Welcome and thank you for logging on to OPS Fourth Quarter Presentation. The details of the presentation and the report itself you will find on our website, wwwokl.no under the tag investors. The fourth quarter was an excellent quarter for the company.
We
delivered excellent results in production. We had a net profit of
million.
Let us just jump into the details and Norem, our CFO, will present you the financial result. And Bitte, please continue.
Thank you, Erik. Production reliability were high both at Joa and Drogon during fourth quarter. Production increased by 22 or nearly 2,900 barrels a day compared to third quarter following completion of the turnaround at Drogon and the planned downtime at Jura. Production were 5% lower compared to last year or about 850 barrels a day. The lower volumes at Drogin were partly due to gas previously currently being used as power supply and replacing diesel.
And also the temporary shutdown at the E 1 well, which was now back up and running again in February. At Jura, we had five days of reduced production in relation to the union strike, which ended in October. Sold volumes were 36% higher than last year or nearly 5,000 barrels a day. That was mainly due to allocation to OKEA of accrued lifting from Eberwosen as well as a large lifting from Droggen in October. We have observed significant improvements in market prices for petroleum products over the last months.
However, we did not get the full effect of the liquids pricing in Q4, partly due to the Drogin lifting occurring very early on the recovery curve. The realized price for liquids were 36% lower than last year, down from $61 a barrel to $39 a barrel. The recovery was however significant for natural gas, which was realized at prices 48% higher than last year. That brings the petroleum revenue to 581,000,000, an increase of 9% compared to last year and more than double the average for the previous two quarters. As for the income statement, the operating income of $584,000,000 mainly consisted of the petroleum revenue of NOK581 million as just outlined, tariff revenue from JEO of NOK16 million and partly offset by cost and accrued losses relating to hedges of million.
Production expense amounted to NOK189 million or NOK110 per barrel compared to NOK121 per barrel last year. That lower cost and that improvement largely relates to the very high production reliability and good performance both at Drauken and Jura. In Q4, we are reversing an impairment at EMEA of a 117,000,000 kroner. That was mainly driven by a very important milestone being achieved on New Year's Eve when Maske Inspire was installed at the EMEA field offshore. That significantly reduces the timeline risk towards production startup.
In addition, the improved macro factors significantly increases the fair value estimate. And as we are now, for all practical purposes, recognizing EMA at fair value, we should expect to see further changes in these estimates, which will result in either future impairments or future reversal of impairments, and these effects will be largely driven by macro factors at balance sheet date. Exploration and operating expense consists of NOK44 million in exploration expense, mainly relating to field development activities at Hasselmooth as well as seismic purchases. SG and A cost of NOK48 million is above average and is a result of an annual recalculation of costs allocated to licenses as well as bonus awards under our share incentive program. SG and A costs for the full year amounted to CHF87 million, a decrease of CHF16 million or 16% compared to last year due to cost cutting initiatives.
Net financial items is a gain of $243,000,000, which mainly consists of an unrealized foreign exchange gain relating to the dollar nominated bond loans as NOK strengthened by 10% compared to dollars during the quarter. This is partly offset by an interest expense of million. Tax expense for the quarter amounted to NOK227 million, representing an effective tax rate of 55% and brings the net profit for the quarter to NOK182 million. Cash and cash equivalents amounted to 871,000,000, and I will get further back to this. The current tax refund of 296,000,000 is losses in 2020.
Interest bearing debt amounted to 400,000,000.0, and this amount has come down partly due to buybacks and also due to unrealized foreign exchange gains. The asset retirement obligation of GBP 4,200,000,000.0 is partly offset by the GBP 3,000,000,000 in non current receivable as the cost of removal from and will be borne by Shell. Cash at the start of the quarter as well as cash at the end of the quarter is just shy of 900,000,000. Cash from operating activities amounted to million. Taxes received of GBP164 million is the net of two tax installments received, each of GBP154 million, partly offset by the residual tax for 2019 paid of CHF144 million.
Cash to investment activities of CHF188 million mainly comprised investments relating to EMA P1 project as well as the gas import project at Dogen. Interest paid of NOK71 million relates to both OKR02 which is payable quarterly and OKEA three, which is payable semiannually. During the quarter, we also did a partial buyback, an additional buyback of OKEA two for a nominal value of $2,000,000 or a cash outlay of 16,000,000 kroner. This is a discount of 11%, and we note that currently the bonds in NOKIA two is currently trading around par. We are also providing guiding on production as well as capital expenditure for 2021 and an indication of expected production given our existing portfolio for 2022.
As for 2020, we're pleased to deliver above our guidance Production of 16,100 barrels a day compared to the guiding of 14,000 to 15,000 a day is due to the strong performance we've seen throughout the year, both for and resulting in an outperformance compared to our guiding in excess of 1,000 barrels a day. And capital expenditure is just below or at the low range of the guiding, ending at NOK $980,000,000 compared to our guiding of the range between NOK 1,000,000,000 and NOK 1,100,000,000.0. As for 2021, the production guiding is in line with the actuals for 2020 at 15,500 to 16,005 barrels a day. And we have a few factors driving that. We have a few positive drivers, which is relating to the two new wells at the URP1 project, which we expect to come on stream now in February as well as the Ime startup expected in second half of the year.
These effects are offset by forty five days of planned shutdown in Q2 at Jura. Parts of this will be compensated as deferred production in 2022 and as well as general field decline. The increase in the 2022 outlook of 17,000 to 18,000 barrels a day is mainly due to an expected full year of production from INA. CapEx guiding for 2021 of NOK 600,000,000 to NOK 700,000,000 is a significant reduction compared to 2020, which is mainly due to both the p one project as well as the EMA new development project, both nearing completion. So on that note, I'll give the word back to you, Verik.
Thank you.
Thank you, Bite, for enlightening us about the excellent results of the fourth quarter. I will now talk a little bit about our projects and our assets. And let me start with the production as already shown. Here you see the production results of the entire year also compared to the fourth quarter in twenty nineteen. And we did last quarter, as already said, produced more than 60,000 barrels a day on average, which is almost exactly the same as we did for the entire year of 2020.
As you see, half of the production for Okea comes from the Drogin field and the other half is gas coming from Joa. So right now, we are about half fully exposed to gas and half to to oil. Let me first talk about the Drugen field. Drugen has is in its late life even though it's another twenty years to produce. That meant that we had to start we didn't have enough gas in the field, we have used diesel to fuel the energy system on Drogan.
But in the fourth quarter, we rebuilt the system such that we could import gas. So we are now importing gas, which started in the fourth quarter, imported gas from the Oskar transport system. And now we are fueling energy on Djergen with gas from the Oskar transport system. But also what is important on Djergen is to keep the wells in operations. And we have together with Oceaneering, we just the other day managed to repair one of the BOPs.
And you see here the operations going on at two eighty meters water depth, where we actually managed to get the valves to work. This is a well that has been shut down since 2019 and yesterday started to produce again. So the next thing that will happen in the Djergen area is the Hasselmuss gas discovery just north of Djergen is planned for development. Not only will we produce between 1,000,000,002 cubic meter of gas from Hasselmuss, but it also will probably be an enabler for producing the gust water gas discovery for a note of that again. But by producing gas from Hasselmuss, we avoid importing gas from Oskar system and we can also then export our condensates from Drogan, which has a high pretty high value and rather than use the condensate for fuel.
So a lot of good work is done on Drogan. At the same time, we we operate that with a very, very high regularity. And, we expect that we will make a decision on Hasselmuss in the first half of this year, and it's possible then to have first gas from Hasselmuss in 2023. With the very high CO2 taxes that is announced, we are really incentivized to find other power solutions to Durgen. And we have come quite far in establishing a project where we can have power from shore.
And we also expect to do final investment decisions sometime during this year. And so the plan for Djergen is to try to produce as much as 70% to extract as much resources as possible with investment already done. It's a very sensible thing to do in a circular economy type of philosophy. We plan to operate such that we can be in production until at least 2040 and produce as much as 70% of the reserves the field. As far as EU are concerned, where the rest of our production comes from, a new development project in the so called P1 secondtor has just finished and the two wells there will be put on stream anytime now and that will also contribute to a better production on Jua.
Jua is of course also of interest for us for two other reasons. One thing is that we have acquired shares and operatorship of Eurora, which is a modern gas discovery. It is possible that we will drill a pressure well on Eurora to make sure that we have quality that we say on the gas and the volumes that we say in order to get a reasonably good tie in contract to Europe before we develop that field. Will be a small one well development. And the pipeline is already laid over the Aurora area.
And in addition, as I will return to, we also got awarded a license just west of EURA platform. A very important thing that did happen at the end of the quarter was that Ume platform was finished in the Egerson yard and towed out to its location. So New Year's Eve, it actually landed next to the Welled platform where it shall stay for the next ten years to produce the Yume field. And this event really derisked the timing of the project. So now we are really confident that first oil will be seen from the Hema field later this year and that will have a significant contribution to OKA's production.
Another thing we did in the fourth quarter was to acquire the Vete discovery, it's another 40,000,000 barrel discoveries, about the same size as Graveling. We have been working very hard to get the cost down on Graveling and not only with a lot of good engineering work for the facility itself. And we look upon a combination or coordinated development between Weta and Gruvling as an enabler to get the breakeven cost even further down and significantly down. So we're working with the partners how to see how to develop those two fields in a kind of combined solution. In addition, we work around graveling where we the same partners, graveling, also hold the license.
So to graveling operated by Krysoor, where two prospects, Jarg and Ildr, will be drilled this year. Actually the spudding of the first well is already in March. And of course a discovery in one of these prospects will have a significant impact on the development plan and the value of course of the graveling field. And as also mentioned before, we were successfully awarded six licenses, eight discoveries in these six licenses, OKL operate four of the six. I go into there are three areas these six licenses are in.
One is, of course, around Drogin where we have a kind of core area right now, where we have four licenses together with Wintershall Dea, with Equinor, with WarEnergy, with Pantheon, with MondiOS and with Mvest. And several of these new licenses contains discoveries already, and that would be really interesting to see whether we can find relevant solution or additional reserves that enable us to develop these fields. Another area we picked up license is north of the Nordner Field together with Lime Petroleum where there are two discoveries. And so another example of finding discoveries to see whether there is possible to develop it with modern technologies and new view of the area. The third area where we acquired the license was, as already mentioned, right west of the Jura field and that is together with DNO and Pandion.
And of course, that's also an area we are already engaged in, so that also would be interesting to follow. DNO is operator of that license. So I want to wrap up by having some comments on the outlook. First let me mention how the market has developed As you see and already seen from illustrations earlier today, the realized oil prices was pretty low in the second quarter and have increased a bit since. So the general tendency with the oil price seems to be go higher.
And as the world is kind of getting back to normal sometime after corona, we think we will again see as also most agency will see again the need of oil is growing significantly. But we also see the gas prices are picking up. And as I already mentioned, Ukea produces also significant amount of gas. And what has happened in the 2020 and seems to still be the trend is that the gas prices have picked really up. There was actually a LNG cargo going in Asia for equivalent of $240 a barrel, but that was kind of an anomaly in the market.
But it really shows the volatility of oil and gas and the value also of gas going forward, we think. And as for the outlook of OKEA, we maintain that we will produce around 16,000 barrels a day also this year. And that will increase next year because of YMEA will be in full production. And from 2023, we assume and plan that the production from new developments will kick in, both Husselmooth and Geveling. These are not sanctioned, of course.
And we have not here at all forecasted anything from the new licenses that I just mentioned. So we are pretty confident that we within five years have picked up production about 20,000 barrels a day. But we have a lot of triggers also in the short term in 2021, already within a few days and definitely in February, we will see two new production in operations from Joao. We will have production from Ime this year. We will make the final investment decision on Hasselmuth.
We are partners in three firm exploration wells and the first one is actually spreading now in March. We'll possibly drill another well on Arora as already mentioned, and we expect that we and partners will discuss and agree on a concept selection for a wetted graveling. And not at least, we will mature a significant larger portfolio now than we used to have had following the APA 2020 award. We have doubled the number of operatorships following this award and we have eight new discoveries to look into and another 15 or so new prospects in that portfolio. That concludes the presentation.
Thank you for listening. And now it's open for questions, which then I will try to answer the best we can. So please post your questions now. Thank you very much.
Thank
And we'll now take our first question. It comes from Andreas Halt from Kepler Cheuvreux. Please go ahead.
Good morning, guys. Thanks for a good presentation. And it's also good to see that 2021 looks to be quite a turnaround year. I just have a couple of questions, if I may. First, you gave quite solid guidance on spending levels for this year and also your production.
Now I'm curious if you can give us any flavor in terms of the spend on exploration for this year and also if you can give anything in terms of operational costs either in NOK per barrel or dollar per barrel, that would also be good. And then my second part is more related to the capital structure of the company. Now with the current tax incentives in place and your quite lower spending level in 2021 compared to last year, This is to be kind of a cash building up on the balance sheet. Just curious to know if there's any thoughts of refinancing any of your debt structure in order to take down cost of capital? Or how do you see the capitalization of KL going forward?
Victor, please. Yes. Thank you, Anders. Well, there was a few questions. We don't provide guidance on spendings on exploration.
But as Eric said, we have three fairly wells planned. As for the capital structure, yes, we are having quite a solid cash balance at the moment, but we are also planning to embark on quite a few projects. So at the moment, we don't have any plans to do any refinancing, and we are exploring exploring various options to to finance new projects, but not in the in the very near term. So in the near term, we don't foresee any major changes to our capital structure. Production expense per barrel for 2021, we don't provide guidance on that, but I think the the track record that we have for 2019 and 2020 is a good indication, whilst that we have also communicated before that we are working on reducing the cost, particularly on Drogin, our operated assets.
But we don't provide specific guidance on that.
Okay. Thanks.
And we'll now take our next question. It comes from Theodor Nilsson of SB1 Markets.
Good morning and thanks for taking my questions and thank you for the update. A few questions from my side. First one on EU. Now I just noticed that you've changed your wording marginal that you now indicate first or the second half of this year compared to what you previously said was 2021. So I just wonder, is there actually a change in the outlook there?
Or is that or what's the reason for minor wording change? Second question on Jura, positive to see that they will come in a new well. I just wonder what should we expect in terms of production increase in first quarter from Europe? And third and last question on Draugen, you're talking about power from shore and then 130 kilometer of cable. Could you indicate to what that project will will cost?
Yes. Eric here. I can, I can start on the The because the EMA has been the project that has created a lot of aching in in the partnership because of of delays? And when we assessed EMA in the outside third quarter and during the fourth quarter, we put in space for a lot of we came into the winter season, and we put in a lot of space for significant weather spend by during the process. And so the fact that the InBERT platform landed on-site, on UEase was one of the few lucky incidents in in the project, because it was the was the weather went down just immediately following the completion at the yard.
And and that, in theory, took away, like, four months of hypothetical weather standby. So, when the platform is there physically and we see the project now going forward with MASHK and ARKIS solutions to hook up everything on the rig. There are still weather, uncertainties for some of the work. But, with the rig in place, we have taken away the biggest risk of significant delays. So that make us there are still four, five months work left.
And then, of course, there might be some work that is hindered by weather during the winter. But now we are very confident that we will see, first off, from after the summer into the 2021, and the risk of delay that in 2022 seems to be extremely small. With the exact number of the the random one I've learned from what we've produced. We're supposed to show. So we are not showing it.
Obviously, it's included in our guiding figures for the year.
Yeah. And now it's besides, it's operated by Neptune, and, it is their estimates and figures that they found. But, of course, that will be as we've seen in the monthly report that the industry delivers or the entity delivers. So we will production will not be a surprise, when it comes to the end of first quarter. The the power from shore project from, to Djergen will cost it's a it's a pretty long distance.
So so both probably cost around 2,000,000,000 to to do it. But, what we are working together with Equinor is to is to work this project together with with them to use on And how we share the the the cost and what is eventually we cost to them, we we don't know yet. So that's what we are working out right now and expect to to have a firm project proposal to to to the the and the same goes with Equinor that they will have the firm process to launch their license. And, and then we have a joint decision, hopefully before, somewhere. So but it looks like it it this project can can be feasible with the all the kind of subsidies and support that we can have to to realize that project.
The benefit for for us in addition to our paying less, CO2 taxes is, of course, that having electricity as an energy source on the organ will also enable us to reduce the operation cost more than towards the tail end of the field more than we can with the present, turbines. But you will get the numbers when we have the numbers. So they are quite tentative right now.
Okay. So maybe just to be fair, those NOK 2,000,000,000 will be shared with the Neurod and Draugen partners, right?
We don't really have a full overview of what the extra cost will be between the two because we have two different frequencies of currency of the two platforms. And so it it is a project going on now with the different suppliers and kind of competitive ideas of how to to do this in terms of of what what kind of currency you bring to air, etcetera, etcetera. So there are still issues up in in the air, but the cost range is quite expensive project, of course. But, yeah, probably for both for both licenses, north of that.
Okay. Thank you.
Okay. This is Tron Amdahl from OKR. On the web, we have a question from Jurgen Thorsten from Fermi Securities. Two questions. Could you please add some color on the higher SG and A for the quarter?
And the second question, do you have a rig lined up for
the exploration program this year?
Maybe I can take the first, at least. So, maybe this was posted before, I I elaborated this in the presentation, but, it it's basically relating to the fact that we've done a reallocation of cost to licenses during fourth quarter. And as we are ending up at lower cost than what we initially budgeted due to the cost saving initiatives, we have a reversal of the previous allocation to licenses. And also, the effect of the bonus awarded in the fourth quarter in relation to the share incentive program It's also a part of the effect that we see in fourth quarter. And we have some more information also in the quarterly report in Note 13.
And then yeah. Yeah.
That's for for the rigs. We the the three, current wells, there are rigs allocated, and and, it's a costly inventory. It's the first ones that are going to this year and build their prospects, starting in next month already. With respect to the potential Aurora pressure well, we have not, assigned any rig yet. But for the refurm wells, there are rig rigs assigned.
Another question from the web from Harald Esteban of Soft Value. Could you give any clarity on CapEx level in 2022?
In 2022?
Not at this stage because this will depend on what projects how the projects that we are now having important milestones is progressing. So that's why we have limited the guidance to 2021.
But also the 2022 cost will will, a lot of this project requires that we submit the PDOs or other things that has to be approved by governments, etcetera, etcetera. So the real investments, we probably not not seen before regarding twenty twenty three, twenty four. But the process project going forward is also where we will see some investments taking place in 2022, but we don't even know exactly how much now.
Okay. Are there any more from a moderator?
Are no more
questions over the phone. Yes. One other question here. You're drilling three firm wells here, Jarl, Ild and Gini. Can you say are they oil or gas?
And can you say
a little bit about the prospect size? Yes, I mean, of them is gas. Other is most likely gas on the other is most likely oil or actually most likely dry for both most likely water in both of them. That's how the next question goes on. And the size expectation is in the 50,000,000, 60,000,000 barrel range.
So it it they are not huge for our projects, But, of course, fifty, sixty million barrels next to, like, sampling will make a huge difference to to the economy of the to joint project because then you have, like, a 100 plus one development. So that would be really significant.
Okay. If there are no more questions, I'll just say thank you, here from OKR. And if there are any other questions, just, we have, given our contact details, and I'll be very happy to get back to you. So thank you