our performance within exploration. The overall goal for exploration is to find 250 million barrels of oil equivalent the next 5 years. Now compared to the discoveries on the Norwegian Continental Shelf in the recent years, this is an ambitious, but still achievable goal. But it's not enough to replace the reserves that we will be producing over the same period. So we're also working on other access to replace reserves. Aker BP's history lies in a combination between organic growth and value-accretive M&A. And actually a lot of the organic growth projects that we are currently working on is in fact coming from M&A transactions. Going forward, we will continue, probably not a surprise, to be active in the M&A space, but we will remain disciplined and only focus on opportunities that can contribute to further strengthen our value creation capabilities. Now let's sum up Aker BP's strategic priorities, which can probably be illustrated like this. The first priority is safe and efficient operation. The goals are 0 incidents, a production efficiency of 95%, and a production cost of $7 or below $7 per barrel. Secondly, we will decarbonize our business, keeping our equity greenhouse emissions below 4 kilograms per barrel and cutting Scope 1 and 2 emissions by 50% by 2030 and offset the remaining emissions to achieve net zero in the same year. Thirdly, we will deliver our growth projects on time, cost and quality and hence, deliver the strong production growth already talked about. And finally, we will work hard to establish the next wave of growth option, both chasing upside in existing assets, active exploration, and through value-driven M&A. Now before we close this presentation and open for questions, let me revisit what I think are the key elements that define Aker BP. Aker BP has a world-class asset base, which is operating -- Aker BP has a world-class asset base, which is operating at high efficiency and low cost and with significant upside potential from near-field exploration. We have the industry lowest CO2 footprint and we will be net zero by 2030. We are at the forefront when it comes to reshaping this industry through our alliance model and digitalization strategy. We have a unique resource base and we are going to monetize a large part of this for development projects that we are preparing to FID in 2022. All with highly attractive economics and all covered by a supportive tax regime, which will lift our production to 525,000 barrels by 2028. And last but not least, we have a strong financial framework, which allow us to fund this growth and to grow our dividends along the way. To sum it up, following the Lundin transaction, Aker BP is in even better position to profit from the energy transition. Now thank you for your attention. This concludes our presentation. And we'll now move to the Q&A session.

[Operator Instructions] We will now take our first question.

This is Sasikanth calling from Morgan Stanley. I had 3, please. The first was related to the CapEx and the impact of inflation. You remain on track to take PDOs for the remaining projects by the end of the year and it -- but it appears to me that there have been some changes in the distribution of the annual development CapEx till 2028 compared to your previous guidance. Can you comment -- can you please comment on whether the cumulative CapEx for 2022 to 2028, whether that has largely remained the same with -- relative to previous expectations? Has there been any increase in the development cost estimates for these projects when compared to, say, 6 months or to 1 year back? The second question was related to the dividend. You've highlighted, of course, the 11% increase in quarterly dividend, but the 2022 annual dividend is raised by around 5% to $2 per share. You also maintain the ambition to grow 5% per year at oil prices above $40 per barrel. Should we take this dividend growth on the annual dividend or the quarterly dividend run rate, just for reference? And also on the expected dividend growth, should oil prices stay above $100 per barrel? Do you believe the 11% quarterly dividend is a good reference point or the 5% increase in annual dividend as a good reference point? If you could comment on the sensitivity of the dividend growth, that would be helpful. My third question was related to the dividends again. Last quarter you mentioned capacity for extraordinary dividends or buybacks if prices sustained over $65 per barrel. Can we still expect any extraordinary dividends or buyback?

Thank you. Let's start with the CapEx. So of course, there are significant movements in the chain at the moment, mostly related to the ongoing war in Ukraine, which has impacted both capacity, capability, but also prices on a number of products and raw materials. In Aker BP, we are working actively to mitigate these issues, and so far, we've been successful in making sure that the current project portfolio is not impacted significantly by the current movement in prices. That does not mean that we will be immune to price increases, but it does mean that we are following this quite closely and that the alliance model allows us a better transparency than we would normally have had in the period. And then, of course, as you rightly point out, there has been some movements, mostly related to the tie-back projects on Edvard Grieg, which have been reallocated along the time line. The net cumulative after transaction CapEx is relatively unchanged from the previous estimates. And then maybe, David, you want to comment on the dividend distribution?

I can definitely do that. So I guess your question with regards to the 11% increase in the quarterly dividends. So this is -- means that we will now have an annual targeted dividend for 2022 up to $2 per barrel. And the new run rate is $2.1 per barrel. And we don't guide on dividend levels for 2023 yet. When it comes to sort of a reference dividend percentage increase, if oil prices are above $100, I think we will keep to the policy, stating that we will increase by a minimum of 5% if oil prices are above $40 per barrel. And then I think it's worth noting that the percentage increase from '21 to '22 is now roughly 48%. With regards to your third question around capacity for extraordinary dividends, as part of our policy, we have stated that at oil prices above $65 for a sustained period of time, we will be generating surplus cash on top of that, the dividends that we are paying as a dividend, the sort of a sustained dividend, or going with 5%, which means that there is capacity for extraordinary distributions and that's still part of the tool kit.

We will now take the next question from the next participant.

This is Teodor Nilsen, Sparebank 1 Markets. I had 3 questions. First one is on breakeven. And you are still underlying that you have a $30 per barrel breakeven requirement. Are you afraid that you will leave some profitable barrels behind in the current oil price environment? Second question, that is on your 2030 net zero ambition. I just wonder what kind of discount rate do you use for carbon reducing projects and how is that compared to your oil and gas discount rates? My third question is on your footprint in Norway. You have previously said that you will not consider to expand outside Norway. Of course, now after the Lundin deal, you're even bigger in Norway. I just wonder, will you now consider to expand outside Norway, and if yes, where would you like to expand?

Okay, excellent questions. Now first topic, when it comes to the breakeven requirements. I think the point of restating the breakeven requirement has to do with the robustness in the portfolio. We are, of course, all aware of the current volatility, and even in the oil and gas business, we tend to quite quickly forget that back in 2020, which is now 2 years ago, the oil price was significantly lower and we were struggling to actually offload our physical cargoes. So the whole point of maintaining a disciplined approach to projects is to have a sustainable, long-lived business. And then, of course, there will be discussions on certain projects whether 30% -- $30 is the right decision criteria. But as far -- so far, we've upheld that criteria. And it looks like on most of the projects this will be the case. I'm actually not worried about leaving barrels in the ground at this price environment. So far we have the project we have, we have the development that we believe is on track to deliver the project on the financial and physical parameters that we would like, and we believe that this is the capacity and a right project portfolio. Now when it comes to discount rate for CO2 projects, maybe we're too simple, Teodor, but we basically view CO2 reduction projects with the same parameters that we view investments in oil and gas production. So that means a 10% discount rate and the same parameters. So far we've actually yet to find projects that are not profitable with the current CO2 prices at these parameters. So we've never really seen -- we never really seen the need to revisit the discount rate for CO2 projects. And then your final question regarding a possible expansion, I think with the current portfolio we'd have, with a significant value creation and existing portfolio, about NOK 150 billion to invest -- be invested on the Norwegian Continental Shelf over the next 5 to 10 years, with a production increase of 400,000 to 525,000 barrels, I think we have a sufficient runway on the Norwegian Continental Shelf. So if anything, I'm probably more preoccupied focusing on what we do have in the hopper now than I have been previously.

We will now take the next question from the next participant.

I would like to ask 3 questions, if I may. I'm Yoann Charenton from Societe Generale, just in case. As you project the rate to become a breakeven target [ in state ], what makes you comfortable in seeing the Wisting project achieving its $30 per barrel breakeven? That is my first question. The second question is, I appreciate certainly that you feel like today is not the best time to disclose an updated production profile for your operated hubs that paid in view of Valhall performance in recent quarters. Would you mind providing a bit more color on the output trend in the second half of the year? What sort of likely exit rate should we expect for year end 2022? And my last question, if you don't mind, what does this new round of impairment on Ula mean in terms of reserves downgrade? How many more barrels do you expect to extract from Ula reservoir basically?

Thank you, Yoann. When it comes to Wisting, I think you're hitting the nail on the head. So Wisting is, of course, challenging in many aspects and is probably one of the projects where we see -- yes, probably the biggest difficulties in terms of achieving our $30 breakeven. That said, with the current process that is ongoing and Equinor is actually doing an excellent job, I'm still hopeful that the point forward economy at the point of decision will be $30 or close to $30. On production profile per hub, yes, would you like to comment on that? We normally don't give a lot of color to that, but...

No, just one comment to clarify with regards to production profile. So for the profiles that we give today -- in today's presentation are the latest profiles that we have both in terms of CapEx and production. So rest assured on that. And then I think as Karl has said, we don't give detailed guidance per hub. And when it comes to exit rates per end of year, of course, it depends, as I mentioned, on the Phase II start of Johan Sverdrup and also the ramp-up of that. So we've given guidance for second half of the year, [ 410,000 to 435,000 ]. I think we won't go into any more detail on that. When it comes to the Ula impairment, as mentioned in my walk-through, Yoann, the impairment is linked to revised production profile and cost profile of the field, and also an acceleration of the shutdown from 2032 to 2028. When it comes to the remaining reserves in the field, we typically don't comment on this outside the sort of the formal reserve updates. But I think a figure that could be used is roughly 15 million barrels left.

We will now take the next question from the next participant.

This is John Olaisen calling from ABG Sundal Collier. When I look at your production outlook chart, it seems to indicate that production from sanctioned projects will fall by a further 50% between '23 and '28, and since Johan Sverdrup represents about half of the production in 2023, I wonder if you could comment a little bit more about the assumed production profile from Johan Sverdrup. For instance, when do you expect it to go up plateau? So that's the first question. And the second question is about the oil and gas mix. Is it possible to give some indication about the mix, oil and gas, in '23 and in '28, please?

Yes. When it comes to the production profile, so remember the current presented production profile is as we stated, the named projects with the production profile they're reporting at the expected level. So this will be the sum of the P50 production profiles across the portfolio. And as you point out, there is a short dip between the -- between 2023, 2024, and then the acceleration back in 2027. Now this is dependent. Whether or not this dip will actually occur is still an open question, and it will essentially depend on 2 key parameters. The first one is, how much infill wells that there will be drilled on Johan Sverdrup, which is again coming back to your question what the production profile on Johan Sverdrup will actually be. And there is ongoing work now to finalize investment decision on infill wells. And the second is that for planning purposes, we have pushed the tie-back projects Rolvsnes, Lille Prinsen and Solveig Phase II to 2027, even with an FID date in 2022. Whether that will be the actual production profile at FID remains to be seen. And then, your final question was related to...

Oil and gas mix.

Oil and gas mix, okay.

So the combined entity will have roughly 12% gas in '23 and then we estimate to increase that ratio with the NOAKA project and also the King Lear projects, and of course also the satellites in the Skarv area, which -- there is a lot of gas in. So we think that the estimate is above 20%, perhaps also up to 25% in 2028.

All right. And I'm sorry, back to the question about plateau for Johan Sverdrup, what have you assumed it coming off plateau in the base case assumptions [indiscernible].

Previously we have referred discussions around a plateau rate to the operator. And I think that's still prudent to do. But as I said, this will depend on the number of infill wells to be sanctioned in the next couple of months.

We will now take the next question from the next participant.

It's James Hosie from Barclays. Yes, I've got 3, perhaps following up from the last one about the production profile. I think 2025 production in particular looks maybe around 40,000, 50,000 barrels a day lower than previously presented. I mean, just based on what you were saying before, is that all due to a delay in these projects for Edvard Grieg, is that the reason there?

James, I actually think you're mistaken. So the production profile is approximately 10,000 barrels lower than has previously been presented and that is related to our planning assumption on the Edvard Grieg tie-ins.

Okay. I will put on my glasses and check again. And then just a further question for me is, you've spoken a lot over the years about the benefits of your alliance model in the service sector. I mean how do you benefit Aker BP in this more active and inflationary environment and is it now the real advantages of that model become apparent?

I actually think that we've already seen a lot of the benefit from the alliance model, both in terms of our capacity to execute the current profile, the maturity we've seen now with the ongoing development project, which now at the pre-FID level is far more mature than any project that I've been exposed to. And finally, since we have already selected vendors, they have -- and they're very transparent on what they need to deliver. They have the capacity to already now go out and allocate production slots and buy forwards in terms of raw materials, et cetera. So I do believe that the alliance model is actually -- at least it's performing -- it's consolidating a basis that gives us an opportunity to mitigate the current inflation in a way we would not have been able to do without the alliance model. And then, of course, it doesn't make us immune to increases in commodities such as steel prices. But it gives us an ability to negotiate with these vendors on who is best placed in the value chain to pick up that risk. And one of the points I tried to make in my presentation is that with the current tax scheme and the way we have set up the hopper, our production projects, we are probably better placed to deal with these possible price increases than the vendors. And since we already have the trusts of these companies and have worked with them extensively over the last few years, we can discuss these topics with far more openness than we could have in a competitive situation.

Okay. So just on that last point, you're saying that you are going to take on more input price risk than you had previously?

At least that's what we're currently discussing, and that will be related mostly to, let's say, open book principles. It's related to the fact that for most of these vendors, if they're going to pick up that risk, the price increase will be far higher than the underlying commodity price increase just to mitigate for their financial risk on top of that.

We will now take the next question.

It's Mark Wilson at Jefferies. And can, of course, first say congratulations on getting the Lundin deal completed, amazing deal there. And then to move on, my questions would be, you're obviously in a unique position to sanction 2 new greenfield projects by the end of the year, NOAKA and Wisting. So can I check on some of the bigger items regarding variables on those. First would be electrification. Could you remind us where both of those sit in terms of electrification of facilities? And also with Wisting, how that would fit within a greater Barents Sea gas development, if there is indeed want to be tied into any part of that offtake line? Just wondering about those bigger picture items that may be -- well, will have to be included in the sanction. And then the follow-on from that is, if these 2 sanctioned by year end as expected, you are immediately into the steel cutting and the spend after the CapEx program next year.

Yes. So let's start with the bigger projects. So there are 3 sizable projects that constitutes a large part of the CapEx in our program. And these are of course NCP, King Lear, or PVP as it's now called, it is NOAKA and it's Wisting. So when it comes to the new development on Valhall, the New Central Platform or production well platform, Valhall is already electrified, there is surplus capacity in the HVDC line, which we will utilize to power both the new infill platform on the Valhall field and King Lear. So that will just continue the electrification strategy at Valhall. NOAKA will be a new line coming out from the Western Coast of Norway, actually way inside the fjords to be directly connected to the Norwegian backbone and avoid grid infrastructure weakness at the coast. We're well on our way to progress our project and do you believe that we have that under control. And then, of course, Wisting will also be electrified directly with the new infrastructure in the northern parts of Norway. Now Wisting as it sits right now, has very little gas. It's a shallow oil reservoir. I think the peak gas output is around 1.7 million standard cubics a day. So the gas will be tied back to Johan Castberg, but I don't really see Wisting fitting into a ground and gas strategy simply because of the PVT composition of the oil in that area. Now when it comes to spend, when we move into an FID situation, we are of course stepping up the CapEx. But it doesn't necessarily mean that the first step after delivering the PDO is to cut steel. We assume that the PDOs will be approved in the spring of 2023 in the Norwegian Parliament for a large project that is above NOK 10 billion. And then we'll start on a detailed engineering phase. And most of the spend will actually initially be procurement spend where we start buying packages and setting orders. I assume steel cutting will, at earliest, be starting towards the summer, autumn of 2023, dependent a bit on the schedule at the different yards.

It appears there is no further questions at this time. I'd like to turn the conference back to you for any additional or closing remarks.

Thank you, operator, and thank you everyone who have given us -- challenged us with your very intelligent questions. This is actually perfect because we had scheduled to end right now. So thank you all. If you have any follow-up questions, don't hesitate to contact us at the IR department at Aker BP. You will find the contact details on our website, unless you already have them on your smartphone. With that, thank you all and have a great summer.