Ladies and gentlemen, good morning, welcome to the Equinor second quarter 2018 conference call on what I know is an especially busy day for you all, we aim to be very efficient. Our CFO, Hans Jakob Hegge, will run through our results in just under 15 minutes. We will open up for questions from the phones, we expect to complete the call within the hour. I am also joined on the call today by Svein Skeie, head of performance management, and Ørjan Kvelvane, head of accounting. With that brief intro, let me pass straight away to Hans Jakob.
Thank you, Peter, good morning, everyone. Today, I am presenting Equinor's first quarterly results after our name change in May. It is a solid set of numbers, I am particularly pleased with good results and cash flow from operations, strong adjusted earnings after tax, record international production, and the value-enhancing transactions. We presented at our capital markets update as Statoil. These results confirm the delivery as Equinor, there are no changes to our strategy and guidance. The IFRS net operating income is NOK 3.8 billion before tax this quarter, adjusted earnings before tax was NOK 4.3 billion. Adjusted earnings after tax was a strong NOK 1.7 billion, this is up 165% year-over-year, adjusting for Angolan profit oil benefit taken last year. I will revert to these results again in a moment. Equinor's activity level in the second quarter was high.
We are progressing a large portfolio development project, I am pleased to confirm that we are delivering according to plans. Aasta Hansteen, Oseberg, West Flanken, Peregrino Phase 2, and Mariner are examples of strong project execution. The biggest of them all, Johan Sverdrup, is the one you can see on this picture. With the lifting in place of the bridge between the drilling platform and the riser platform. Many of you visited the living quarters at the construction site last year, now more than 800 people are currently working offshore, getting the field ready for startup in 2019 at substantially lower cost than anyone thought was possible at PDO. In our project pipeline, we already have Bay du Nord in Canada, Carcará and BM-C-33 in Brazil, and Johan Castberg, Snorre Expansion, and Troll Phase 3 on the NCS on the move.
In early July, we presented the phase 3 development plan for the Troll field. With more than 2 billion recoverable barrels, this project is among the most profitable and robust ever in the history of the company. The Troll field has already generated a massive NOK 1,400 billion in revenues, we are now extending the field's lifetime beyond 2050 and expect to create even greater value going forward. In addition to these on-schedule and on-cost project deliveries, we continued to build our project portfolio for the future during this quarter. We closed the Roncador and Carcará transactions in Brazil and the North Platte acquisition in the Gulf of Mexico. We secured attractive new exploration acreage in Brazil, the U.K., and Norway. The second quarter is characterized by solid results, solid cash flow from operations, high production at higher realized prices.
Our after-tax result is especially strong this quarter, with major contributions from E&P International. For the second quarter, the board has decided to maintain the quarterly dividend at $0.23 per share. The safety of our people and the integrity of our operations is and will always be our top priority. The group's 12-month serious incident frequency was 0.5 per million hours worked. This is at the same level as in the first quarter 2018. It was our strongest SIF to date. The SIF for the same quarter last year was 0.7. Now on to the financial results in more detail. We delivered adjusted earnings before tax of $4.3 billion in the quarter, up $1.3 billion, or 43%, compared to the same period last year. High production from ramp-up of new fields and new wells and higher realized oil and gas prices contributed to the strong results.
Exploration & Production International's contribution is especially strong this quarter. The after-tax result is very close to the record from the first quarter 2012, when the oil price was above $110 per barrel. Realized liquids price for the group in the second quarter was $65.8 per barrel, an increase of 48% compared to the same period last year. Realized European gas prices were up 28%, while U.S. gas prices were down 12%. The IFRS result was $3.8 billion in the quarter, influenced by net impairment reversals and derivatives. Net reversals were $0.3 billion. In the quarter, we report impairments of around $760 million for U.S. onshore, largely caused by a change in our long-term oil price assumption and a change in valuation methodology for Eagle Ford. Let me remind you that we, in the fourth quarter last year, had reversals of $1.3 billion for our U.S. onshore activities.
The low tax rate in the quarter of 60.7% resulted from strong earnings in areas with low or no tax. The low effective tax rate in the international segment reflects structural composition of the earnings in the quarter from areas with low or no tax. There were no one-offs. Let's now move on to look at the segments. Exploration & Production Norway delivered adjusted earnings before tax of $3.1 billion, an increase of 58% from the same period last year. High production, higher realized prices resulting in higher margins were the key drivers. In the quarter, 10 turnarounds were completed. We experienced some increase in reported costs due to new fields coming on stream, in line with what we communicated at our CMU. We had some quarter-specific costs related to higher seasonal maintenance, pensions, and some unplanned losses at a couple of our fields.
We continue our improvement work and maintain a strong cost focus across the organization. Achieved liquids price was 50% higher than in the same period last year. Exploration & Production International delivered very strong adjusted earnings of more than $1 billion before tax, up 18% compared to the same period last year. Let me remind you that we had last year impacted in our result for the second quarter an improved effect of $750 million due to a one-off effect related to Angola. Adjusted for this effect, the result is eight times higher than the same quarter last year. The production in the quarter was record high with an underlying growth of 11% year on year. At the same time, the underlying OpEx SG&A costs per barrel were stable.
The cash flow after tax from our international business was very strong this quarter at NOK 30 per barrel, which is higher than what we saw from the NCS. To our MMP segment, which delivered a pre-tax result of NOK 302 million compared to NOK 292 million in the same period last year. We achieved solid results from LNG and products trading, while the natural gas trading delivered somewhat weaker contributions. To the production. Equinor's production during the quarter was 2,028,000 barrels per day. This is an increase of 32,000 barrels per day, corresponding to an underlying increase of around 2% year-on-year. Our international production was the highest ever, driven by strong production growth, mainly onshore, but also offshore U.S. In addition, the Roncador field in Brazil started contributing from June 15th.
Production ramp-up of new NCS fields like Gina Krog and Byrding, new wells, and higher flex gas production volumes also contributed positively. In the next quarter, we expect higher impact of maintenance on group level with higher turnaround activity in our international operations. The planned impact is estimated to be around 80,000 barrels per day. Year-to-date, we deliver a strong cash flow from operations of more than NOK 13 billion and a net free cash flow of NOK 0.9 billion after the acquisitions of Martin Linge and Roncador and the Carcará farm-down. In the quarter, our net debt ratio grew by 2.1 percentage points to 27.2%. Without the above-mentioned transactions and the change in our working capital this quarter caused by liquid inventory growth, the net debt ratio would have been three percentage points lower. Year-to-date organic CapEx is NOK 4.6 billion.
To sum up, we are on track to deliver on the targets we presented at our capital markets update in February. We maintain our CapEx guiding for the full year at around NOK 11 billion. Our expected exploration spend this year is maintained at around NOK 1.5 billion. Expected production growth is still 1%-2%, and the expected annual production growth during 2017 to 2020 is unchanged at 3%-4%. Before I ask Peter to start the Q&A, as you may know, I'm moving to the U.S. to take over the responsibility of our global onshore assets. Let me use the opportunity to thank everyone with whom I met and spoken to during this busy, interesting, and I believe quite successful period. I want to wish my colleague, Lars Christian Bacher, every success as CFO starting next month. It's been a great pleasure.
Thank you, Hans Jakob, spot on in delivery again, 15 minutes to the dot. Let's move to the Q&A. I'll pass over to the operator, who will run the polling. Thank you very much.
Thank you. If you would like to ask a question, please signal by pressing star one on your telephone keypad. If you're using a speakerphone, please pick up your handset, and please make sure your mute function is turned off to allow your signal to reach our equipment. Again, that's star followed by one to ask a question. Our first question is from Oswald Clint of Bernstein. Please go ahead.
Hi. Good morning. Thank you very much, Peter. Thank you very much, Hans Jakob. I just wanted to clarify your comments there. Spoke about a little bit of higher unit OpEx in the NCS versus the CMD kind of ambitions, but alluding to the fact that it is pretty much quarter and field-specific in the second quarter. Could you just reiterate that point and why through the second half of the year, we should expect costs to come back in line with your 2018 forecast, please? Secondly, maybe going over to the U.S. onshore, the business you're going to start running. I'm just looking at international gas, and it looks like Marcellus gas is up really strongly, 36%, 37%, despite gas prices actually falling year-over-year through 2018.
Just wondering, is that still because the Marcellus is so low cost and so profitable, you can still drive up volumes there and still deliver underlying profitability there? That's the second question. Thank you.
Thank you, Oswald, for those questions. First on the NCS cost, as we said, we will see some higher costs when new fields are brought on stream, like Gina Krog and Viding. Remember, costs are still very close to a 10-year low after several measures taken over the years. As you mentioned, there are some quarterly specifics related to maintenance. Pension is a one-off, and also some additional costs on unplanned losses on some fields. We continue with our continuous improvement and strong efforts on cost and capital discipline. On the U.S. onshore, you're absolutely right. It's a strong production growth of 34% overall from the U.S. The onshore is accordingly growing in the gas. This is Utica and Marcellus, new wells on stream, and a record high 370,000 barrels overall U.S. production.
This is in line with what we said at the CMU, and it's a strong contribution from this, and it contributes to the strong close-to-record-high international results.
Okay, very good. Thank you.
If you find that your question has been answered, you may remove yourself from the queue by pressing star 2. Our next question comes from Thomas Adolff of Credit Suisse. Please go ahead.
Morning. I've got two fairly straightforward questions, please. Firstly, just to clarify on your comment on the underlying decline rate. If I'm not mistaken, you said it was 2% or thereabouts. Presumably, that's better than your base case. Your base case, I think, is around 4% or 5% per annum. I was wondering what's driving that since production efficiency is quite high already on the NCS. Second question, just specifically to Europe and gas demand. Can you say something on gas demand, including reloads during the second quarter, and perhaps linked to that, why European trading was a bit softer this time around? Thank you.
Thank you, Thomas, for those questions. On the decline rate, it's 5%. It's unchanged. I said the production growth for this year is 1%-2% and maintained. That's hopefully clarifying that one. On the European gas, we have seen hot weather increasing cooling demand reducing availability of all hydro as an effect of the weather. Going forward, we could see some pressure since the European gas prices gained through the second quarter. The pressure from high crude prices, relatively low LNG volumes and some containments both from the U.K. and the NCS. Storage injections have been relatively strong, significantly reducing Europe's deficit to the 2017 levels. Going forward, some pressure on European gas, we expect.
Okay. Thank you.
Our next question comes from Biraj Borkhataria of Royal Bank of Canada. Please go ahead.
Hi. Thanks for taking my question. I had two, please. The first one was just following up on your comments on the Eagle Ford. You mentioned the impairment was driven by a lower long-term oil price assumption, but also a change in valuation methodology for the Eagle Ford. Could you just provide some more color on what exactly has changed there? Also, as part of that, could you give us an update, if there is any, on the well spacing issue? That'd be the first one. Second question, just very simply for you, is looking to the second half of the year, could you just remind us what your expectations are for the Norwegian cash tax installments? Thanks.
Thank you, Biraj. On Eagle Ford, in the second quarter, first overall in the U.S., we full-time impairment reversals. Overall for the U.S., it is NOK 300 net. NOK 760 million impairments, of which NOK 240 of them is exploration expenses. On Eagle Ford, there is a small change in the long-term price, also a business plan update with some deferred production from Eagle Ford due to the change of the well spacing. We have in the past explained that we did 500-foot well spacing. Along with other players in the industry, we narrowed it down to 200. We did the campaign of 80 wells on 200. That didn't turn out to be successful. We are assessing it. While the recent drilled wells show improved production performance, the results are not mature enough to be taken into consideration for the impairment evaluation.
More time is needed realizing the production performance over a longer period of time with more wells. This is impacting the long-term production with some deferred barrels. The second element of changing the valuation methodology, Ørjan, you want to comment on that?
I can do that. In third quarter, we used the fair value. That means that we got input from external market. We are required to use the higher of the external market and our own assumptions. What we see from the market is an indication of that not being present any longer. We are moving back to our own assumptions now in second quarter.
Your second question was related to NCS tax installments. Svein, do you want to cover that one?
Yes, I can cover that one. As you know, the Norwegian taxes are paid half the year they occur and half the year after. In the first half, we have paid taxes then from last year. First of August, we will have the first installment on the 2018 taxes. That is estimated to be around NOK 14 billion. We will do an assessment then for the two remaining parts of it, the first one is around NOK 14 billion.
Yeah. Great. Thank you.
There will be a recalculation also in September, October related to the two remaining NCS installments.
Okay. Noted. Thanks.
Our next question comes from Alastair Syme of Citi. Please go ahead.
Hello. I also had a question on the impairments. You mentioned change in the long-term oil price view. I just wanted to clarify if that's a corporate change or is that just applying to the U.S. business? Secondly, I just wanted to ask about Roncador, which I think you mentioned completed on the 15th of June. I believe the deal was backdated to the 1st of January. I just wanted to confirm that that backdating was flowing through the working capital and the cash flow. Thank you.
On the impairments, it's a corporate change. Roncador, Ørjan, you want to cover the question related to January? Svein?
On Roncador, the effective date was then 1st of January. In the settlement that we then did the final payments on it, we took into account the value of the production from 1st of January up until the closing date. That has then been taken into account, reducing the payment somewhat.
It's a reduction in the payment rather than any of the other working capital items. Is that right? Is that what appears in the cash flow?
Yeah. The pull-on comm meant that you paid a little bit less on the CapEx.
Just back to the oil price view, are you able to say what your new long-term oil price view is?
On the oil price, as it is disclosed in note six in the MD&A, it is mainly up a little bit on the short term, 2022, it's $75 in 2018, and $80 in 2013, 2018, which earlier was measured as a base year 2016. That's the measure.
Okay. Brilliant. Thank you very much.
Our next question comes from Mehdi Benbachir of Societe Generale. Please go ahead.
Hi. Good morning, and thanks for taking my questions. First question regarding the U.S. production, please. We can see that onshore liquids production started going up with the increasing number of rigs currently in use. Can you tell us if you intend to keep increasing the number of rigs if the WTI price remains at around $70 in H2 and also for 2019? Second question regarding your production efficiency in Norway. You highlighted those last quarters that you were reaching record-high levels, above 90%, and you intended to stay around those levels. But can you please tell us what was the production efficiency level in Q2, given it looks like it went slightly down? Do you think that you will be able to reverse the situation in the second half of 2018 despite you are increasing the impact from turnaround? Thank you.
Thank you, Mehdi, for those questions. Let me start with the last one. On production efficiency, we have had an impressive performance of many of our NCS installations also this year. In the first half, we have more than a dozen installations with regularity well above 90%. In this quarter, we had somewhat higher unplanned losses due to events on a couple of our installations in April, May. Those issues have been solved. These are deferred volumes, and we think we can achieve also high regularity going forward. To your first question on the U.S. onshore production and activity level, we have a high activity level in the U.S. We continue to look closely at economics before we raise the activity. We have four operated rigs and one completion crew in each basin. In this quarter, the production increased by 34%.
Overall, it's expected to increase slightly in 2018 versus 2017 with more completions.
All right. Thank you very much, Hans, and all the best for your new position in the U.S.
Thank you.
Our next question comes from Anne Gjøen of Handelsbanken.
Good afternoon. Thank you for taking my question. I have a question related to maintenance activity. You're guiding somewhat higher maintenance activity, third quarter in particular. Will this have any impact when it comes to cost level due to a different product mix? Will it impact tax to some extent if it's a different product country mix? Where is the maintenance activity mainly taking place in the third quarter? Thank you.
Thank you, Anne. The maintenance impact was clearly visible as guided on the NCS this quarter. The coming quarter, there will be more so in the international portfolio. We are expecting an 80,000 barrels impact on the production. We do not have any guidance on a change in the products mix as so.
Question? Thank you. Our next question comes from Rob Pullin of Morgan Stanley. Please go ahead.
Thank you. Thank you, gentlemen. Just shifting gears slightly, could I ask about some of your maybe further out projects, including in Brazil, where I believe there are drilling plans on Greater Carcará, and when we should expect an update in terms of news flow around that development. Secondly, if I can just clarify on the maintenance from the Norwegian side that those higher maintenance costs or maintenance-related costs in 2Q will not be spilling over into 3Q. As you mentioned, there'll be international maintenance, but that's a different issue. Thank you very much.
Yeah. The short answer to the second question is that, yes, the seasonal one-offs and related to maintenance, you should not expect to see in the coming quarter. On the first one, we have an exciting well in Brazil called Guanxuma. It is in the BM-S-8 license, with the Carcará discovery. It's an ongoing operation. We have a discovery, but we have not clarified yet the size of the discovery or the commerciality. This is something we will have to revert to. The initial results are promising.
All right. Thank you and best of luck in America.
Thank you.
Our next question comes from Christyan Malek of JPMorgan. Please go ahead.
Hi. Good morning. Thanks for taking my question. One question on just underlying cash flow. Year-on-year looking at your CFO from ops, I understand the delta on taxes paid, with the improvement in the oil price, can you just help me understand the extent to which basically your cash flow from ops will come down, which links into the underlying cash flow for the quarter? Why is it that you're not getting as much capturing on the cash flow from ops relative to where the oil price is year-on-year, also sequentially? Help me understand where is the cash flow leakage here, if you just walk me through the moving parts, please. Thank you.
Thank you for that question. The cash flow from operating activities year-to-date is very strong, over NOK 13 billion, NOK 10 billion after tax. This quarter from operations, it's NOK 1 billion lower than the 1st quarter. We ended at NOK 6.1 billion. This is mainly due to the reduced volume sold in the 2nd quarter compared to the 1st quarter. It's partly offset by increased prices. We also have the derivative effects related to commodity derivatives, a loss of NOK 465 million in this quarter, compared to a loss of NOK 163 million in the 1st quarter. We have the taxes paid. They increased by NOK 1.2 billion from the NOK 1.1 billion that we had. We are up to NOK 2.3 billion on taxes due to the two tax payments in the 2nd quarter compared to only one in the 1st quarter.
Yeah.
Yeah?
I understand that, on a year-on-year basis, your cash flow from ops have gone from NOK 4 billion to NOK 3 billion. Trying to understand that in the context of an oil price that's up significantly. Put another way, is it basically higher oil prices are coming with more cash taxes, more working instruments? Essentially, the capture on the higher oil price is not as good as you thought it would be? I was trying to understand on the year-on-year improvement rather than sequentially what the underlying cash flow efficacy is doing, with the higher oil price, trying to square why it's not better.
There is no change in any guidance. We are on track with the break-even of USD 50 and the NOK 12 billion free cash flow as we guided on, no change to that.
Okay. Fair enough. Thank you.
Our next question comes from Raphael Guettaz of Bank of America Merrill Lynch. Go ahead.
Good morning. Thank you for taking my questions. Coming back to the maintenance in Norway that you highlighted, I wanted to know the fields that were specifically the drivers behind the, I guess, disappointing performance in Q2, and I wanted to know if it was more logistics related or operational issues that led to the slower-than-expected ramp-up back to full pelt over there. Secondly, you mentioned in your associated income that the weakness was partly driven by, I guess, Lundin Petroleum. I wanted to understand whether that was owing to operational or fiscal issues. Thank you.
Thank you for the question. On maintenance in Norway, we had a seasonally high maintenance activity, some additional costs related to that. The turnarounds impacted the overall production. This is normal for the second quarter, but the impact was larger than in 2017. On the regularity, the production efficiency, it was not on par with the very high results obtained in the previous quarters. As I explained, we had more unplanned losses. This added to some of the costs, but also the lower production. Costs per barrel went up relative to the high performance we've had. It's two fields. It's [Back in time], the issues have been solved. The decline is expected, and we had the contribution from the new fields coming on stream. Overall, we should be fine, I think, going forward on the maintenance part.
The associated income of Lundin affects impact. I would just refer to the Lundin results.
Understood. Thank you.
Our next question comes from Theepan Jothilingam of Exane BNP. Please go ahead.
Thank you. Good morning, it's Theepan. I have two questions, actually. Could you just talk about the oil price or macro assumptions you made for the guidance on the NOK 14 billion for the first tax installment? Secondly, on CapEx, I know typically you are sort of second-half loaded in terms of annual CapEx, but I was wondering how much contingency is there in the NOK 11 billion for 2018?
Okay, Theepan. Thank you. I'll do the CapEx, and I'll ask Svein to cover the first installment. On the CapEx, NOK 4.6 billion year to date, high activity level, higher in the second quarter than in the first. Going forward, we have very good progress on our project and the activity related to start-up of Aasta Hansteen, the completion of Martin Linge, Johan Sverdrup Phase 2 to be sanctioned later this year. We have delivered the PDO for Johan Castberg, Snorre Expansion. We expect higher activity. We also have Peregrino Phase 2 in Brazil, there will be higher activity in the second half. To you, Svein.
Regarding the basis for the calculations of the taxes, which then resulted in the NOK 14 billion in the first installment, what we do then is that, in the beginning of June, we take the realized prices that we have done so far, up until May, into context. We look at the outlook for the remaining of the year, looking at the forward at that point in time, and then taking into account the production and investment levels. That's what we have used. We are into the 70s.
Next question.
Our next question comes from Lydia Rainforth of Barclays. Please go ahead.
Thank you. Just a very big-picture question from me, if I could. Just in terms of when you reflect on your time as CFO, what is the thing that you are most proud of achieving? Then what do you think is the biggest challenge for your successor coming into that role? Thank you.
Thank you, Lydia. It's been great to be a part of a team that has contributed to a significantly stronger portfolio through the value-enhancing transactions. The counter-cyclical moves, selling at high prices in Norway, buying at lower prices both in Norway and international, the break even of our next-generation portfolio of $21 per barrel, $4.5 billion lower costs per year. Also, I think the share price development over the last few years has been okay. I think looking at the biggest challenge for Lars Christian, it's more related to what to do with all the strong cash flow going forward.
Wonderful. Thank you.
Our next question comes from Rob West of Redburn. Please go ahead.
Hi. Thanks very much. I'd like to go into two areas. The first one is on the tax losses that you're dipping into in your international business. I'm guessing that's mostly the U.S., where you have unrecognized losses and you're realizing those, boosting your cash flow per barrel. Is there anywhere else in the international business where you have unrecognized tax losses that we should be flowing through? What would make you shift those unrecognized losses to actual tax assets? That's the first question. The second one is on Oseberg, which I asked about last quarter, but I'd like to go back there. Is performance in the first half of the year at Oseberg where you wanted it to be? Can you comment on some of the issues on fields flowing into the Sture terminal? Thank you.
Thank you, Rob. Oseberg is a fantastic installation, the organization has performed very well over a long period of time. This quarter, it's slightly lower on the regularity, but they will be back. On the tax losses, there are more than U.S., Ireland is an example. There are also some deferred tax losses in Brazil, we have Canada on the list.
That's great. Thank you.
As a reminder, if you would like to ask a question, please press star one on your telephone keypad. Our next question comes from John Olaisen of ABG. Please go ahead.
Thank you for taking my question. When we look back to the cap markets update earlier this year, you guided on average CapEx of $11 billion in 2018, 2019, and 2020. Since then, you've done a number of rather big transactions, both in Brazil, U.S. Gulf of Mexico, Martin Linge, Garantiana, et cetera. I just wonder, over those next three years, that CapEx will have been influenced by these acquisitions, i.e., will it be higher due to these acquisitions in the medium term, the next two, three years' CapEx?
Thank you, John, for that question. No, there's no change in the guidance on CapEx. You're absolutely right. You mentioned several, what we call value-enhancing transactions. These are opportunity-driven. We think they make good sense in a long-term perspective, and we will continue to grasp these opportunities as they appear, but there's no change on the CapEx side.
The CapEx related to the acquisitions is included in the $11 billion guidance?
Yes.
May I ask, how many more acquisitions can you do?
Organic.
-before the CapEx is influenced for the next couple of years?
Well, organic CapEx guidance of NOK 11 billion is including the transactions.
Okay. Organic includes acquisitions, non-organic. Bit confusing.
Guidance and the non-organic is slightly higher.
Okay. total CapEx will be higher than 11, is that we understand?
Let's be clear. We provided guidance on organic CapEx. We said it would be around $11 billion.
Yeah
in 2018, on average $11 billion a year 2018 to 2020.
Yeah.
Okay? We also said that we would be opportunistic in terms of anything that came up, as we have been in the inorganic, and that will be one of the ways that we might use the additional cash flow. That's not included in the 11. It would be on top and opportunistic. The CapEx that we have on some of those acquisitions, for example, Martin Linge, is included in the $11 billion guidance.
Okay. That's okay. Thank you.
Thanks.
Our next question comes from Kim Fustier of HSBC. Please go ahead.
Yeah. Hi, everyone. I just have one question. I wondered if oil prices above NOK 70 are starting to unlock incremental investment at the margin, for example, things like infill drilling on the NCS. Do you find that, for example, within your NOK 11 billion organic CapEx budget, you've got good execution on the big projects, so you're sort of running a little bit below that in terms of run rate. Do you think you'll be able to do more than you expected initially on things like infill drilling? Thank you. Any color you're able to offer would be helpful.
Thank you for the question. It's been very rewarding to see the drilling and well performance over the last years with more efficient drilling, 70% more meters today, 40% less time, and 35% less cost per well. That's been an impressive performance, and that qualifies for we get more for less, and we have done more wells for these benefits and including infill drilling. The ambition level on IOR is very high. We are already at a world record on some oil fields, and more than 3,000 engineers work on moving resource classes getting ready for this additional drilling. This is part of the ambition level of our EUR and part of the efficiency program that we are going through.
That's great. Thank you.
It appears that there are no further questions at this time. I'd like to turn the conference back to your host for any additional or closing remarks.
Thank you. Yes. No more questions. I'd just like to thank everybody for participating. I know it's a busy day. As always, if there are any follow-up questions, don't hesitate to contact us in Investor Relations. I'd also like to thank Hans Jakob for his time as CFO and wish him the very best of luck as he moves over to the U.S. and to welcome Lars Christian. With that, I'll bring the call to a close. Thank you very much indeed.