Good morning. Welcome and thank you for tuning in to Aker BP's first quarter 2022 presentation and conference call, which, as always, will be hosted by our CEO, Karl Johnny Hersvik, and our CFO, David Tønne. As always, after the presentation, we will open for questions. With that, here is Karl.
Thank you, Kjetil, and a really good morning to all of you listening in to this Q1 presentation in 2022. First quarter of 2022 was yet another quarter of record earnings and strong progress for Aker BP. The main driver of our financial performance was, of course, the high oil prices and even higher gas prices in Europe. Together with stable production, this resulted in a record high free cash flow of $1.1 billion. The backdrop for the record high gas prices is the European energy crisis, which has been long in the making, in my opinion, and has been further amplified by the Russian war against Ukraine. In this dire situation, we are doing what we can to maximize our gas export to Europe, and we have managed to increase our gas volumes to a record level in Q1.
We have also, as a part of the same strategy, started a blowdown phase of Skarv, which will further increase our gas production ahead. We have sold our stake in Cognite this quarter and realized a significant gain which contributed to the record results. I'll comment on that a bit later. Now turning our attention to the growth project, I'm pleased to see that all early phase projects, which is project where we are yet to submit the PDO, are progressing towards PDO submissions by the end of 2022, and we are on track to deliver all projects on time. Hod started producing from the first well in early April, and the team is now working to bring the other five wells on stream in the coming weeks or months.
At Johan Sverdrup, the phase two development made significant progress during the quarter and remains on schedule for first oil in the fourth quarter of 2022. The PDO for Hanz and Kobra East Gekko have now been approved by the authorities, and the Trell and Trine project has secured approval of its pre-investment program. We have, of course, also made good progress in the Lundin transaction, which has now been approved by the shareholders of both companies, and we expect the final government approval shortly. Closing of the transaction is planned for end of June, with a full organizational integration from the first of October. With that, let's have a closer look at the production performance of the first quarter. The Q1 production ended at just above 208,000 barrels per day, stable quarter-on-quarter.
The slight increase was driven by higher oil production from Skarv and the Alvheim area as well, partly offset by lower production from the Ula area and Ivar Aasen compared to the previous quarter. Including a bit of overlift, we sold 216,000 barrels per day in the quarter. Our gas production reached a record level of 45,000 barrels of oil equivalents, which is a record, of course, for Aker BP. This was helped by the first full quarter of production from Ærfugl. Late in the quarter, we also started the gas blowdown on Skarv, which will further boost gas production going forward. I'll come back to that shortly. At Ivar Aasen, we had an unplanned shutdown towards the end of the quarter due to technical issues on Edvard Grieg.
The production has now restarted at approximately a 50% level, and we expect to be back at full capacity when remediation works are completed in May. In order to minimize the impact of this shutdown, we have used the opportunity to perform maintenance, which was originally scheduled for a turnaround later in the quarter. Just to confirm, we remain on track with regards to our full-year production guidance of 210,000-220,000 barrels per day. Now let's move from production to HSE performance. Safety is always and has always been our first priority, and we are working continuously to build and maintain a strong safety culture in Aker BP.
In the second half of last year, the trend started to move in the wrong direction with a total of 13 injuries with low or moderate severity in the last half year. This was countered by a significant effort, and we're now back on track with only one injury recorded in the Q1 2022. When it comes to CO2 emissions, we remain unchanged at 4.8 kilograms per barrel, which is below our own target of 5 kilograms and less than about a third of the global industry average.
We continue to drive emissions down through energy efficiency improvements, electrification of our new fields, and through close collaboration with suppliers to address emissions also in the upstream value chain, that is upstream of our value chain. We are also working on a decarbonization strategy to cover our residual emissions with a view to achieve net zero of scope one and two by 2030. We believe that low CO2 emissions are a competitive advantage, of course, with regards to direct emission cost, but also with regards to access to and cost of course, capital. Now, moving onto our assets and our projects, let me first comment on the sale of Cognite. It should be well known that the digitalization has been a cornerstone of the Aker BP improvement strategy for many years now.
Some of you who have followed Aker BP have heard me talk about digitalization repeatedly. Our ultimate goal is to utilize the full power of digital technology to transform the way we operate and develop our assets. One of the steps we took very early on was to contribute to establishing Cognite, to help develop a state-of-the-art data platform to support our digital strategy. We were Cognite's first customer and instrumental in the development of what is now its main product, Cognite Data Fusion. Cognite Data Fusion has since become a commercial success with many customers across various industries, and as such, our strategic purpose of the ownership in Cognite has been fulfilled. In Q1, we sold our shares to Saudi Aramco for a consideration of $118 million, which resulted in a net gain of $99 million in the quarter.
Through the Cognite journey, we have established an excellent platform for our continued digital journey. The next step is to establish an ecosystem of applications on top of this platform. In this context, we have participated in the founding of yet another company called Aize. This company is building applications for project execution and operational support on top of CDF. Aize is not starting from scratch. The company is building on decades of software development within the Aker group, and the first priority for this collaboration is to develop a truly digital project execution model. The first use will be the NOA Fulla project, and we believe this holds the potential to become a new industry standard. Aize is also working to improve condition-based maintenance and barrier management for quite a few of our assets.
Now let's move on to our assets and project. This time, let's begin with Skarv. The Skarv field has now been in production for nine years, and oil production from the original reservoirs is declining. Our strategy here is very, very similar to the one we have had for years on Alvheim, which is simply to find additional resources in the area and tie them back to, and hence maximize the capacity utilization of the Skarv FPSO. We are simply using the same strategy developed on Alvheim on Skarv. The first big tieback wave was completed last year with the startup of Ærfugl, two years ahead of original schedule. We also managed to literally squeeze in the small but highly profitable Grosbeak development. In parallel, a combination of transactions and exploration, we have added discoveries like Shrek, Örn, and Alve Nord to the resource base.
We're now preparing for the next wave of tiebacks through the Skarv Satellite Project. Skarv contains a mix of oil and gas, and until now, we've held back on the gas to maximize oil recovery. This means, in practice, that we have reinjected a large part of the produced gas to support reservoir pressure. We have now come to a point where it actually makes more economic sense to export the gas, both because the remaining oil volumes and potential are low and because of the high gas prices. We have therefore initiated what we call the Skarv blowdown. In technical terms, this means that we have stopped injecting gas in certain reservoir compartments at Skarv and instead are exporting this gas to meet the strong demand in Europe.
The blowdown also fits well in the wider area strategy, because one benefit of the blowdown, of starting the blowdown now, is that it makes more processing and export capacity available for the Skarv satellites, which are of course due to come on stream a bit later on, the first one from 2025. In the first quarter, we did a concept select for the Skarv satellite. The goal is to submit PDOs by the end of this year, and we're well on track. The satellites will add close to 70 million barrels to our reserves and is an excellent illustration of our strategy of maximizing value creation through the assets through continuous areas development.
We are also preparing for the longer term in the Skarv area, and this year we have planned a total of 5 exploration wells in the Skarv area with a combined net unrisked volume potential of more than 90 million barrels. We are actually very excited about this program, which have the potential to add substantial resources and contribute meaningfully to the value creation at Skarv into the next decade. Now let's move on to our project in execution, which means after we have delivered PDO. Let's start with one that has started production, namely Hod. Hod was actually the first project to be sanctioned under the temporary tax regime only the day after it was approved in the Norwegian parliament. Only 22 months later, we're able to flip the switch on the first well in the field.
In my humble opinion, this is remarkable achievement in the midst of a pandemic world. Hod is developed with an unmanned platform, which is remotely operated from Valhall. We have drilled six new wells, and the first started producing in April. Work continues to stimulate the remaining wells and bring them on stream over the coming weeks and months. To me, this is a great example of what Aker BP is all about. Low cost, low carbon barrels, strong project execution in close collaboration with our alliance partners to secure attractive project economics. With power from shore via Valhall, the production from Hod will have minimal CO2 emissions. In this project, a total of five alliances have contributed, and we've been working as one team from start to finish.
We truly believe that this is the way forward for the industry, bringing in the best players across the value chain, aligning interests, and working together to develop better, more robust projects and hence create even more value. Now let's move on to a couple of other projects in the execution phase. Starting with Johan Sverdrup, the PT platform and the bridge linking the platform back to the field center were installed according to plan and cost during the quarter, and drilling campaigns have started ahead of schedule in January. This leaves us firmly on track to produce first oil in Q4 2022 from this ongoing amazing project. Both Kobra East Gekko in the Alvheim area and Hanz at Ivar Aasen had their PDOs approved by the authorities in Q1 and have now moved into execution.
At KEG, which is what we call Kobra East Gekko, we are now preparing for the installation of new pipelines, which will be done in the third quarter. Well planning, engineering, fabrication, and procurement activities are also progressing according to plan. At Hanz, we have already drilled a shallow gas pilot, and we're now doing detailed engineering. We are focusing on early placement of procurement orders to secure capacity and prices. Development concept for Hanz includes an innovative solution for water injection, which actually saves us one injector well. The Christmas tree is actually recycled from the abandoned Jette field. In total, this contributes to low breakeven. Combined with power from shore, this also makes Hanz one of the greenest project on the Norwegian continental shelf. To me, this is standardization and reuse in practical terms.
All in all, I am happy to report that all our projects in execution are progressing according to plan and cost. Equally important are all the early phase project, which is where we have not submitted a PDO, which we intend to bring into execution mode over the next quarters. We do have some truly transformative projects in the pipeline, including, of course, NOAKA and the Valhall NCP King Lear. Both these projects, as well as the Skarv Satellites, Trell and Trine, and Lille Prinsen, remain on track to submit PDO by the end of the year and thus be covered by the temporary tax regime. We expect all these projects to meet our investment criteria of $30 breakevens, and they will also contribute to further reducing our emissions intensity. We remain laser focused on bringing these projects across the finishing line.
At the same time, we're not blind to the things that are happening in the world around us. Rising inflation and value and supply chain issues have been key global topics in a post-pandemic world. With Russia's recent invasion of Ukraine, this has further accelerated and complicated this issue. This, of course, begs the question, what consequences for cost and schedule on our projects will this have? Let me add some color on how we're working to make sure that our projects are delivered on time and on budget and with high quality, and with the high quality demand we have on all our projects. First of all, we have been working systematically over many years to improve our project execution process and supply chain efficiency. The most important tool, if you want, is the alliance model.
This model brings together Aker BP and our key suppliers in one team with common goals and shared incentives. The model involves full transparency on cost and capacity, which enables better planning and allow us to structure the activities in our project portfolio in the most optimal way. The alliance model does not shield us completely from the inflation and the inflationary forces, but it certainly provide us with much more visibility and control than the alternative. We're also able to tap into the global supplier within our alliance partners. We will be executing many project in parallel, and we have therefore established a cross-functional team to manage this, let's call it project portfolio. The team will support the individual project in driving synergies, standardization, risk management and mitigation, and consolidate issues and facilitate resolutions across these projects. Many have talked about standardization for a long, long time.
In Aker BP, we are executing it. Through our alliances, we have also implemented a supplier managed risk program where the structure is to ensure that we have a good company overview of the key risks and are able to respond quickly with mitigating actions. The alliance models allow bad news to travel fast and allow us quickly to respond to upcoming issues. We have also strengthened our procurement strategy, and instead of doing procurement separately for each project, we have established a common organization to consolidate the purchases for bulk and materials across all projects. The goal is, of course, to ensure a coordinated go-to-market strategy and optimal utilization of available supplier capacity. Of course, we seek to place our orders as early as possible, and sometimes even earlier than a PDO approval. The goal is to ensure competitive terms and timely high-quality deliveries.
Again, the alliance models give us visibility, availability, and communication with the key suppliers. One such example is the Trell and Trine project where the pre-investment program was recently approved by authorities. Here, we have already secured vessel and materials for the planned pipeline campaign in 2023, which also enable us to drill Trell and Trine wells in a direct continuation of the Kobra East and Gekko drilling campaign in the same area. In summary, we are closely monitoring our supply chain while taking actions to ensure the robustness of our project, and I'm confident that we, together with our alliance partners, will be able to deliver. Now let's move to the financial review, which will be presented by our CFO, which is still David Tønne. The floor is yours.
Thank you, Karl, and good morning, everyone. It is truly a pleasure to present Aker BP's first quarter results with record high revenues and cash flow generation. As mentioned, production was stable quarter-over-quarter, but with an increased share of gas. The price environment further improved with realized liquid prices increasing almost 30%. Free cash flow was $1.1 billion in the quarter, an increase of 50% from the fourth quarter. Our net debt ended the quarter below $1 billion, supported by a very strong cash position of $2.8 billion. This cash will soon be put to use to pay the $2.2 billion cash consideration for the acquisition of Lundin's oil and gas business at closing, now expected end of June. The first quarterly dividend payment of $0.475 per share was paid in the first quarter.
This is up 40% from the dividend level last year. The next dividend payment is scheduled for the eleventh of May, and the current plan is to pay a total of $1.90 per share in 2022. If we then move on to take a look at our revenues and sales figures. With stable production and increasing prices, we report a record high total income of $2.3 billion in the quarter, a 24% increase quarter-on-quarter. Net production was 208,000 barrels of oil equivalents per day, and as we overlifted 8,000 barrels, this left sold volumes at 216,000 barrels of oil equivalents per day. The realized crude price was roughly $104 per barrel. The price was positively impacted by strong differentials across our crude qualities.
Adjusting for NGL, our average liquids price was just shy of $101 per barrel, up 28% from the fourth quarter. The average realized price for natural gas was $171 per barrel of oil equivalents. Close to the average realized price in the fourth quarter last year, but it is worth noting that there has been an extreme volatility in the gas prices the last few months. Combined, this gave us a realized average hydrocarbon price of $115.5 per barrel of oil equivalents in the first quarter, up 20% quarter-on-quarter. We continue to see a strong contribution from gas in our portfolio, now representing over 30% of revenues. Skarv is the biggest gas producer in our portfolio with 55% of our gas production.
As Karl has already covered in the operational update, we have now initiated the gas blowdown, which in short means that we are producing more gas out of the reservoir and reducing gas injection. This has several benefits. First of all, it makes sense from an overall reservoir management perspective. It provides additional gas export to Europe in a time when the market is in distress and desperately needs more reliable energy. It makes sense financially given the current relative price between gas versus oil. Roughly 90% of our gas is sold on contracts that are linked to spot day ahead, and we have the option to further increase this to almost 100% by October this year.
During the quarter, we also decided to lock in the price for a small part of our 2022 gas production when the prices spiked in March. Since then, prices has come somewhat down, and as a consequence, we have booked an unrealized gain of almost $40 million on these derivatives in the quarter. Over the coming years, we expect Aker BP's gas production to increase as several of our large development projects have a significant share of gas. Now, let's shift focus from revenues and sales over to capital spend and cost. Although we are in a very strong price environment, we continue in Aker BP to focus on capital discipline and cost awareness. Total spend across key cost categories, capital investments, exploration, abandonment, and production costs are down roughly 20% quarter-over-quarter.
The main driver for the reduction of almost $90 million in CapEx quarter-on-quarter is less investments on Alvheim, as we have completed the drilling of the Kameleon Infill West well. In exploration expenses, we had a reduction of almost $27 million in field evaluation costs. This cost category continues to decrease as more and more of our early-phase projects pass concept select and move into the phase where these costs are instead capitalized. On production cost, we had an increase of $26 million quarter-on-quarter, where the key drivers were continued high well maintenance activity on Valhall, an increase in environmental taxes, and last but not least, higher power cost on electrified fields, which of course is correlated to the high gas prices in Europe, positively impacting our revenues.
Although the increase in production cost in absolute dollar terms is not substantial compared to the changes in other items, the increase impacts the cost per barrel produced metric quite significantly since production volumes are stable. As seen on this slide, on a per barrel basis, production cost amounted to $11.6 per barrel in the first quarter. This is, of course, higher than the guided $10 per barrel average for the full year. However, in the second half of the year, we do expect cost per barrel to trend down as planned well maintenance work will be lower and production ramps up on Hod and Johan Sverdrup. With this as a backdrop, I will move on to take a quick look at the full P&L for the quarter.
When we subtract production cost of $220 million and other operating expenses of $7 million from total income, we get to an EBITDA of $2,064 million, up 26%. Exploration expenses amounted to $58 million, of which $39 million was dry well costs, mainly related to the Grefsenkollen exploration well. Depreciation was $231 million, or $12.3 per barrel. Net financial income was $61 million and included a gain of $99 million related to the sale of our shares in Cognite, as Karl has covered previously. Profit before tax ended at $1.8 billion, up 51%. Tax expenses amounted to $1.3 billion, which means an effective tax rate for the quarter of approximately 71%.
Consequently, net profit ended at $537 million, or $1.49 per share, up 47% quarter-over-quarter. In addition to the record high revenues, we also had record high cash flow generation in the quarter. Breaking that down, you can see that operating cash flow after working capital and taxes ended at $1,375 million in the quarter. The first quarter was impacted by a working capital adjustment of roughly $266 million. The key driver was increased value of receivables related to oil sales late in the quarter, which again, is more or less a direct consequence of the significant price increases. Taxes paid in the quarter were $388 million, in line with previous guidance. Investment activities, excluding payments on lease debt, amounted to $400 million.
In addition, we have a positive contribution of $118 million in cash inflows related to the sale of our shares in Cognite. Free cash flow ended at $1.1 billion in the first quarter or $3 per share. We paid a dividend in the quarter of $171 million, equal to $0.475 per share. Interest paid, payments on lease debt and other finance items were $77 million. We ended the quarter with a cash balance of $2.8 billion, an increase of $845 million from the fourth quarter. In addition to the strong increase in cash on the balance sheet, as always, I would like to highlight a few other things.
Property, plant, and equipment increased by $281 million, where $492 million was additions, and we had $211 million in depreciation. Receivables and other assets increased by $296 million. The increase is mainly due to receivables related to oil sales accruals, and this is the main driver for the increase in working capital that I just mentioned. On the right-hand side of the balance sheet, the main changes are related to an increase in tax payables of $760 million, and an increase in equity of $366 million. The latter, of course, is the profit for the period minus the dividends distributed. Relentless work over many years has put Aker BP in a strong position with a portfolio of quality assets benefiting from low cost and low carbon that then generates high cash flows.
These cash flows have enabled us to build a financial flexibility and positions us to invest in our portfolio of profitable growth projects in a supportive fiscal regime, while we in parallel return significant value back to our shareholders. Through the cycle, our investments and financing costs are expected to be covered at a $30 oil price, and the rest is value that will be returned to our shareholders over time. To me, it's the combination of a strong technical team, a real drive to reshape the industry through, for example, digital and the alliance model, and last but not least, the ability to execute transformational M&A, that are the three things that really have set the company apart and positioned Aker BP as one of, if not the E&P company of the future.
On the latter point of transformational M&A, the acquisition of Lundin Energy's oil and gas business is now planned to close on June 30. Financially, I believe we could not be better prepared. Supported by a very constructive price environment, we have continued to deleverage with a net debt ending the quarter at less than $1 billion and with no debt maturing before 2025. Our liquidity position is very strong, and with over $2.8 billion in cash, we actually now project to have the capacity to fund both Q2 dividends, taxes, and the cash consideration to Lundin of $2.2 billion without issuing any new debt. The rating agencies have also taken note of this, and on April 8, S&P upgraded Aker BP to BBB with a stable outlook.
The balance sheet of Aker BP is constructed to withstand the volatility of the commodity markets and at the same time allow us to seize both organic and inorganic opportunities when they arise. While we do this, we will return the value we create back to our shareholders. According to our 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 sustainable growing dividend. For 2022, the board of directors has proposed to pay a cash dividend of $1.90 per share. This is up 40% from 2021 on a per share basis, and the first installment was paid already back in February, and the next is due in May.
In addition to growing distribution sustainably over time, our dividend policy also opens up for extraordinary distributions in the form of either extraordinary cash dividends or buybacks if oil and gas prices are sustained above $65 over time. Now, before I leave the word back to you, Karl, to conclude, I will share some reflections on the financial guidance for 2022 in the context of the Q1 results. Please note that this guidance is for Aker BP as is and does not include any effects of the Lundin acquisition. In February, we guided production between 210,000 and 220,000 barrels of oil equivalents per day for 2022. In the first quarter, we produced 208, which is close to the lower end of the range.
This is in line with our communication on production phasing when the 2022 guidance was announced in February. As also communicated in February, we have a month of turnarounds on both Johan Sverdrup and Valhall in June that likely brings total production for the first half of the year slightly below 200,000 barrels of oil equivalents per day. In the third quarter, we expect a further ramp-up of production on Valhall and Hod, and in the fourth quarter, we expect Johan Sverdrup Phase 2 to come on stream. Guidance for the full year therefore remains unchanged at 210,000-220,000 barrels per day. We have guided on an average production cost of around $10 per barrel for 2022.
First quarter production costs were 11.6, and due to the shape of the production profile, it is expected to have higher than average cost per barrel in the first half of the year. In the second half, we expect production costs to trend down, and we maintain the guidance of around $10 per barrel on average for the year. Capital investments was guided at around $1.6 billion for the full year. Roughly 40% is planned spent in the Valhall area, 20% in the Alvheim area, and 20% on NOAKA. In the first quarter, we spent slightly below average, but this is due to natural phasing of the activities and the guidance is kept as is.
On exploration, we have an ambitious program in 2022 with a total of 13 wells to be drilled, and we expect to spend roughly $400 million pre-tax. The program progressed according to schedule in the first quarter, and we make no changes to the guiding. Lastly, we expect to spend roughly $100 million on decommissioning in 2022, down 50% from 2021. Most of the spend is planned in the summer months with removal of old facilities at Valhall, and we make no changes to the guiding. Now, that concludes my presentation, and I will leave the word back to you, Karl, for some concluding remarks. Thank you.
Thank you, David. I'm actually quite sad we don't have video now because you would have seen a very happy CFO indeed. Now, let me round off the presentation with a few words on our priorities ahead. First of all, and the first priority, and probably goes without saying, but I'll say it nevertheless. Safe and efficient operations is the key to convert resources to cash flow with high reliability and high valuation. Secondly, we are already among the global leaders in our industry when it comes to low CO2 emissions, and we want to maintain this leadership position. We will therefore continue to change emissions both inside our own operations and upstream in our value chain.
We will make sure that all new field developments are designed to minimize the CO2 footprint, and we are also working on plans, sorry, to eliminate the residual emissions through a net zero, and be a net zero company by 2030. Thirdly, we are extremely serious about our digital transformation. Through our collaboration with partners like Cognite and Aize and others, we are targeting real transformation of the way we run an E&P business. The number one priority right now is the work we're doing on digital project execution. Which brings me to our next point, number four, project execution. Let me reiterate. In the midst of significant turbulence in the markets, all our projects in execution and early phase are on plan.
These projects will contribute with substantial, robust growth in the coming periods, and we continue to work relentlessly with our alliance partners towards delivery of these projects. Last but not least, we are finalizing the merger with Lundin and plan to close towards the end of the current quarter. With that, we have come to the end of the presentation, and we'll now take questions. Thank you.
Ladies and gentlemen, if you would like to ask a question, please signal by pressing star one on your telephone keypad. If you are using a speakerphone, please make sure your mute function is turned on to allow your signal to reach our equipment. A voice prompt on the phone line will indicate when your line is open. We will now take our first question from.
Thanks, Teodor. It was hard to understand your name initially, but thanks. You're very clear. Skarv blowdown. The way we think about this is that the impact on the oil reserves are relatively modest, and certainly less than, let's say, five or six million barrels, which is inside the uncertainty of the remaining reserve range. This is one of the reasons we believe that this is a timely response when it comes to converting injection to production. And of course, this blowdown is new to us. We have just recently initiated it. I think you can look at this from a 2022 perspective in the range of 2.5-3 BCM increase in gas production, on a gross basis.
Then we'll come back with updated estimates going forward, and that will, of course, be included our guidance. Then when it comes to the ramp-up of Johan Sverdrup, as I said, we are very early in the drilling phase and started that in January. We expect installation and then production increase in, let's say, start up in fourth quarter. We expect a relatively rapid ramp-up until we meet the new plateau rate. I'm not going to speculate to the exact date that will occur, but, as I said, we expect a relatively rapid ramp-up. Then cost inflation, and this is a little bit more of a complicated issue. Cost inflation in itself is, of course, important, but most of the cost inflation that we're seeing now is impacting raw materials.
On an average basis, you could think about raw materials as contributing roughly. I would say 15%, but in the range of 10%-20% on a project, depending on nature, of course. That means that even with a tripling of steel prices, you only will see a gross cost increase of about 5% on a project or major top-side project. Some see a bit less, which will be, I don't know, somewhere in the range $0.20-$0.25 on the break-even. The big issue is not necessarily cost inflation. It's availability, quality and timely delivery of all the goods and necessary services that we need to develop our projects. I figure the crucial point here is actually time.
We spent significant amount of energy, which I also tried to underline in my statement to make this value chain robust and early. We're about 6-12 months earlier than we would have been on a normal project execution. With the alliance model, this actually gives us high visibility, what we call an open book transparency, and a good idea of where the bottlenecks are, and we're working to mitigate all of those. Right now, I don't see any bottlenecks that will hinder the project execution.
Okay. Thank you. That's useful. Just to clarify, the 2-3 BCM gross you talked about on Skarv, is that a 2023 effect?
We started in April, so it's starting, of course, in 2022 and then continuing in 2023. I'm guessing that the gas production will be pretty flat actually from 2022 to 2023, so I don't think you'll be far off.
Okay. Thank you.
We will now take the next question from Chris Wheaton from Stifel. Your line is open. Please go ahead.
Thanks so much. Good morning, guys, and well done on another safe and extremely profitable quarter. Well done. A number of questions, if I may. Can we pick up on the previous question about Skarv? Are you able to talk about the changes you've made to your longer-term gas price assumptions, which I assume is what's driving your recalculation of the NAV of the field, and therefore your decision to enter blowdown now rather than wait a couple of years, as I think was your original intention? Secondly, two questions on the balance sheet, if I may. What would trigger additional payouts to shareholders given how strong your liquidity position is? As you've said, David, great balance sheet to have.
Also, you know, I know that Vår Energi has just increased its dividend by another $200 million or so. Last question, again to David on the tax. You talked at the last quarterly results about basically $2.3 billion of tax payable over the rest of 2022, i.e., 2Q, 3Q, 4Q. Is that still valid at current prices? Thank you.
Let me talk a little bit more about the gas blowdown, and then I'll hand you over to David to talk about the balance sheet and tax issues. When we think about the blowdown, and you're of course correct, we had in our prognosis to push back gas blowdown a couple of years, but of course, depending a bit on the effect of the gas injection. Right now, this is driven essentially by maximization of resources. At that point in time, the gas prices was, I don't know, 10%-12% of the oil prices in pro rata terms. Now, of course, we are seeing significantly different gas prices.
While I would say that the gas blowdown economics were pretty much on balance at the previous, let's say, estimation of gas prices, we're hugely in the plus now. I'm not going to comment specifically on our assumptions on long-term gas prices, but I'll say this, the value distribution or the value change both relating to increase the capacity of gas production across Skarv and of course, increased gas prices, essentially makes this a very simple decision.
Okay. On the dividends, what will trigger additional dividends?
I guess the starting point, Chris, is of course our dividend policy and how we view this in the longer term. Our ambition is to pay a sustainable growing dividend over time, and we increased our dividends with 40% at the announcement back in December of the Lundin's transaction for 2022 compared to the 2021 level. Our policy opens up for additional extraordinary distributions if oil prices are sustained above $65 per barrel for a sustained period. We've now one quarter into 2022, and I think it's a bit too early to start talking about extraordinary distributions. But it is an option that's part of our policy.
In terms of taxes, we didn't include a slide in the pack this quarter on sort of cash tax payments, which I guess is an indication that the estimates that we provided at our fourth quarter presentation is still valid. We still expect to pay $800 million in the second quarter, which is for the fiscal year 2021. The scenario analysis that's provided for the third quarter 2022 and the fourth quarter 2022 is still valid on an Aker BP standalone basis. In the second half of the year, we will be a much larger company combined with Lundin, and we will provide new estimates once we have that ready.
No. That's understood on the parameters. Brilliant. Thank you very much indeed there, guys. Thank you.
Thank you. We will take the next question from Yoann from Société Générale. Your line is open. Please go ahead.
Good morning. Thank you for the presentation. Just a few questions, if I may. First, looking at the Alvheim and Valhall production ops, we are seeing quite a gap in terms of production efficiency rate. I'm just wondering if you could provide some color basically on your expectation for the trend for the rest of the year. Can Alvheim really maintain such a high efficiency rate? And what about Valhall? Do you expect efficiency to recover back above 90% from 2Q onward? Maybe if you can comment on this, I appreciate it might not be possible. But I believe you have estimated the cost for the merger with Lundin Energy E&P portfolio to be close to $145.5 million on a pre-tax basis.
Is this estimate still valid as we speak? I will like to know how much basically of this cost has been incurred so far. Maybe just to come back onto this gas blowdown that of course I appreciate you have already provided some color on this, but any chance you could give us a bit more granularity in terms of gas-to-oil ratio to expect in the midterm for Skarv overall?
Okay, thank you. Let me comment on the production efficiency issues and the two different issues. On Alvheim, they are related to equipment that have been changed out in the quarter. That is a planned activity, which we assume will not be impacting the production efficiency on Alvheim going forward. When it comes to Valhall, this is related to well intervention work, which is also commented when we talked about the OpEx, which is where we're going into the wells, stimulating these wells. As we're stimulating these wells, we need to shut down this and other close by wells. This work will continue throughout the spring and into the summer.
Of course, the effect of this work is that while the production efficiency is slightly lower, total production will go up as we're putting more wells on stream. That's the explanation to this, and then we'll move onward to Hod, and this activity at Valhall will cease over the summer. When it comes to the merger closing cost, David.
Yeah. The merger cost estimate close to $145 million that you referred to, Yoann, is still valid. It's a combination of both companies, and it's directly linked to sort of transaction costs triggered at closing. Most of that is not incurred yet.
When it comes to the gas blowdown, as I said, there is a series of reservoir segments at Skarv. This relates to a couple of the segments. Of course, as you're moving into a blowdown phase, you're moving more into a pure gas production over time. We do not intend to provide granularity on gas-oil ratios across the different reservoirs at Skarv.
That's very clear. Thank you.
Thank you. We will now take the next question from James Thompson from JP Morgan.
Great. Good morning, gentlemen. Thank you very much for the presentation. Also I'd like to say congratulations, a very strong set of results. Karl, we've had a number of conversations with companies and you've obviously flagged it today in terms of inflationary factors and trying to keep that under control. You know, post the Lundin deal, you're gonna have very high equity across a number of your assets. Obviously, you've got some very large CapEx programs. I appreciate that you've been successful, you know, at buying assets on the NCS over the years. I just wondered whether you had any kind of ambition here to actually try to trim some of your equity.
I appreciate there's no real balance sheet need to do it, but just in terms of risk profile, you know, taking advantage of, you know, the strong commodity price backdrop and probably higher industry appetite for assets here. I mean, you know, could you give us an indication about whether that's something you're thinking about and maybe, you know, sort of in many ways de-risking maybe part of the portfolio, particularly where you've got very, very high asset concentration?
Yeah. Well, we never really comment on what we intend to do either on acquisition or on sales. As you probably have understood, as a result of the Lundin transaction, we do end up with 100% equity in quite a few of these licenses. That is a situation we need to resolve, and which will be resolved. Apart from that, I'm not really going to comment on what other portfolio dispositions we may or may not consider. I will say this, that there is no strategic link, at least in my head, and not to knock Aker BP strategy, between the inflation and, let's say, a balance of equity across the portfolio.
Okay. That's very helpful. Okay, just in terms of technical, I mean, I have a number of questions over the last few days. When it comes to kind of two key reporting, will you report Lundin as well, you know, assuming the transaction closes on the thirtieth of June? You know, do you have an update about when you expect to kind of give us that forward guidance on the combined company?
Yeah. You can do that, David.
Yeah. With regards to second quarter reporting, since closing is expected on the 30th of June, and then if we achieve that, we will incorporate Lundin's balance sheet into our accounts, but not the P&L for the quarter. When it comes to sort of more broader strategy update post-closing, that will be some time, most likely, in the second half of the year, but we'll have to come back to a more specific date.
Okay. Thank you. Just final one for me. You know, I'd appreciate a number of questions about Skarv and the blowdown process. Is there any kind of material CapEx associated with it in terms of, you know, debottlenecking the facilities and things like that we should be aware of?
We actually did that last year. You might recall that we talked about the upgrade of the Skarv gas treatment capacity over a couple of quarters in 2021. The capacity upgrade, including drying, gas treatment, et cetera, is already done. We actually did that as a part of the Ærfugl phase in and production startup. We're utilizing the same capacity, which means that there are no additional CapEx accrued.
And then, uh, just to-
Very good. Very good.
Sorry, James. Just to add, just for information, for those of you who are potentially dialing in from the US, we do have a small presentation on our web pages behind the disclaimer wall, which is providing some input on the combined company. If you haven't seen that already. Hopefully that satisfies some of the needs to get a better view of the full combined entity in the interim while you wait for the capital markets day.
Thanks, David. Thanks, Karl. Well done. Good. Good statement. Pass it over.
Thank you. We'll now take our next question from Mark Wilson from Jefferies. Your line is open. Please go ahead.
Hi. Good morning, gentlemen. My question is regarding the sanctioning of projects by the end of the year. A huge amount of work has been done, obviously, to get to this stage. You spoke, Karl, to the amount of work you've got going on to balance the risk of execution of these projects. The 700 million barrels of reserves for projects, Lille Prinsen, NOAKA, Skarv, and Valhall. Could you see any risk of any of those slipping beyond the end of the year? Maybe to quantify that as a second part, what would you consider to be the dollar per barrel NPV impact of a project that didn't sanction by year-end 20 and slipped into the following year? Thank you.
Excellent question, Mark, and I'm really happy to answer. So this is what we're probably, at least I am spending about 70-80% of my time on. So in terms of PDO and PDO deliverable, right now, I don't actually see any risk on the PDO slipping. Quite the contrary, we are in a very good position when it comes to the FEED engineering, procurement work, and all the other necessary work to make sure that we're in a position to deliver PDOs. I would actually go as far as to say that some of the FEED work that we're now doing is significantly more robust and more mature than what I've seen the startup of detailed engineering or projects in the past.
I'm actually quite confident that the PDOs will be delivered on time. What we're spending time on is to make sure that as we are delivering the PDO and sanctioning this project, we have as robust project execution strategy as we possibly can. That of course includes procurement, availability of resources, raw material, goods, services, et cetera. As I stated, we are working with our alliance partners to do that. This work is a lot more mature now than I've seen in the past. We're probably 6-8 to 12 months ahead on where we used to be if this had been a conventional project development portfolio. PDOs, I don't think they will slip.
When it comes to the effect, the net barrel effect, that depends on the projects. If you think about this in a typical $10 per barrel range, if you come outside the temporary tax system and then slightly offset with the new tax system that's coming on stream. If you calculate a net across the portfolio in the range of $5-$10, that will of course depend on size of CapEx and time between CapEx exposure and production and such issues. Remember, we're doing NPV 10, right? Time is actually quite critical here.
Got it. Okay. Thank you. Very clear. Maybe just as a related point, where do we stand with the new tax regime being implemented in parliament or in government?
Yeah.
David loves to talk about tax. I'll leave that to him.
Yeah. The new government came out with a white paper just very recently, which is very much aligned with the original proposal from the former government. That is expected to go through parliament sometime before summer. As mentioned, it's very similar to what was originally proposed. As mentioned, we are supportive of that proposal and expect it to go through.
Okay. Thank you very much. Good luck with those PDOs and the completion and operations. I'll hand it over.
Thank you.
Thank you. We will now take the last question from Anish Kapadia from Palliser Advisors. Your line is open. Please go ahead.
Good morning. I had a couple of questions. Firstly, just following up on the current environment, a high oil price environment and inflationary pressures. Now I know you've talked a lot about mitigating of the cost inflation, but I think one of the things that we've seen historically in high oil price cycles is that companies have underestimated the impact in terms of production efficiency falling, availability of services, lead times increasing. So just wondering, as well as the kinda cost inflation impacts, how much of that have you factored in to your production guidance and in terms of your CapEx plans over the course of this year and going forward. And then the second question is relating to shareholder returns to some extent.
Post the Lundin deal, you're gonna have a number of shareholders that are tied up, locked up, and then coming off lock up over the following period. Is there any intention to maybe look at share buybacks or a tender offer, with a view to, you know, absorbing some of that potential equity that could come to market? Thank you.
Yeah. Again, really good question, Anish. So when it comes to production efficiency and let's say the quality impact of cost inflation, which is what you're essentially talking about. This is, of course, I would say, an issue of concern to just about everybody in the industry. I do believe that there are, let's say, quality issues in parts of the vendor chain at the moment. Some of these quality issues have had impact on our production and also, let's call it quality of operations, which have had less performance than we'd ideally have desired. Our response to this is of course, through the alliance to put task forces together to improve quality, improve checklist, et cetera, et cetera, which I think is a quite conventional industry approach.
What I would say is the fact that we do have these alliances in place allows us to work much more openly with our vendors, which means that we much more rapidly than I'm used to is getting to the root cause of these quality incidents and are implementing compensating measures. To me, you're also talking about probably the most important topic when it comes to these projects. While we're not immune to inflationary pressures, I think the key issue for us is to make sure that what is delivered is delivered with the right quality and the right time and to avoid rework and other, let's say, complications in the execution.
Right now, I feel actually quite confident that through the use of these alliances, we are putting in place a much more robust process and organization than normally would have been in place. When it comes to whether or not we've factored that into the guidance. The guidance for 2022 and also the guidance onwards includes our best estimates, and which of course will be impacted by our evaluations on availability, quality, interventions, drilling and so on. We have, of course, taken some of these issues into account, while others we plan to rectify. Now, your question on shareholder return. I think I'll restrain myself to say that we'll come back with our view on this at the time when we feel that this is yeah sufficiently processed and sufficiently discussed.
Of course, ultimately, shareholder return is a matter for the board.
What I can add to that is that buybacks is part of the dividend policy already today. As mentioned, and to reiterate myself, sustainable growing dividends, that's the ambition. We do have a policy which opens up for extraordinary distributions, both in terms of cash distributions, but also buybacks if oil prices are sustained above $65 per barrel.
In short, we'll come back to this issue in a timely manner.
Great. Thanks very much.
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.
Kjetil, would you like to close?
Yes. Thank you, Karl. Thank you, David. Thank you everyone who have asked questions and participated on this call. If there are any follow-up questions, please contact us at the Investor Relations department in Aker BP. We can be reached on email, ir@akerbp.com. With that, we wish you all a continued great day and see you again in three months time.
Thank you, guys.
Thank you.