Hello, everyone. Welcome to OKEA's fourth quarter result presentation here in Oslo. Both welcome to you present here in Oslo, but also to you watching and following the webcast online. My name is Ståle Myhre. I'm VP Investor Relations in OKEA. Please, go in. With me here today for present our result is our CEO, Erik Haugane, our SVP Accounting and Controlling, Kjersti Hovdal, SVP Operations, Tor Bjerkestrand. Following the presentation, there will be an Q&A session. For those following online, there's also an opportunity to post question on the webcast. Okay, Erik. Go.
Thank you. Yeah, thank you, and welcome. Last year was extremely, not only important, but a year of big change for OKEA. It was the year that we moved from a group of 40 people to 200, where we moved from being a company with a lot of aspiration of doing development and production, to actually become one of the very few field-operating companies in Norway. The most important thing we set out one year ago, was that we needed to demonstrate a prudent, good, efficient, and cost-efficient, and technically efficient operations on Draugen. That's why also Tor Bjerkestrand will hold most of this presentation to show you what we actually have done there, and how we have basically through the last year been qualifying ourselves to be in the premier league of oil companies in Norway.
First, which is very important, is the first zero, work every day, every hour to make sure that management and the workers are very aware of the risk that is within this industry. That we actually work in a way that we, on behalf of the Norwegian government and the Norwegian people, to produce oil in a very secure manner. We are really pleased about that result, but that is not something that will come in itself, and we have to continue improvement on that field. We did produce almost 19,000 bbl a day in average throughout the year. We have a decent cash flow of more than 2 billion NOK. That kind of demonstrate the size of the company. The highlights was operational to a large extent.
Financially, Kjersti will go through the figures, but the main figures are that we did also a refinancing of the OKEA01, the first bond we had, NOK 120 million. What is also important with that bond is that that bond is also very flexible in terms of how we're going to refinance the company in the future. We had, during fourth quarter, a quarter of the NOK 2 billion that we earned did we earn in the fourth quarter. Our profit from operating activities was NOK 55 million. The cash flow from operations in the quarter was NOK 238 million. As for new opportunities acquired through the work in 2019, was the annual licensing round for 2019, which was actually awarded in January. We got five new licenses, all of them in areas that we have defined as the key areas for hubs, so to say, for OKEA.
We are not exploring doing wildcatting, we are not collecting a lot of licenses around on the shelf, but in mature areas where we know there are discoveries. In at least one of these, there is a discovery that we hope we can develop also pretty fast. That is the overall picture of what we have done in 2019. I will return at the end of the presentation with the outlook, what we plan to do going forward. Our key objectives for the first year is that we actually, in such a short time, if you compare it to other companies, using both two and three years before they actually are up on full speed as operators, we managed that through in 2019. Hereby I leave the word to Tor, who is the boss of operations in OKEA. Please, Tor.
Thank you, Erik. Hi, everyone, and to everyone looking at the live stream.
I will take you through the fourth quarter results from operations, but I will also tell a bit of the story in OKEA, going from acquiring Gjøa and Draugen from Shell and then becoming what we are today. I'm responsible for the operated assets. It means Draugen. We are an operating company, so we are then operating Draugen, and then we have licenses where we are not operating. That's the non-operated, which is Gjøa and Ivar Aasen for us. For quarter four, we have a slightly lower production and mainly because of a well at Draugen, where we have a safety valve in down in the well, which are not functioning as it should, and then we have to close it. That's regulatory and it's Yeah. That was closed in the fourth quarter.
The gas from Gjøa and several other fields go through the SEGAL system to U.K. and on the U.K. side, they had problems with receiving the gas and then it affects the production. Secondly, at Gjøa, we had a compressor technical issue, so that was also the reason behind. There is no well potential reasons. There are technical reasons. When you come to Draugen itself, where we are the operator, fourth quarter was, as I said, a bit lower than expected because of that well. Looking at the operational efficiency, we are showing a 95% availability or uptime at Draugen in the fourth quarter, which is then compensating for some of the loss of that well, and that is very high for Draugen.
In the same period, we did also finalize the Skumnisse and Ø, the two wells that we drilled, and those were plugged and abandoned with a lot of results coming out of those logs after doing the drilling. We are looking at how to restore the well, and we are planning to do an intervention now in Q2. I will mention Hasselmus here, which is a small gas field discovered quite a number of years ago, close to Draugen inside the license. That is like a gas tank. There are well-defined volumes. It's a relatively straightforward development, but we in OKEA have made that commercially attractive and we passed DG II in OKEA and the board, I guess, approved that development yesterday.
Now that will be up for the license approval and we will then kick off that project as the first tieback in OKEA. It's a fantastic project. We are also looking at other prospects close to Draugen. I will come back to that a bit because it's interesting how much oil which is still there in that area. The story of 2019 is quite interesting, because at the point of OKEA acquiring Draugen, the license, the whole concept of Draugen was to harvest. It was to take out the resources which are in place and then keep it going. Changing that into a development mode, that is a significant change. That means that you are starting to invest, look for, and then develop the assets for more volumes, and more volumes creates a longer lifetime.
The first thing we did was to set up in the license with Petoro and Neptune the agreement of 2035 and how to get there. We had to set up the organization to be able to speed up because we didn't have the budgeted plans for development. In a couple of months, we had agreed targets for drilling. We have got the rig, and we did the drilling. That was done in eight, nine months. I think if you look into other drilling campaigns, that is quite a good story. No serious incidents or spills from that part. I can also mention the ambition for the license and for OKEA and for Draugen is to keep Draugen producing until 2040. That we are close to showing that is a concept that is possible.
If you look at the operations itself, in addition to the drilling performance, we have had through the year 88% availability. That's a number. I think Equinor use production efficiency is the same. How many days of the year are the factory up and running? That is a quite high number. If you look back in the history of Draugen, there's only one year in the last 10 years that have been better. Going from the previous operator to OKEA, we have still maintained and improved the operations efficiency, and that has been instrumental in protecting the production, and then the value, and then the earnings. Being an operator is quite a complex organizational structure. It's not something you can develop just in a day or a week or a month.
It's years and years of experience, which now sits in OKEA's organization, which are now operating Draugen, and can take on more. The other important part for an operator company is to execute projects. In the start of 2019, we had two major projects ongoing. We had to change a significant part of the oil piping on board Draugen, and that was done on the record schedule. I think the number of days from shutting in to being back in production, changing 190 meters of piping, was 10 days. Without any incidents and on cost. We also have done other projects during the year, where we have done it according to plan and no incidents. When it comes to the emissions part of Draugen, you have emissions to air, you have emissions to water. We have several projects ongoing which are attacking that.
Let's say for one of them is the flare. We always have a flare, which is there just to protect when you have a shutdown, you need to get rid of the gas, and that goes to the flare. We have now a project ongoing to close the flare, and that is about 1 MW reduction in energy. We also have projects ongoing to make the compressors more effective. These are big machines, so if you do improvements, there are significant reductions. Of course, the big change for all offshore installations is power from shore. We are now ahead of competition, I would say, in the area for assessing the ability to do power from shore to Haltenbanken area and to Draugen in specific. We are pretty busy on looking at that. Very interesting.
Since we now have access to water power and hydropower and wind power in Trøndelag, it's a real option to use that energy. The fourth thing I will talk about is digitalization and the projects we have, and I will mention especially one. I can take the drilling campaign first, where we, as the first-ever, live-streamed the information that the driller have offshore on our website. Geologists around the world, they were looking at this stream because then you could actually see what happened 1,600 meters down there at the drill end every second. It was quite a change to be allowed to do that. In the end, we made that happen and I think sharing of data is an important thing in our industry. By doing that on that drilling campaign, it was a change in how we do it.
I will mention briefly the work we are doing together with ABB. Out at an installation offshore, you have a control system. That is a system where you have hundreds, thousands of instruments logging data at any time. That data has been a kind of a protected source and used for specific programs and for specific activities. What we have done now, and I should really stream the live screen for you, but I can't, it's a presentation. This is a snapshot, and we can build pictures like this showing all that data on your mobile. For those that knows how that data is collected and being transported now, this is a significant change. This change is so significant than if you go to Hewlett Packard in Houston, you will find this screen on their showroom. In difference from others, we will also share this data.
By sharing this data, you are connecting up to the real-time data, which is collected by the instrumentation offshore. Okay, that was the story of 2019. A fantastic year for the organization and for all of us. I would just like to show you how the license work. There are three partners at Draugen license, which is Petoro, Neptune, and OKEA. That license is the board of Draugen reserves and the values. You need to have a quite clear strategy for how to develop. It's not like week by week or month by month or the one year. We need to look ahead, and we are looking ahead towards our vision, 2040 plus. This is nothing, just an OKEA vision and dream. This is Petoro, Neptune, and OKEA together in the Draugen license saying, "Our vision is 2040 plus." How do we do that?
This is the value drivers behind how you develop such a license forward. We are updating this every year. In fact, that update is ongoing as we speak. We're having two days now together with the license partners developing this for the second time. Here you see the change from harvest mode to development mode. I will mention a couple of elements here. Ultimate recovery, 70%. Compared to the existing plan, we are talking about 30 million-40 million bbl. There is still a lot of value in the Draugen reservoir. The challenge is how to get it out. To buy new technology, buy new ways of looking at the reservoir, we expect we have an ambition to get 70% recovery. We are even talking 75% recovery. You're talking 40 million bbl more. These are ambitions.
These are the plans that we would like to chase and to deliver on. We are near field exploration, where we did the drilling in Skumnisse, and we are now looking at other prospects nearby. Of course, with the lifetime of 2035, 2040, Draugen as a hub is now an option. Nearby discoveries can be then transported to Draugen in the case they need that infrastructure. I think also the availability, also the ability to keep the factory running every single day, year out, year in, that is our most important task because it's easy to look at those volumes that are in front of you that you have to discover and the new oil. Caring for and securing, safeguarding the existing production is all about availability. By having that, we can deliver the volumes.
I will just mention that we just got the January numbers for Draugen, 97% availability. On cost, no incidents in January. We will continue doing that. That's our ambition. I'm looking forward to going on the plane back to Kristiansund this afternoon and sitting together with the license and look at the update we are going to do today and tomorrow and even sharpen the ambitions. Just finally, a short look at Gjøa, where we are a partner and not an operator. As I said, the reasons for the lower production was SEGAL export system and the U.K. side, which could not receive the gas and the gas export compressor, which had a technical issue and had to be changed. P1 interesting project for us.
First oil in quarter one next year, on schedule, being managed well by the operator, and looking forward to see that being completed. Thank you.
Thank you, Tor. I will take you through the highlights on the financial side this quarter. Tor already mentioned that the oil and gas volumes were reduced this quarter. The main reasons was the production issues on Gjøa with the turbine replacement and the SEGAL restrictions, also the shut-in well D2 on Draugen. The sold volumes were reduced with 17%. On Draugen, we lifted the same volumes in the third and the fourth quarter. The reduction here on sales was a result of the reduced production on Gjøa. Also we went into the quarter with an over-lift position on NGL on Gjøa, meaning that we had previously lifted more than our proportional share in the license. That position was neutralized in the fourth quarter and causing reduced sales. The realized prices increased both for liquids and for gas.
A combination of the volumes and the prices resulted in revenues of NOK 534 million in the fourth quarter. Some more details on our income statement. I already mentioned the revenues that goes into the operating income, but I will also talk about the production expenses and the exploration expenses, financial items and taxes. The production expenses were a bit higher than the average because we did some well maintenance work on three of the wells on Draugen in the fourth quarter. The exploration expenses, we had previously expensed the cost on Skumnisse that had incurred until the third quarter, but the drilling continued into the fourth quarter, and the remaining parts were expensed in the fourth quarter. The same was the case for the Catherine Well nearby Yme.
We also had seismic costs related to future possibilities in the area South Grevling and also in the Draugen area. The cost related to field evaluation is mainly on Grevling and Storskrymten. On the financial side, we had a favorable FX position at the end of the quarter that resulted in an FX gain. We also did the refinance the OKEA01 bond and replaced it with OKEA03, and we had financial expenses that were expensed as a consequence of that. The profit before tax for the entire year was NOK 419 million. The taxes ended at NOK 491 and consists of two elements. It's taxes payable and the amount of taxes payable is NOK 430 million, and the other component is changes in deferred tax. We normally, as a starting point, expect the 78% taxes.
The fact that we had more than NOK 100 million of impairment, that is non-tax deductible, that causes the relative tax percentage to be higher than 78%. In addition, we get an uplift on the CapEx investments we do. Finally, the financial items are partly allocated to the offshore tax regime. That cost in total, the tax percentage to be 117% for OKEA for the entire year. The cash flow, we had very strong cash flow from the operating activities in the company. Before we deduct the taxes, we had NOK 2.3 billion generated, and we paid taxes of NOK 172, both related to 2018 and prepayments for 2019. We had investments on NOK 847 related to Yme and the P1 project on Gjøa and also some CapEx projects on Draugen.
We had the share issue last summer as part of the IPO process that we had NOK 283 million from. As mentioned, we repaid the bond OKEA01 and refinance with OKEA03, costing and repayment and additional net proceeds this quarter. Finally, we paid interest of NOK 232. We ended the year with a cash position of NOK 1.7 billion, close to. That was the summary of the financials. Over to Erik for outlook and concluding remarks.
Thank you. We have, in addition to what we already talked about, we are involved in three development projects. One is Yme, which is Repsol operated. There is an offshore campaign going on to prepare for the hookup of Maersk Inspirer to start production. Aker Solutions has come up with a revised plan to complete the onshore modifications. We trust that a reputable company and a reputable yard managed to actually do that. According to our own inspections and the operator's forecasts. The work is progressing very well right now in Egersund, and we trust that they manage to complete all the offshore modification and leave the yard in the second quarter. The operator will come back with an exact estimate of first oil. The ongoing work offshore is meant to mitigate any time delay in the hookup process.
We expect production start-up during the summer 2020. With respect to Gjøa, another ongoing which is also quite significant, gives more than 2,000 bbl a day net to OKEA, is the P1 Gjøa project. There we can report a good progress from Neptune, and there will be two more production wells drilled later this year. The plan is an early start-up production in early new year. With respect to Grevling Sør, which is operated by OKEA, we have matured the project to the extent that it was a hugely negative value project when we took over to a positive value project. We are not fully satisfied with how positive it is. As you also may have noticed, that we have employed a new Senior Vice President for development, Knut Gjertsen, coming from Equinor, extremely reputable person in the industry in Norway.
One of his tasks will actually be to go and review the whole Grevling development and see if our estimate seems to be right, and to see if there could be additional improvements. Also in the Grevling strategy, the same partners are involved in two wildcats, just south of Grevling. Of course, added reserves into that development will change the game totally. The result of that drilling campaign, of course, has a major impact on the economy of Grevling. As I said, we apply for licenses quite selectively. We apply for five licenses in the license round, and we got five. As you may see on the map, they are all in close by existing licenses we have and close to fields we have.
Just will mention one that is particularly important to us is together with Equinor as operator, just northwest of Draugen, where there is a gas discovery already. We're quite sure that when we develop Hasselmus, as you may see in just north of Draugen, the distance to that, a bit smaller gas discovery, that license is such that suddenly that become economic again. It's kind of building on a previous investment. We, of course, prepare the Hasselmus development, so that's easier to tie in another pipe into that system. The volumes talked about here is also straightforward for Draugen to assimilate. The Hasselmus discovery is going for a so-called DG2 decision in the license right now.
The importance of that is that it both provide energy to Draugen, because we don't have a sufficient gas going forward to run the turbines on Draugen, but it also gives us quite a significant oil export capacity in the existing pipelines from Draugen. We will continue to apply for licenses in the licensing rounds. We will look at all the wells, all the discoveries that has been made. Some of them underestimated, et cetera. There will be also applications from OKEA this autumn. Finally, the outlook going forward is, as Tor already mentioned, first thing you have to do is to maximize the value of things you already have in your household, and particularly Draugen. To increase the recovery, it is, as you know, extremely good reservoir. Johan Sverdrup is the kind of next that type of reservoir.
It's a big pile of sandstone reservoir. We see that it produces extremely well. We think it's absolutely possible. There are still 500 million bbl left in Draugen. How much of that can we extract? That is the key issue. As Tor mentioned, there are absolutely within reach to take out another 100 million bbl out of Draugen. The two wells we drilled were also extremely important. They gave us a lot of value in terms of now remodel and make a new reservoir model for Draugen. We were surprised by some of the information we got there, and that is now implemented in the new model to really understand what goes on in Draugen and also next to Draugen.
With respect to next year, mainly because of a delay of Yme, we expect to produce almost six million bbl of oil throughout the year, which is a bit lower than we perhaps thought half a year ago. The financial flexibility is good. We do also have a biannual maintenance project going on Draugen this year. We have a very good cash flow. I think the estimate is that we might pay NOK 1 billion in tax this year. That will help some, I guess. We are also pleased with the structure of the OKEA03 bond, which gives the company a lot more flexibility in the future financing of also additional projects. We already mentioned that we will be a partner in two wells on South Grevling and also one well on Yme, in addition to the production wells going on in P1 project on Yme.
To grow the company organically is not sufficient. We want to make OKEA significantly bigger than we are today, and we are, of course, actively pursuing M&A opportunities that we see on the Norwegian shelf. We think that the dynamics we have seen the last few years is just continuing in restructuring and company pulling out. Being one of the few, which is our main asset, we are one of the very, very few field operators with the field operating competence on the Norwegian shelf, which is completely dominated by Equinor, of course. That is something that we will capitalize on, going forward with respect to M&A opportunities. That concludes our presentation.
Okay. Thank you, Erik. We move over to the Q&A session. Raise your hand and Okay, Teodor.
Thank you. Teodor Nilsen, SpareBank 1 Markets. First of all, on the 2020 production guidance, how much contribution have you included from Yme?
Less than you think.
Have you included anything in Q3 at all?
No.
Okay.
In the estimate.
Okay.
We definitely expect production start in Q3.
Okay. Second question on Grevling. As far as I understand, the two exploration wells in the south are very important for the economics. Let's assume that there won't be any discoveries there at all. Is Grevling commercial on a standalone basis without any discoveries?
As we see it today, Grevling is commercial on a standalone basis, but it has inherited the risk. In a P50 sense, it's definitely a commercial project. With smaller projects like Grevling, we talk about less than 50 million bbl. A lot depends on how the lease of the production unit, et cetera, is organized. Even in that case, the P90, the uncertainty level, the very certain part of what we have at the oil prices we look at has a negative value. It's also a philosophical question, but will you spend another NOK 500 million to NOK 1 billion to do a test production and find out whether it is worthwhile doing or not? Grevling contains 200 million bbl of oil. It's a very low recovery rate in the way we plan to produce it.
Then you can find out, well, it is more than we thought, so we can actually develop it, but then you have lost that money. We will come back to how we can improve the economy on Grevling to make it even profitable at the low scenario reserves that we have. We're working with Halliburton, and we are also will give Knut the challenge to really go through some of the cost estimates and the uncertainties on the development in that respect.
Okay. Just final question from me. You talked about M&A. Could you just briefly discuss how you view the M&A market on NCS now, and whether you will focus on the M or A or both going forward? Thank you.
Of course, we look at both. Because buying assets is not straightforward and easy. Those who sell assets, you don't get any for free. It's basically, no one is at a distressed asset. We think that in the market of late-life fields, for example, as Draugen and as other field is a market that is interesting to OKEA. Of course, you have an ongoing production, which is also easier to finance than go in and buy asset directly. We look at all kind of possibilities on the shelf. Obviously, some deals, as you know, are too big for us. There are some we don't even look at.
Thank you.
Halvor Nygård from SEB. Returning a bit to Yme, how confident are you on the summer 2020 startup targeted date? What kind of timeframe do you foresee from sail away, which Maersk is saying modifications work will be done in late Q2? The lead time from sail away to start up with the hookup and commissioning, and also knowing and noticing that Maersk is saying they expect limited EBITDA contribution from Maersk Inspirer in 2020?
Of course, Maersk, they don't get paid before we have produced a certain number of hours. They must take their kind of precautions. The original plan for the hookup process was three months work. With the rig out there now, which is actually at present going to take the plugs out and prepare that, there's a lot of work done. The operator said that we are mitigating a lot of the time that was supposed to be done by Maersk Inspirer. They have not submitted to the license a revised plan yet because it is not fully concluded how much offshore work will actually be completed before Maersk Inspirer leave the yard.
What we have been focusing on in the partnership in the license is actually to now finalize the work on Egersund in order to get the rig out before the summer so we can take advantage of the summer seasons in terms of the hookup work. The operator will get back to how many weeks the actual hookup process will be planned for. We have no information about that except that we expect it to be significantly less than the three months that was the plan when the PDO was submitted.
Okay, thanks.
Any further questions? No. I thank you all for joining and.
Okay. Thank you very much, and have a good day