Good morning, everyone, welcome to this presentation of Aker BP's first quarter results for 2023. Our CFO, David Tønne, and I will hopefully provide some insight into our performance and outlook, the presentation is, as normal, followed by a Q&A session. It is a real pleasure to report yet another strong quarter for Aker BP. We produced more oil and gas than ever at low cost and the lowest emission intensity in the oil and gas industry. To me, this is a result of having world-class assets and a dedicated team with a culture for operational excellence and continuous improvement. I am also extremely pleased to report that our field developments are on track. We are off to a good start for the new project that we launched in December, where procurement and detail engineering are progressing as planned. With the strong performance comes strong results.
In Q1, we delivered EBITDAX of roughly $3 billion and a free cash flow of nearly $1 billion, almost 3x the amount we paid in dividends. We reiterate the full year guidance that we provided last quarter. Let me start with a few words on safety. It is, of course, a fundamental goal for us to keep our people safe. In the first quarter, we had zero serious incidents, and the total injury frequency continued trending downward with only two injuries recorded, both classified as moderate. Safety focus is an integrated part of our operations model, and we believe that high safety goes hand in hand with high operational efficiency in general. When we look at the overall production efficiency, which is our way of measuring the capacity utilization across our producing assets, it was 93% in Q1.
This is down from 95% in Q4 due to an unplanned shutdown at Edvard Grieg and Ivar Aasen, but still strong in an industrial context. The high efficiency also translate into your low unit cost. In Q1, we managed to keep the production cost per bbl at $7.2, in line with strong performance from the previous two quarters, and of course, well within the guided range of $7-$8 for the full year. High production efficiency obviously has a positive impact on production. We are pleased to report yet another production record for Aker BP with an average production of 453,000 bbl per day in Q1.
The increase was driven by Johan Sverdrup phase II, which had its first full quarter in operation and partly offset by the outage on Edvard Grieg and Ivar Aasen that I just mentioned. At Sverdrup, we are now in a phase of testing and debottlenecking the phase II facilities to maximize the processing capacity. I'm optimistic with regards to achieving the level of gross 755,000 bbl of oil per day that we have previously talked about. Although we still don't know the exact timing of when this debottlenecking is completed, we remain comfortable with our 2023 production guidance of 430,000-460,000 bbl of oil equivalents per day. On the exploration side, we have completed five wells so far this year and made two smaller discoveries.
We are currently drilling two wells, Carmen, operated by Wellesley, and the Aker BP-operated East Frigg, where we use the Scarabeo 8 rig. This well is targeting additional resources in the Yggdrasil area. The next well on our schedule is the Rondeslotter well, which is a classic high risk, high reward opportunity. This is actually an appraisal of a discovery from 2003 called Elida, which encountered good quality oil in a reservoir with very low permeability and hence low producibility. The purpose of the new well is to find out if the reservoir properties are better at the apex of the structure, and in the most optimistic scenario, which of course have low probability, this could unlock several hundred million barrels of oil.
The exploration program for the rest of the year is unchanged since last quarter. As always, the timing of each well is indicative and subject to rig arrival. It's not unlikely that some of the Q4 wells might be pushed into next year. Q1 was a record quarter, not only on production, but also on greenhouse gas emissions with 2.9 kg of CO2 equivalents per barrel. The main reason for this good result is that an increased share of production came from fields that are powered from shore, the ramp-up of Sverdrup phase II, and the electrification of Edvard Grieg, which was initiated late in Q4. In the previous quarters, we have reported CO2 emissions only, which represent more than 90% of our total greenhouse gas emissions.
As from this quarter, however, we are including all greenhouse gases, including methane and N2O, which gives a more precise picture of our footprint. With this strong performance, we are fortifying our position as a global industry leader within emission intensity, as we showed last quarter. This chart is so good that it deserves to be shown again. Compared to the 300 largest upstream oil and gas companies globally, Aker BP is ranked number one on emission intensity per barrel produced. We will, however, not relax in our effort when it comes to our emissions. Let me take this opportunity to repeat the main points of our decarbonization strategy.
We will continue to reduce emissions wherever it makes economic sense. From 2030, we will offset our remaining emissions through reforestation or other carbon removal projects. With the reforestation initiatives we got through the Lundin transaction, we are already roughly half of this volume covered. Finally, from 2040, we expect all our fields to be powered from shore and remaining emissions from our production will be minimal. In Q1, we also announced that Aker BP was awarded a license for CO2 storage on a Norwegian continental shelf in partnership with OMV. We expect CCS to play a role in a transition to a low energy future. Norway has a significant potential for carbon storage.
As a leading operator, we are well-positioned to take an active role in this area, and we see this as a potential natural extension of the EMP value chain.
Thank you, Karl. Good morning to all of you. Although the first quarter of 2023 was characterized by continued external volatility and declining commodity prices, Aker BP executed on our projects according to plan. Our financial performance was strong, with almost $1 billion in free cash flow generated. Volumes sold hit a new record high of 450,000 bbl oil equivalents per day, with roughly 85% in liquids. With a reduction in commodity prices, our net income was down quarter-on-quarter and ended at $3.3 billion. Liquids were on average sold at $78 per bbl and gas at $99 per bbl of oil equivalent.
The average realized differential to Brent was also slightly down quarter-on-quarter, in particular, driven by a weaker market for Johansverd crude in the beginning of the quarter. We saw this normalizing towards the end of the period. Moving on to a few key points in the income statement. Despite a 5% increase in sold volumes, the cost of those volumes was down $23 million from the previous quarter. As we kept cost per produced barrel stable, the difference can be explained by the valuation of underlift in the different quarters. More important is the cost per produced bbl of $7.2. This is well within our guidance range of $7-$8, and is the result of a focus on cost control in an inflationary macro environment, combined with a weak Norwegian kroner and more normalized power prices.
Exploration expenses increased to $98 million, driven by high drilling activity. Depreciation and impairments were $972 million, resulting in an operating profit just shy of $2 billion for the quarter. The impairments of $373 million were mainly driven by the previously announced termination of the Troldhaugen project and by reduced short-term oil and gas forward prices, leading to an impairment of parts of the technical goodwill that was allocated to the Edvard Grieg and Ivar Aasen hub after the acquisition of Lundin. Since technical goodwill is not depreciated but must be impaired over the lifetime of the asset, we actually expect to impair technical goodwill more or less every quarter if all other assumptions remain unchanged.
As the impairment of goodwill is without deferred tax, the effective tax rate in the income statement is driven up and ended at 90% in the first quarter. Net financial expenses increased by $100 million compared to previous quarter. This was mainly caused by the strengthening of the U.S. dollar against the Norwegian kroner and the related impact on currency items, including derivatives. We posted net profit of $187 million for Q1, corresponding to $0.30 per share, up 66% quarter-on-quarter. As mentioned, the good operational performance also flowed through to a strong cash flow generation in the quarter. Operating cash flow after tax was nearly $1.7 billion, where approximately $150 million-$200 million can be attributed to positive effects from working capital changes. Cash flow to investments, including exploration and abandonment, was around $700 million.
This is slightly lower than a pro rata share of the total investments for the full year. This is as expected as the project sanctioned in December are still ramping up execution. Deducting investments from operating cash, the free cash flow was $977 million. After distributing around 1/3 in dividends and spending 1/10 on interest payments, we ended up with a positive change in cash of $523 million in the quarter. As taxes paid in Q1 were more or less the same as the current tax generated and no new financial debt was raised, the cash increase is a fairly good approximation of the actual underlying cash generation in the quarter.
Speaking about taxes, this illustration provides an overview of projected cash taxes in 2023. We paid one tax installment in Q1 as planned, while we will pay two installments in Q2, where actually one installment was paid already in early April. The tax installments for Q3 and Q4 will first be set in June. The illustration provides a few scenarios for what they might be based on various oil price scenarios. These scenarios are the same as we presented at the fourth quarter presentation in February, only that we have adjusted the gas prices used in all scenarios from $25 per MMBtu to $15. Our financial position remains strong, which of course is important given our investment program. The total available liquidity increased to $6.7 billion, where roughly $3.3 billion is cash and cash equivalents.
This compares well to the net after-tax CapEx exposure of approximately $4 billion of five years. Financial debt was stable compared to the previous quarter. We added roughly $240 million of lease debt in Q1, driven by the intake of the rigs, Scarabeo 8 and Deepsea Nordkapp. The strong revenue generation and further improved financial position is also reflected in our leverage ratio, ending the quarter at 0.16 x net debt to EBITDA. On this slide, we illustrate how our key credit and liquidity metrics have developed over time. I want to reiterate our message from previous presentations. Our first capital allocation priority is safeguarding our balance sheet. This is a key component to maintaining our credit ratings, which gives necessary access to capital markets and ultimately is a foundation for further investments.
We have successfully been able to improve our financial flexibility over the years, this is a continuous effort where we in the first quarter focused on extending the maturity on parts of our undrawn revolving bank facility. Although we have a strong financial position with ample liquidity and no pressing bond maturities, we will continue to actively manage our financial risk and optimize our capital structure going forward. It's a good operational performance from a world-class asset base combined with a robust balance sheet that enables Aker BP to invest in high return projects, creating sustainable shareholder value. The value created will be distributed to our shareholders with the key principle being that dividends shall reflect the financial capacity through the cycle.
As we have communicated previously, for 2023, we plan to pay a cash dividend of $2.2 per share, up 10% from 2022. The dividend is to be paid in four quarterly installments, with one installment paid in Q1. The next payment is due in May. To round off my section, I would like to reiterate our full-year guidance on key parameters. The main message is that we are progressing in accordance with plan. We make no changes to the guidance we gave back in February.
For production, we maintain a range of 430,000-460,000 bbl of oil equivalents per day. We expect volumes to be in the high end of the range in Q2 as Johan Sverdrup phase II is further ramping up, towards the low end in Q3 impacted by planned summer maintenance. Production cost for the quarter was $7.2 per bbl. Our estimate for the full year is still between $7 and $8 as we continue to see pressure and volatility in key drivers, including general inflation, fluctuating electricity prices, and foreign exchange rates. On CapEx, we still expect to spend between $3 billion and $3.5 billion pre-tax in 2023. We have chosen for now to keep the CapEx guiding quite broad for the rest of the year.
The reason is that although we have taken final investment decisions and moved into execution on our project portfolio, there is still quite some uncertainty regarding the in-year and between the year facing of the spend, and this is being further matured throughout the year. Lastly, on both exploration and abandonment spend, we make no adjustments to the full-year estimates of $400 million-$500 million and $100 million-$200 million pre-tax respectively.
Thank you, David. Last quarter, we gave an overview of our large project portfolio that we will put into production over the coming years with our latest estimate for resources, CapEx, and breakevens. My key message today is that we are off to a good start and that we are on track. We look forward to delivering these great projects, which will unlock around 770 MMbpd of oil equivalents. Between now and 2028, this will require investments of roughly $20 billion pre-tax, which corresponds to roughly $3 billion after tax. Let me put this into context. The projects play an important role in the longer-term development of the company.
Along with measures to increase efficiency and recovery, this project will enable Aker BP's daily production to grow to around 525,000 bbl in 2028. In addition, the project would contribute to extending life of existing production and enable future growth opportunities. The project economics is very robust as we calculate the project portfolio break-even of $35-$40 per bbl. To further illustrate the attractiveness of these investments, we estimate an IRR of roughly 25% and an average payback time of one-two years at an oil price of $65 per bbl for the portfolio. The project plans are a manifestation of our ambition to create the oil and gas company of the future with low cost, low emissions, profitable growth and attractive returns. I am extremely pleased that we have been able to mature all these opportunities into projects.
Going forward, the job will be to execute the project on time and on cost. Delivering this project is obviously a very important value driver for Aker BP. This is why we have invested a lot of time and effort into developing a project execution model that drives quality and efficiency. The cornerstone of this is our alliance model, which is a platform for building strong relations and seamless cooperation with our main suppliers based on shared goals and shared incentives. We have been testing and developing this concept for many years, and we know it works, having delivered 16 projects on time and on budget. Of course, our ambitions going forward are nothing less.
The close collaboration with our suppliers has allowed us to plan ahead and reserve capacity in the supply chain for our project at a much earlier stage than what is normal in the E&P industry. We are now reaping the benefits of this work. We have placed all major contracts, and we are well on the way with detail engineering, and we're working closely with vendors and sub-vendors to prepare for upcoming project activities. I am often asked if we are impacted by the inflation we observe all around us, and of course we are. However, this is already embedded in our CapEx estimates. When we last year established the cost estimates for the PDOs, we made a big effort to understand and estimate the inflationary pressure in the various parts of our supply chain.
Of course, we haven't got every detail exactly right, but the overall conclusion is that we are on track and our total CapEx estimates are unchanged. Let's zoom in to each of the main projects. I'll start with the tieback project to Alvheim, which is nearest in time. We proudly announced that Frosk commenced production in March on schedule and within budget, only 18 months after the PDO was submitted. This is a great example of what we can achieve with the alliance model, working as one team with our suppliers towards a common goal with shared incentives. At Cobra-East Gekko, or KEG for short, we are progressing very well for a project start in Q1 2024, and the Tyving project is on track for the planned startup in 2025.
These projects combined have a net resource estimate of roughly 60 MMbpd to oil to Aker BP with excellent economics and once again demonstrates how we are leveraging our assets by developing discoveries in the vicinity of existing infrastructure. Our largest project is Yggdrasil, previously named NOAKA, consisting of several discoveries in the area located between Alvheim and Oseberg. This is the next major development in Norway with a current gross volume estimate of 650 MMbpd of oil equivalents with above 400 net to Aker BP, who is the operator. Through good cooperation across licenses and operators, we are opening up a mature and prospective area in the North Sea. At Yggdrasil, we are setting new standards for how to operate the field. We plan for remotely controlled operation, unmanned production profile, platforms, new technology and data-driven decision and work processes.
We are also digitalizing the project execution with our strategic partners and suppliers. It will be developed with power from shore, minimizing the carbon footprint, and there is significant additional volume potential in the area. The Yggdrasil development is therefore designed to also serve as a hub for future potential tie-ins. The Norwegian government has presented a proposition to the Storting, recommending approval of the PDO, which we expect before the summer. The project is progressing nicely with all major contract awards and approved concessions. We are well into the detail engineering phase, and we're working closely with the partners and suppliers for construction start already this year. Production start is planned for the first half of 2027.
The second largest project is the Valhall PVP and Fenris and comprises of a new production and wellhead platform, PVP for short, to the Valhall field center and an unmanned installation at Fenris, previously called King Lear, which will be tied back some 50 kilometers to Valhall. This is a unique collaboration project on the Norwegian continental shelf, a coordinated development that will both ensure continued value creation for the Valhall area and at the same time establish a robust development solution for the Fenris discovery. We estimate total volume of 230 MMbpd of oil equivalents to be produced, of which around 190 is net to Aker BP.
Startup is planned for 2027, and the project is progressing well. In fact, the first cargos of steel to the Fenris jacket have already arrived at the yard in Radal, and steel cutting will start before the summer. One year later, the completed jacket will be installed offshore before we start the drilling campaign. Valhall is undergoing a major modernization where the oldest platforms are being removed and the PVP installation will become an integrated part of the Valhall infrastructure. The PVP and Fenris have also been designed with hub flexibility to enable future tie-ins. The total resource potential enabled by this development, which also includes the effect of life extension and new wells at Valhall, is estimated to around 500 MMbpd . The final government approval follow the same process as Yggdrasil, with expected resolution by the Storting before the summer.
In the Skarv area, we are going to develop three separate gas condensate discoveries jointly referred to as the Skarv Satellite project. Each of these developments comprises of a four-slot template and two wells, all tied back to the Skarv FPSO in the northern part of the Norwegian Sea. The activity level in the project is currently high, and we're off to a good start. We have recently concluded that the planned maintenance and modification activities at Skarv will be supported by a flotel instead of new living quarters on the FPSO. The flotel alternative offers significantly higher accommodation capacity and will allow us to accelerate the maintenance and modification activities, and potentially also have a positive impact on the overall schedule.
The total resources to be unlocked by these discoveries are estimated to approximately 120 MMbpd of oil equivalents, predominantly gas, with planned production start in 2027. The project leaves significant flexibility for future tie-ins with the recent Aker BP discoveries, Storjord and Njord as obvious candidates. Watch this space. There is more to come from the Skarv area. At Utsira High, we are working on three separate subsea tie-back projects to Edvard Grieg and Ivar Aasen, with a total volume estimate of more than 100 MMbpd of oil equivalents. Late 2021, we submitted a PDO for Hans, which is an oil and gas discovery that will be tied into the Ivar Aasen platform and a schedule for first oil in early 2024.
Last December, we submitted PDOs for Symra, a tieback to Ivar Aasen, and Solveig phase II , which will be connected to the Edvard Grieg platform. Production start is planned for 2026 and 2027 respectively. We also in December submitted a PDO for the Troldhaugen project, which was subject to the performance of an extended well test. The results of this test did not provide sufficient comfort in the project's production estimates, and we therefore decided to discontinue this project. The withdrawal opens for potential optimization of the other project, and although it's a bit early to conclude, we are looking into the opportunities to accelerate first oil dates for Symra and Solveig. Time will tell, and detail engineering is ongoing on the two projects. We're off to a really good start on our project execution together with our alliance partners.
We're making good progress with current focus on engineering, procurement, and contracts. We remain comfortable with our estimates both with regards to CapEx and schedule. Before we open for Q&A, let me quickly repeat the main messages in our Q1 report. We delivered strong operational performance in the quarter with record production, low cost, and the lowest emission intensity in the global oil and gas industry. We are pleased to report that our projects are on track, and we are laser focused on delivering this project on time and cost. The strong performance also translated into high earnings and cash flow in the quarters. As David just went through, we're also on track with regards to our 2023 guidance, which is unchanged from last quarter. We will now take a short break before we open the Q&A session.
If you want to participate in this session, please enter via the Teams link provided on the webpage. If you just want to listen in, please stay right where you are and we'll be back in a couple of minutes.
Welcome back to the question and answer session. For those of you who have joined via Teams and want to ask question, please raise your digital hand and Kjetil Bakken from our IR team will help me to ensure that we conduct this in a somewhat orderly fashion. Kjetil will also really appreciate if you turn on your cameras when it's your turn, and that will make his day and also mine. Kjetil, what is the first question?
I don't know what it is, but I know who it is. I will call on Victoria McCulloch to come with the first question. Victoria, please.
Good morning. Can you hear me okay?
Absolutely. Good morning, Victoria.
Excellent. Apologies, there's no camera at the computer I am at. Otherwise, I would definitely have it turned on. Apologies for that this morning. I wonder if you could give us a bit of an idea initially, where your current production is versus your guidance. I noted in the release, obviously, discussion of Sverdrup being worked towards 755,000 bbl a day. If you assuming at the top end of your guidance, for Q2, where are we seeing the declines that we should maybe be aware of? If I could ask another one, you talk about what the wider CapEx guidance.
Could you give us an idea of maybe some of the moving parts that we can look out for or phases, in progress that we should, that might give us an idea of where, the phasing across the years is in terms of capital spending? Thanks very much.
Okay. We can start with production. As you obviously know, the Q1 production was 153. My expectations is that we'll end up roughly in the same territory in Q2. There are some more planned maintenance in Q3. From an overall perspective, I think the 430-460, which is our full year guidance, is still our best assessment. When it comes to Sverdrup, I think the last news that we're now running at nameplate capacity, and we obviously plan to ramp up towards the 755. The exact timing of that is uncertain, but I'm assuming that we'll carry out the first test within the next couple of months. The CapEx guidance through the year, David?
As I said in my presentation, the CapEx guidance is kept quite broad for the year between $3 billion and $3.5 billion. The point of keeping it broad is that we're still in the process of ramping up and the in-year phasing and in-between year phasing is still quite uncertain. With regards to updates on this, I think the way that we will do it, we will of course provide progress in the quarterly presentations on in-year phasing. If there is material changes in the between the year phasing, we'll of course also update you on that. I think this will take a bit of time to really detail out.
Kjetil, let's move on.
Yes. The next question is from Jørgen Bruaset from Nordea. Please go ahead, Jorgen. Jorgen, you have to unmute your line. Okay. He might be away from-
Sorry. Can you hear me?
Absolutely.
Yes.
Good morning, Jørgen. We can hear you, Jørgen.
Okay. just touching a bit on both the production guidance and also on the CapEx guidance as initially asked.
Just go on.
There seems to be a big, big lag here. Maybe question on the...
We hear you at least, very well, Jørgen. Please go ahead.
Okay. Jørgen asks if we can quantify the maintenance effect in second half.
You want me to take that?
Yeah, go ahead.
Yeah. As I think detailing the maintenance effect is a bit difficult, but in terms of fields that has turnaround in the third quarter, it's in particular Alvheim. Then we also have a couple of ESD tests across the different fields. We don't give specific detail guidance on each of the fields and then the production for the specific quarter.
Okay. I think we'll move on to the next the next question, which is Vidar Skogset, Lyngvaer. Please go ahead, Vidar.
Yes. Looks like he withdrew his question. Next one is Yoann Charenton from Societe Generale. Yoann, please go ahead. We don't hear you, Yoann, so we'll move on to the next question, and then that would be Mark Wilson. Mark, I hope you are there.
We can't hear you either, Mark. It looks like we have some technical difficulties, so just please remember to unmute before speaking. We recognize that it might not be on your side, the issue is, so we'll try to figure that out.
It's Tom from AB.
Hello. Can you see me and hear me?
Yes, we perfectly can, Mark.
Um-
Thank you so much.
I'd like to ask. Okay. Well, I'll ask my question anyway in case you can't actually hear me.
Go ahead, Mark.
My question, regarding your big exploration well, the Rondeslottet, that's coming up, it says it's an appraisal of a discovery from 2003. Could you give us some details on what that discovery found and therefore what you're gonna see?
Yeah, sure. I think the issue here is the time lag from our microphones to the Teams, if you can work on that, guys. The Rondeslottet was a discovery from 2003. It was at that point in time known as Elida. We discovered quite a lot of volume, but a very tight reservoir. The well was drilled on the flank of the reservoir. At least as we'd carried out the geological studies, it seems that there might be better reservoirs as you're moving towards the apex and the southwestern part of the reservoir. The appraisal well is not really to prove in-place volumes, it's to produce producibility of this reservoir at commercial rates. That's what we're doing, and that means that there are some more...
A little bit of a different formation evaluation program than we're used to, where you usually try to prove in-place volumes. We're now trying to prove our producibility. If successful, there are several hundred million barrels existing in Rondeslottet. It's an exciting well, but of course it's a classical high-risk, high-opportunity case. It's different from most of these wells because we know the oil is there, we just try to find better geology.
All right. I think, before we take the next question, I have a suspicion that if you are watching on the stream and you are asking questions on Teams, there is a time lag...
Oh, okay. Thank you.
between those two.
Is there a flow test in that appraisal would be the follow-up question. Also some questions from investors asking about the production guidance and whether it appears more conservative than we would expect.
I don't think it was on.
I think it was on. I didn't catch that question, Mark, if you might repeat that, please. We could hear you, there was some noise on the line here. Is it an alternative to do a two-minute pause and make sure that the technology works before we continue? Is that the better way of executing?
Yes. A message to all of you who are on Teams and asking questions, you should turn off the streaming in your web browser and only follow the sound on the Teams. There is a 30 seconds approximately time lag between the two, if you are listening into the stream and asking questions on Teams, it creates these lags. Please only use Teams.
Okay. Should we move on to the next question?
Yes. I think we'll try again with Yuan from Societe Generale. Please, Yuan, go ahead.
I don't hear anything.
Okay, maybe we have fixed the problem now. Let's see if we can get the next question, Kjetil.
Yeah. I have opened the line for Johan. Johan, if you are still there, please ask your question.
Good morning, everyone. Thank you for the presentation. Hopefully you can hear me perfectly.
Absolutely. Perfect.
Sounds good. Thank you. I may have missed it, but just looking at the figures you provided, for the resources that will be developed under the temporary tax scheme. In the annual report, you referred to 700 MMbpd , which was taking into account the discontinuation of one out of 10 PDOs, and today you are referring to 770 MMbpd . Can you please tell me what I'm missing here that will explain that gap? Maybe, let's say a more generic question. Just a year ago, when you presented your results, the Lundin deal still had to complete. At the time, you were showing that ex-Lundin shareholders were going to own 43% of share capital upon deal completion.
It may be difficult to keep track of things given you regularly meet with some of the largest investors. Are you able to give some color on how the share may have evolved since deal completion, please?
Yeah. David, do you wanna?
I can. Very nice to see and hear you, Johan. That's a great relief that the technology is now working. Yes, the difference between the 700 and the 770 MMbpd is actually quite easy to explain. The 770 includes all the volumes that we have sanctioned under the temporary fiscal regime and not only the volumes that were sanctioned in December. Including, for example, the KEG project that is currently being developed and Hans under execution. With regards to shareholders and shareholders development, of course, it's difficult to speak on behalf of shareholders with regards to how they are developing their shareholding.
When it comes to, of course, the major shareholders, there's no big development in their shareholdings since deal completion, as far as I know, at least.
Okay, let's move on, Kjetil.
Yes. We move on to Chris Wheaton from Stifel. Chris, please go ahead. The line is yours.
Thank you. I hope you can hear me okay. Thanks very much. Fantastic. I'll keep my video off, though, 'cause you don't want to see me this morning. Thank you very much for your time. One question from me. How much visibility do you have in the project CapEx, and timing assumptions, given that, you know, with industry inflation continuing to be quite strong, and I think particularly in Norway, given the tax system has encouraged everyone to sanction projects, not just yourself, inflation's going to be quite persistent. Can you talk about the process of you reassessing or reviewing the CapEx timing and CapEx amounts within the project, and therefore the likelihood of, you know, when we can start to see updates on those CapEx numbers actually start to come through?
I guess my concern is, you know, we come in one morning and discover that you've put out an announcement saying your CapEx is, you know, $1 billion higher than you thought it was. That's the kind of risk I'm sort of thinking about. Thanks so much.
Yeah. Okay.
I should also say a great quarter of delivery on production performance and safety and everything as always, I would expect. Well done. Thank you.
Thank you, Chris. Yeah, basically two questions. The one is about phasing, and the second one is about volume. When we did our estimations back in November, October, November last year, we did quite a lot of work on how we expect inflation to behave in 16 different categories across the project portfolio, both from a short-term and a long-term perspective. We put those inflation numbers into our assessment in December when we made the final investment decisions. I wouldn't say that we were 100% right on all categories, but in general, our analysis of inflation and inflationary pressure at that point in time was pretty spot on.
Now that we've done the first master control estimate, which is the kind of bottom-up buildup of cost and schedule, we're pretty much spot on the estimates that we had back in December.
If that is an indication that we are also correct when it comes to inflation in the future, I think we would say that we're pretty well off. We are now getting a lot of prices in and more and more prices are being locked in as we move forward in the contracts and the continuation and the clarification works with these counterparties. That means that there are less and less scope that is actually directly exposed to inflation. As time goes by, most of the cost increase will come due to events which we hopefully won't really see. I think there is a discussion around phasing.
It's quite clear that some of this phasing discussion that was also referred to in Victoria's question, we are discussing about the cash, the cash value and the value worked on with these vendors. We are seeing a somewhat higher front-loading than we would normally see in this project, but that was also accounted for back in December. All in all, I would say that we were, we were pretty spot on, both when it came to how the market would react in terms of inflation, but also what kind of rectifying measures the market would put in place to compensate for future inflation. Then you had a question about when do we do estimates.
We do update control estimates at least once a year, and probably now in the phase I we'll do this every second year, every half year, two times a year.
Brilliant. That's very hard thing to get right, but that's really interesting insight into your process there. Thank you very much indeed.
Thank you, Chris.
Yes.
Let's move on, Kjetil.
Yeah. We circle back to Jørgen Bruaset, who hopefully now can both hear us and we hear him.
Absolutely. I can see and hear you. Thank you for circling back. I reckon you are not in a position to give any more color on my initial questions regarding quantifying maintenance for next year, but just two more housekeeping questions from my side. Just looking at the CapEx number for Q1, run rates slightly below where we see CapEx for the full year. Are you able to just give some more clarification on the distribution of CapEx through the year, H1, H2, back-end loaded, front-end loaded? Then also maybe if you're able to tie in some comments on your production guidance versus your OpEx per barrel guidance.
Should we look at this as the midpoint of the production guidance squaring with the midpoint of the OpEx guidance, or are there any other dynamics we need to think about in that regard? Thank you.
Housekeeping, that's your department, isn't it, David?
Housekeeping is my department, Jørgen. Good to also hear you loud and clear now. Apologize for that. I think we found the technical difficulties on our side. Apologize to all of you who are being stressing and muting and unmuting. In terms of CapEx phasing through the rest of the year, as planned, we wouldn't spend the pro rata share this quarter, of course, as the projects are ramping up execution. I think what we can give in terms of guidance for this year is sort of a steady increase through the different quarters. As mentioned again, you know, there is, you know, phasing elements here that we're still working on. But I think that's the base case expectation.
Then when it comes to OpEx and production costs. Yes. I think the midpoint of the guidance on OpEx is typically the midpoint of guidance on production, right. Of course there are other elements also which really impacts. We've talked about it previously, and I also talked about it when I gave the guidance back in February. It's of course, power costs influences quite a bit, foreign exchange rates being the other. Then when it comes also to phasing of OpEx, well maintenance is typically sort of a bulky activity which could sort of land in between quarters. All of these aspects are important looking at this quarter-on-quarter.
That's why I think it's better to use the average throughout the year.
Thank you for your patience, Jørgen.
Very clear. Thank you.
We'll move on, Kjetil.
Yes. next hand is Teodor Sveen-Nilsen. Please go ahead, Theodor.
Good morning. Thank you, Kjetil. Can you hear me?
Yes, we can.
Excellent. I'll keep my camera off just to reduce the risk for any further hookups here. Just have a couple of questions here. Maybe some of them have been asked already, but since I've been thrown out from the webcast, hard to say. I just wonder on the current production rate, you obviously had higher production towards the end of first quarter than in beginning of first quarter and quarter. Is the current production above your full year guidance? When I say current production, let's say quarter to date April. Second question that is on Edvard Grieg. What's the current book value of Edvard Grieg after the impairment? Second question on Grieg, why did the production decline substantially from fourth quarter?
Third question, Rondeslottet, really exciting well. One of your partners provided a pretty aggressive resource estimate. Do you have a resource estimate for Rondeslottet?
Yeah. Okay. Production rate, obviously we averaged 153. As you point out, the run rate towards the end of the quarter is slightly higher than that. You're also right that this was the full, first full quarter with Johan Sverdrup being on nameplate capacity.
My expectations is that Q2 will end up pretty much in the same territory, maybe slightly higher. There are some maintenance activities in Q3 that will also impact the total yearly average. I still believe that the 430-460 is a fair assessment of where we'll end then in terms of total volumes. Production in Edvard Grieg and also actually Ivar Aasen was impacted by a shutdown caused by an electrical failure in Q1. That's why we have a slightly reduction in production in Q1 from Edvard Grieg. That's also the main reason that the production efficiency and overall went from 95% in Q4 to 93% in Q1.
On Rondeslottet, I don't think I'll go out with an updated estimate. I'm aware that there are different opinions out there. Rondeslottet is a relatively tight reservoir. It's a discovery from back in 2003 called the lead at the time. The well produced up a significant oil column. I could say that there are 700 MMbpd of potential. The discussion is the producibility. We'll place this well closer to the apex of the structure and in what we hope is a slightly or somewhat higher producibility section. Of course, if that's successful, that would unlock quite a lot of potential.
I'll keep it at that. We'll come back once the well is drilled. On book value, Teodor, I think you can refer to note five on the details of the impairment and the book value in total of the cash generating unit, Edvard Grieg and Ivar Aasen. I think it's fair to say that we still have technical goodwill allocated to the unit. As mentioned in my presentation, all things equal and no changes in assumptions, we do expect to impair goodwill, or technical goodwill, on a quarterly basis as we are producing out value of the field.
Okay. Understood.
But-
Just back to the 700 MMbpd you mentioned, Karl. Is that oil in place or recoverable resources?
The original estimation is recoverable resources. As I said, the big uncertainty here is the recovery factor. That's why we're doing this, appraisal exploration drilling. I'll come back to that once we've drilled the well, with more precise estimations.
Understood. Thank you. That's all from me.
Thank you, Teodor. We'll move to the next one, Kjetil.
Yes. There are no further hands raised, we got a follow-up question from Jørgen at Soc Gen. Do you expect to have received all necessary approvals before we meet again this summer on the PDOs?
The process with the PDOs is now that the Norwegian government has sent all the necessary papers to the parliament. As far as I understand, the parliament will make a decision before while they are in session and before the summer. That probably means a decision in late May, June somewhat. My guess would be yes. Then there are concessions related to power from shore and building concessions. The concessions from power from shore is already given, and we're applying now for construction concession on shore and a bit later for construction concession in the fjords for the power from shore project. That might be the only outstanding item once we meet in July.
Hmm. Yes.
If there are no further questions, I suggest we close. Guys, my sincerest apologies for the technical difficulties we'll have. This is the second time we're running this system. We'll make sure it's better next time. Thank you, and have a good day.