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 two main parts.
We will start with a review of the second quarter performance and results, and this will be covered in tandem by our CEO, Karl Johnny Hersvik, and our CFO, David Tønne. After that, Karl Johnny Hersvik will give an update on the strategy for Aker BP. In total, we expect this to take a little more than one hour, and we will then have a Q&A session. Now let's start. Karl Johnny Hersvik, 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 transactions on the thirtieth 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 two 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 portfolio, we are firmly on track to submit PDOs for the remaining projects by the end of the year. Including the additions from the Lundin portfolio, this means that we will sanction projects with a total of roughly 900 million barrels of contingent resources under 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 three main credit rating agency, who all upgraded their rating of Aker BP during the last quarter.
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 bring the targeted full-year dividend up to $2 per share. Overall, this has been another strong quarter for Aker BP.
Let me now first dive into a bit more details on the Lundin integration. Everyone that has been involved in 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 Norge. We used these learnings from both these transactions when we're 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 organizational 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 the first of October. 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 two leading European E&P companies, we are truly generating the E&P company for the future with low cost, low carbon barrel, an 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 strategies update session shortly. 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 lift, we sold roughly 173,000 barrels per day. Now 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-over-quarter at 35,000 barrels of oil equivalent, helped by production from Alvheim 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 HSE 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've had 0 process safety events and only one minor injury recorded. That is, of course, 1 too many, but it's still a good representation of a strong safety culture. However, the only good HSE day was yesterday, and we're working relentlessly to continue the improvement. Turning to CO2, our CO2 intensity was slightly down quarter-on-quarter to four kilograms per barrel, below our target of five kilograms per barrel and slightly less than one-third 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.
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 the thirteenth of June, we do not consolidate production, revenues, and cost before first of July, so the numbers I have 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 Energy's operational performance for the first half of the year, and the highlights include 181 thousand 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.
While both the production efficiency and operational cost was 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 asset and the 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. 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. This quarter, we selected concepts for all the remaining projects, including the Lundin project at Lilleprinsen, Rolfsnes, Fullfield, 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. This year, we have had a very active exploration program. Last week, we announced a sizable discovery at Storjo in the Skarv area. Preliminary estimates show between 25 and 80 million barrels of oil equivalents, which is substantially higher than the pre-drilled estimates of 16 million-45 million barrels of oil equivalents.
Aker BP also had a relatively high working interest in the discovery of 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 is to me a very exciting prospect.
Now, this type of discovery fits perfectly into Skarv area strategy of finding and adding tieback candidates to build yet another wave of developments post the Skarv Satellite Project, which is currently ongoing in the development phase. 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. Three additional prospects are lined up to be drilled in the third quarter, and in addition to the three wells in Skarv area in Q3, we plan to drill another eight wells for the combined company in the second half of the year. Currently, we are drilling Njord 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, Calle, and good morning, everyone. The second quarter has been another eventful quarter for Aker BP, and the main event, as Calle 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 first 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 on to the financial highlights of the quarter, as Calle 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. 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. 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 equivalents, down from $171 last quarter. Combined, this gave us a realized average hydrocarbon price of $126.8 per barrel of oil equivalents, up 10% quarter-over-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 million and other operating expenses of $20 million from total income, we get an EBITDA of $1.8 billion, a margin of almost 90%. Exploration expenses amounted to $67 million, of which 34 was dry well cost 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 on 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 million. Tax expenses amounted to $878 million, and the relatively 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. 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 at 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 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 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 three 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.
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 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 occurred because of the consolidation of the acquired business from Lundin at fair value. Note two 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 arises 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 new Aker BP shares. Bank and bond debt increased to $5.8 billion, mainly related to two 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 gives 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 first. This slide is therefore developed to give a fair representation of Aker BP's current capital structure post the transaction.
We have adjusted the cash and liquidity position and debt facilities to include the actions taken on July 1, 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. We always believed that the transaction would be credit accretive, and during the second quarter, this has been confirmed by all three rating agencies with credit upgrades to BBB 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 first. 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 three points.
One, immediate tax depreciation of investments within special petroleum tax. Two, refund of potential tax losses within special petroleum tax. Three, this is then 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. As normal, in June, we fixed the first three tax installments for the fiscal year 2022 to be paid in the third and 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 10-11 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, the high electricity prices and environmental taxes give some upward pressure on cost. 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 Johnny Hersvik, will come back to as part of the strategy update that we will now move on to. With that, I conclude the second quarter review and give the word back to you, Karl Johnny Hersvik. Thank you.
Thank you, David. Sure, I'll come back to capital allocation. You can be sure of that. 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. 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.
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 cost. The acquisition of Lundin inspires us to further strengthen these efforts with renewed energy and a larger asset base as a target.
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 five years. 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. 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 5-6 years, production cost below $7 per barrel, and CO2 intensity below four kilos. 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 two-thirds of these 2C resources under the temporary tax regime. 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 equivalent in 2028, as of course illustrated on the right-hand side of this slide.
Remember, this production profile does not include any upside from 3P reserves or new exploration or additional IOR measures. This represent purely the production from our named projects. The ultimate purpose of this growth is of course not to grow volume, but value, and therefore we target all our investment to break even at $30 oil price using a 10% discount rate.
We are also supported by a good tax system here in Norway, as David just ran 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.
While we have an industry-leading growth profile, we're also preoccupied with the environmental footprint of our production. To be the leading E&P company of the future, we also need to be leading in the area of sustainability. 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. 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. World-class performance requires hard work, doing the right things right, and always chasing improvements.
I want it 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 our assets and deliver our project faster, cheaper, and more efficient. 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. This is also why we've been investing heavily in digitalization.
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 break-even barrels in a supportive fiscal regime, we are set to generate strong and resilient cash flow through the cycle. At $90 per barrel, we estimate an operating cash flow after tax from 2022 to 2028, between $25 billion and $30 billion.
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-dollar 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.
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. 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.
In our opinion, the most important capital allocation priority for an E&P company is to have a strong balance sheet. For us, this means 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 they will create tremendous value. Our investments have a targeted break-even 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. Finally, and let me be very clear on this point, all the value created in this company will be returned. 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 a previous slide.
Today's announcement of an 11% increase in the quarterly dividend is a good illustration of this point. Now, so far, we have talked mostly about Aker BP and what our ambitions are. 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. In the following, I would like to share some thoughts on our four 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. Let us 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, 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. Safety is also important to attract and retain competence.
While our safety record is strong, and I'm thankful of that, we will never relax our target of zero 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 its really, really strong organization.
95% will put us firmly among the best companies in the industry, which is what we are, of course, striving for in all aspects of our business. 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.
It's to minimize our own emissions and finally share technology and knowledge to help scale energy systems that the world will need. 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 low, when it comes to carbon intensity, and we have achieved this primarily through electrification.
Valhall and Johan Sverdrup have both had power from shore, and Edvard Grieg and Ivar Aasen will follow suit later this year. We have also achieved significant effects through improving energy efficiency at our current asset, which is at the core of our operational philosophy, and in fact, delivering on our annual energy efficiency targets is directly linked to the compensation of all employees and top management, and we experience a great drive to reduce emissions day by day.
Finally, don't forget the denominator in the CO2 per barrel equation. Our DNA of continuously hunting the upsides in our assets. Developing subsea tiebacks and infill wells has allowed us to maintain high production and deliver oil and gas at very low incremental carbon intensity.
With this great starting point, where do we go? Well, today we announced that Aker BP will be net zero across our own operations from 2030. We will leverage our low carbon intensity as a competitive advantage. Our decarbonization plans essentially follows three steps. First, to avoid emissions through electrification and portfolio rotation.
That means retire high emissions asset and put greenfield developments on stream with power from shore. Second, we reduce the remaining emissions as much as we can through energy efficiency measures, and the residual hard to abate emissions are neutralized through carbon removal projects outside our own oil and gas value chain. I will revert more to this shortly. First, let us look at a 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 hydropower 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 20,000-40,000 tons per year and aim to continue this trend.
These are small modification 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? This slide shows our gross operated emissions measured in million tons 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. In 2030, we forecast 55% lower emissions than the do nothing baseline. This corresponds to 800,000 tons 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 older 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 zero, as more than 95% of our production will be electrified by then. 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 ton of CO₂ we emit, we will remove one ton 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 to proprietary reforestation projects acquired as a part of the Lundin transaction.
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. In the longer run, this may also be linked to our own decarbonization efforts.
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. Nevertheless, let's start at the 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.
Less than one and a half year of payback time from first oil across the portfolio at $65 oil, and less than two years if the portfolio across the portfolio, if the oil price drop as low as $40 across the time period. I have yet to see any company that matches the magnitude and characteristics of this growth portfolio, 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. We have 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.
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'd 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 through tax deductions, of which almost 85% of deductions is already in year one. In reality, this represent a significant increase in our financial capacity compared to the old tax system.
Tax is not enough. To deliver on all of these investments, we need to work together with excellent suppliers. 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, another.
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 create 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 is on the task at hand.
Finally, we have developed a model for aligning the incentives between the contractor 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 these principles working together is a significant improvement in time, cost, efficiency, and quality. While we have added significantly to our headcount 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 allow us longer-term planning. Let me show you one concrete example of how we're 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 E&P company, also for Aker BP. Over the coming years, it represents 30%-50% of the total CapEx in a typical field development project. We plan to drill almost 200 wells over the next decade. The drilling of a well is a highly complex process involving many different disciplines and requires extensive planning.
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 simulations 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 cost. 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. Now, let's zoom out to this plan.
This is, in fact, the latest illustration of our current project plan, and we have also included the Lundin project with the Edvard Grieg tiebacks, and Wisting. 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. 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 NPV-10 break-evens at or below $30. While we deliver this massive investment program, we expect to stay financially strong to maintain an attractive dividend stream to our shareholders.
The project that we just talked about are, of course, key to deliver this project and a top priority in the years to come. 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 projects in our business. It does not include any 3P reserves, any upside, or any production from new discoveries.
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. History 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 now chasing Alvheim.
We will continue to chase the upside in and around our existing fields. These upsides can be split into three 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. 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 10-15 wells per year going forward. 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 this aim. The rest is focused on new areas where we're typically targeting larger prospects, where they 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 five years. Now, compared to the discovery rates on the Norwegian continental shelf in the recent years, this is an ambitious but still achievable goal.
It's not enough to replace the reserves that we will be producing over the same period. We're also working on other assets to replace reserves. Aker BP's history lies in a combination between organic growth and value accretive M&A. Actually, a lot of the organic growth project that we are currently working on is in fact coming from M&A transactions.
Going forward, we will continue, probably no 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 zero 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 four kilograms per barrel and cutting our Scope 1 and Scope 2 emissions by 50% by 2030 and offset the remaining emissions to achieve net zero the same year. Thirdly, we will deliver our growth project on time, cost, and quality and hence deliver the strong production growth already talked about.
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 at high efficiency and low cost and with significant upside potential from near field exploration. We have the industry's 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 with development project 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.
Last but not least, we have a strong financial framework which allow us to fund this growth and to grow 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.
Ladies and gentlemen, if you would like to ask a question, please signal by pressing star one on your telephone keypad. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. A voice prompt on the phone line will indicate when your line is open. Please state your name and company before posing your question. Again, press star one to ask a question. We will now take our first question. Your line is open. Please go ahead.
Hi, this is Sasikanth calling from Morgan Stanley. Thanks for taking my questions. I had three, 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. 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 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 CapEx, development cost estimates, for these projects, when compared to, say, six months or to a year back? The second question was related to the dividend. You 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 maintained 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?
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 sustain over $65 per barrel. Can we still expect any extraordinary dividends or buyback?
Thank you. Let's start with the CapEx. Of course, there are significant movements in the vendor chain at the moment, mostly related to the ongoing war in Ukraine, which have 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.
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 do mean that we are following this quite closely and that the alliance models allows us a better transparency than we would normally have had in the period.
Of course, as you rightly point out, there has been some movements, mostly related to the tieback projects on Edvard Grieg, which have been reallocated along the timeline. The net cumulative after transaction CapEx is relatively unchanged from the previous estimate. Maybe David, you want to comment on the dividend distribution.
Yeah, I can definitely do that. I guess your question with regards to the 11% increase in the quarterly dividends. This, you know, means that we will now have an annual targeted dividend for 2022 up to $2 per barrel. The new run rate is $2.1 per barrel. 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.
I think it's worth noting that the percentage increase from 21 - 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 the dividends that we are paying as a dividend, sort of a sustained dividend or growing with 5%. Which means that there is capacity for extraordinary distributions, and that's still part of the toolkit.
Thank you. We'll now take the next question from the next participant. Please go ahead. Your line is open.
Good morning, Karl Johnny Hersvik, David Tønne. This is Keld Nielsen from SpareBank 1 Markets. Thank you for a very extensive, useful presentation. I have three questions. First one is on breakeven. 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. 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 don't want to consider to expand outside Norway. Of course, now after Lundin, you are even bigger in Norway. Just wonder, will you now consider to expand outside Norway? If yes, where would you like to expand? Thank you.
Okay, excellent questions. Now, first topic when it comes to the breakeven requirements. I think the point of restating the breakeven requirements 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 two years ago, the oil price was significantly lower, and we were struggling to actually offload our physical cargoes. The whole point of maintaining a disciplined approach to projects is to have a sustainable long-lived business. Then of course there will be discussions on certain projects whether 30%, $30 is the right decision criteria.
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.
We believe that this is the capacity and the right project portfolio. Now when it comes to discount rate for CO2 project, maybe we're too simple, Keld Nielsen, but we basically view CO2 reduction projects with the same parameters that we view investments in oil and gas production. 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. We've never really seen the need to revisit the discount rates for CO2 projects. Then your final question regarding a possible expansion.
I think with the current portfolio, we'd have, with a significant value creation in the existing portfolio, about NOK 150 billion to be invested in on the Norwegian continental shelf over the next 5-10 years. With a production increase of 400-525,000 barrels, I think we have a sufficient runway on the Norwegian continental shelf. If anything, I'm probably more preoccupied focusing on what we do have in the hopper now than I've been previously.
Sure. Understood. That's all for me. Thank you.
Thank you. We'll now take the next question from the next participant. Your line is open. Please go ahead.
Good morning, Karl Johnny Hersvik and David Tønne. Thank you for the presentation. I would like to ask three questions, if I may. I'm Yoann Charenton from Société Générale, just in case. As you project the rate become a break-even target instead, what makes you comfortable in seeing the Wisting project achieving a $30 per barrel break even? 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 as stated in view of outperformance 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?
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.
Thank you, Yoann. When it comes to Wisting, I think you're hitting the nail on the head. Wisting is of course challenging in many aspects. It's probably one of the projects where we see the biggest difficulties in terms of achieving a $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. Would you like to comment to that? We normally don't give a lot of color to that, but
No, just one comment to clarify with regards to production profiles. The profiles that we give today in today's presentation are the latest profiles that we have both in terms of CapEx and production. Rest assured on that. Then I think as Karl Johnny Hersvik said, we don't give detailed guidance per hub. When it comes to exit rates per end of year, of course, it depends, as I mentioned, on the phase two start upon Johan Sverdrup and also the ramp up of that. We've given guidance for second half of the year, 410-435. I think we won't go into any more detail on that.
When it comes to the Ula impairment, as mentioned in my walkthrough, 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.
Thank you both again.
Thank you. We'll now take the next question from the next participant. Please go ahead. Your line is open.
Yes, this is John Olaisen calling from ABG Sundal Collier. Thank you for taking my question. When I look at your production outlook chart, it seems to indicate that production from sanctioned projects will fall by more than 50% between 2023 and 2028. 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 off plateau? That's the first question. The second question is about the oil and gas mix. Is it possible to give some indication about the mix of oil and gas in 2023 and in 2028, please? Thank you.
When it comes to the production profile, remember the current presented production profile is, as we stated, the named projects with the production profile. They're all reporting at the expected level. This will be the sum of the P50 production profiles across the portfolio. As you point out, there is a short dip 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 two 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 on what the production profile on Johan Sverdrup will actually be. There is ongoing work now to finalize investment decision on infill wells. The second is that, for planning purposes, we have pushed the tieback projects, Rolfsnes, Lilleprinsen, and Alvheim Phase Two to 2027, even with an FID date in 2022. Whether that will be their the actual production profile at FID remains to be seen. Then your final question was related to-
Oil and Gas Mix
Oil and gas mix. Okay.
The combined entity will have roughly 12% gas in 2023. 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 is a lot of gas in. We think that the estimate is above 20%, perhaps also up to 25% in 2028.
Right. Sorry, back to the question about plateau for Johan Sverdrup. When have you assumed it's coming off plateau in the base case assumptions on
Previously, we have referred the discussions around the plateau rate to the operator, and I think that's still prudent to do. As I said, this will depend on the number of infill wells to be sanctioned in the next couple of months.
Okay. Thank you. Thank you.
Thank you. We'll now take the next question from the next participant. Please go ahead. Your line is open.
Hi, good morning. It's James Hosie from Barclays. I have a couple of questions to you folks following up on 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?
Here, James, I actually think you're mistaken. The production profile is approximately 10,000 barrels lower than has previously been presented, and that is related to a planning assumption on the Edvard Grieg tie-ins.
Okay. I will put on my glasses and check again. Then just a further question from me is, you've spoken a lot over the years about the benefits of your alliance model with the service sector. I mean, how do these relationships benefit Aker BP in this more active and inflationary environment, and is it now that 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. 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.
I do believe that the alliance model is actually, at least 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. Of course, it doesn't make us immune to increases in commodities such as steel prices. It do gives us an ability to negotiate with these vendors on who is best placed in the value chain to pick up that risk.
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 production projects, we are probably better placed to deal with these possible price increases than the vendors. Since we already have the trust 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, thanks. Just on that last point, you're saying that you are gonna take on more input price risk than you would previously?
At least that's what we're currently discussing. 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 pricing increase just to mitigate for their financial risk on top of that.
Okay. Thank you.
Thank you. We'll now take the next question. Please go ahead. Your line is open.
Hi. Good morning. It's Mark Wilson at Jefferies. Can I first say congratulations on getting the Lundin deal completed. Amazing deal there. To move on, my questions would be, you're obviously in a unique position to sanction two new greenfield projects by the end of the year, Noaka and Wisting. 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? Also with Wisting, how that would fit within a greater Barents Sea gas development, if there is indeed one to be tied into any part of that off-take line? Just wondering about those bigger picture items that may be in.
Well, will have to be included in the sanction. Then the follow on from that is if these two sanctioned by year-end as expected, you are immediately into the steel cutting and the spend as per the CapEx program next year. Thank you.
Let's start with the bigger projects. There are three sizable project that constitutes the large part of the CapEx in our program. These are, of course, NCP King Lear, or PWP as it's now called. It is Noaka, and it's Wisting. 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'll utilize to power both the new infill platform on the Valhall field and King Lear. 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 that project and do believe that we have that under control. Of course, Wisting will also be electrified directly with a 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 cubic meters a day. The gas will be tied back to Johan Castberg.
I don't really see Wisting fitting into a grander gas strategy simply because of the PVT composition of the oil in that area. 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.
Then we'll start on a detailed engineering phase. The 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.
All right. Excellent answers. Very clear and, thank you very much and good luck.
Thank you. 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. 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. Thank you all. If you have any follow-up questions, don't hesitate to contact us at the IR department at Aker BP. You'll 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.