Welcome to this Third Quarter Presentation from OKA. We will, following this presentation, also have a Q and A session, which you can log on to. The third quarter has been a challenging quarter for a lot of industries, our industry included. But our performance despite certain constraints, has been very well. We have had no serious accidents, and we have handled the COVID situation very well.
We have had no incidents neither on Drogin nor onshore in our organization. So we have had an excellent performance. And also, the turnaround we have had on Rogen has been performed very well. Financially, we are quite robust. We have a good cash situation.
We have had a reasonably good EBITDA. However, the cost overruns and delays on the UEM do impact the net results of the company as bit will present soon. So we are positioned for growth, and we will just return to our future opportunities following Bitte's presentation of the financial results. So then I leave the word to Bitte to present our figures.
Thank you, Eric. Despite a very high production reliability of 99% both at and at Droggen for the quarter, produced volumes were 27 lower than last year due to the planned shutdowns at Jura and Drogin. So during the quarter, we had twenty days of downtime at Drogin due to the turnaround, which started on June 23, and production was back up again on July 21. In addition, we had seventy days of downtime at Jura in relation to tie in projects. And for Jura, we will be compensated for the deferred production when Druva and Nova comes on stream.
Sold volumes were 15% compared to last year, mainly due to the planned maintenance and a general decline at Even if the oil price has recovered somewhat compared to second quarter, it should be no surprise that realized prices are down compared to last year. Realized price for liquids were 32% lower than last year by a reduction from $56 a barrel to $38 a barrel. We have seen some improvements in the pricing also for gas over the recent months. However, for the quarter, the realized price for natural gas was still 27% lower than last year. The result of the lower volumes sold and the lower price of petroleum products was a reduction in revenue of 40% compared to last year, ending at million.
When accounting for the effect from the May cargo at Rugen, the Petroleum revenues recognized in the quarter amounted to $3.00 €8,000,000 As mentioned, the market for Petroleum Products has improved compared to second quarter, but the outlook remains uncertain. As of today, we have entered into hedging arraignments, put options for approximately half of the after tax oil exposure for the following three quarters at an average strike of $40 a barrel. This reduces the downside risk relating to oil price for the coming period. Moving on to the income statement and starting with the operating income, million, which mainly consists of the Petroleum revenue of NOK308 million as outlined on the previous slide and also tariff revenue from Joao. Production expense amounted to NOK154 million or equivalent to NOK180 a barrel compared to NOK80 last year.
The main driver of the increase per barrel was the lower produced volumes, mainly due to the planned shutdowns. Impairments amounted to CHF572 million, mainly relating to EMA, due to increased capital expenditure as well as a revised estimate in expected time to start up. We will revert to this also on the following slide. Exploration and operating expense consists of CHF16 million in exploration expense, mainly relating to field evaluation at Hasselmooth as the activity level is picking up on the project. Net SG and A cost to OKEA was £4,000,000 This is a bit lower than usual, partly due to cost cutting initiatives that have been implemented and higher allocation of costs during the quarter following a year to date true up.
Net financial items represents a gain of million and mainly relates to unrealized foreign exchange gains relating to the dollar nominated bond loans as NOK strengthened by 3% to the dollars during the quarter. Taxes had a positive contribution of CHF508 million, which results in an effective tax rate of 96%. Also in relation to the third quarter, we observed some impairment indicators. And let's start on the positive side. Improved market conditions resulted in a positive headroom at Droggen and Jura compared to second quarter.
However, the improved market conditions were not enough to compensate for the delay and the CapEx increase for the EMEA new development project as we announced earlier this month. These adverse changes reduces the recoverable amount on EMEA, which impacts the third quarter results for OKEA significantly. In total, we recognized an impairment of £572,000,000 divided between two assets: oil and gas properties relating to EMA of CHF125 million plus a deferred tax effect of CHF444 million, in total CHF569 9 relating to EMA and technical goodwill relating to Eva Rosson of GBP 4,000,000. Of the total GBP $572,000,000 recognised in impairment, the impact on equity, the post tax impact, amounted to GBP 129,000,000. As for the cash development, the cash at the start of the quarter was in excess of CHF900 million and cash at the end of the quarter was just shy of CHF900 million.
Cash from operating activities amounted to £216,000,000 and taxes received amounted to £154,000,000 And that relates to the first of six installments for 2020 that follows from the temporary tax regulations where taxable deficits are refunded through negative installments. In the fourth quarter, we will receive two such payments and also pay the final settlement for 2019, which amounts to roughly £130,000,000 Cash to investment activities amounted to £323,000,000 and mainly related to IMA, the P1 project at Jura and the Drogin gas import project. Interest paid amounted to GBP28 million and relates to OKEA02. And during the quarter, we also did a partial buyback of OKEA02 amounting to a cash effect of £53,000,000 for a buyback equivalent to $6,200,000 in nominal value. The world has changed dramatically over the year but we are now seemingly moving in the positive direction for our industry.
As we have started seeing the effect of already this quarter, the temporary tax amendments have significantly improved OKA's financial position and is a trigger for our revised assessment of profitable projects. It improves our liquidity position over the next year significantly and improves project economy and liquidity for qualifying projects also for some time going forward. As for the existing financing under our two bond loans, we have secured a comfortable buffer to the covenant requirements until the 2021. The first maturity is in June 2023 and OKEA three matures in December 2024. During the quarter, as mentioned, we bought back $6,300,000 in OKEA at a discount of 11%, which is in addition to the buyback of OKR02 earlier this year, a total of $6,200,000 at a discount of approximately 23%.
And finally, the organic growth case, which Erik will outline in further detail, is planned to take place without the need to issue more shares. And on that note, I'll leave the word back to you Erik. Thank you.
Thank you, Bitte. And now to operations. As already mentioned, we had a lower production in the third quarter than the third quarter last year. And here, you see the development. However, the both the second quarter and third quarter are anomalous in this story, partly because of the COVID situation and the maintenance stop, but also on Jura where there has been a modification because of tie in projects.
We have in our operation had, as I mentioned, no serious incidents, very high reliability when we have been in production. And we have also completed the reduced production permit in with the way we organized the turnaround. On Eurowan, we have had incidents concerning the production drilling on the P1 project, which PSA has announced that they will investigate. But apart from that, the also the new operations operated by Neptune has gone very well, both in reliability and in terms of incidents. OKR is a proud producer of reliable and affordable energy.
And as you see on this graph, our reliability is quite impressing. We have had a change since we took over the Droggen field, where we have managed to empower people both in the operations center in Kristansson and onboard Djoggen, of course, such that we have increased regularity significantly, as you can see on this graph. That will also contribute, of course, to the lifetime of Djoggen that if we can maintain this kind of successful production going forward. We will, as announced, also look at the cost of operations. And we have already embarked have received a significant reduction in our operating costs, but we are embarking on a project where we look at additional savings going forward.
And we will also, of course, work on the income side by trying to increase production, and we do that partly by regularity, of course. And you see the figures here, which we target to reach during the next year or two. We also see the opportunity of increasing production from Droogen, which is will be a part of the lifetime extension of Droogen. And we think it's very realistic that with the reservoir we have in Droogen, we can reach a 70% recovery rate. Because if we invest in more wells, etcetera, that will also impact the investment volumes as seen here.
And we would like to again remind investors and the audience about that the way we financed the purchase of both Droggen and Joa implies that Shell will cover the abandonment cost when that happened. Innovation is extremely important to OKR. It is through innovation that we can have a higher reliability on production and not least a longer lifetime and a higher recovery rate from the fields that we operate. And we are have this on the agenda all the time. And one of the successful innovative project that we have just concluded is the way we run scale squeezes on Djerogen, which is normally done by quite heavy supply vessels and service vessels.
And we challenged the organization, and they challenged themselves in a way to see can this be done with a smaller vessel. And since we have Centimeters Pryde on a long term charter working for OKEA on Nodrogen, is it possible to utilize this vessel, which is significantly smaller than the normal vessel used for this kind of job? And we managed to do that. And by doing so, we actually reduced the cost of a scale squeeze to half the price of what is the common way to do it. Of course, on a smaller vessel, the storage area became quite busy, and the whole work has to be organized differently.
The crane capacity is just a fraction vessels. And there's not enough beds on board to host everyone who would like to be on a vessel during such operations. So some of the activities has to be carried out from shore. For example, the running the ROE was done from Bergen and not from the vessel. This is has not been possible without the very good collaboration with our suppliers, and in particular, in this case, Centimeters Offshore, Subsea seven, IKM and others did contribute to this success.
Djogen energy supply is an issue that was addressed by Shell when they operated this, and that is also on OKEA's agenda. From the start in 1993, there was no gas infrastructure at all on Haltenbachen and Drugen gas was partly injected and partly used as a power supply for the Drugen field. So associated gas covered the energy need on Dogen up until 2018. Since 2018, we have used a mix of associated gas and diesel, and diesel was imported from shore, of course. And but now we are turning the from gas export, which used to be the case in the early 2000s, to gas import to That means that we import gas for fuel for our turbines and thereby replacing 55,000 for 54,000 tonnes of diesel up until the Hasenwus project, which will return to common stream because then we can use gas from Hasenwus as a supply for energy as well as export from Dogen.
However, we are looking at another phase of energy supply for Dogen, and that is the possibility of taking electricity from shore, which has its operational benefits as well as reduced CO2 taxes for OKEA. We are also studying together with OKEA carbon capture, a possibility of continue to use gas as a power supply, but combined with carbon capture systems. So we will return to this project when they have matured, and we hope that we can conclude on what we do for the long term on Droggen during at least early next year. The project that will be our first actual new development will be Hasselmuss. It is a gas discovery just Northwest of Jergen.
This can be developed in a rather simple manner such that the breakeven cost will be less than $30 a barrel, which is the kind of new norm for making development decisions. And we expect the first gas to be on the platform by in early twenty twenty three. This was a project that was halted due to the COVID situation and the market turmoil that we saw in March. But due to the tax incentives that the parliament passed in the summer. This project was restarted, and we work now intimately with SEA, which is a joint venture between Subsea seven and OneSubsea and Aker Solutions to make this a successful development project.
We have also, during this quarter, acquired a share in a license Northwest of Droggen, which has a very promising prospect called Calypso. This is Neptune operated license, and we're going to drill this one in early twenty twenty three or mid-twenty twenty two, sorry, and or possibly in 2021. If a discovery is made here, a tie in to either Nord or Drogan is will be the development solution. We also acquired from Equinor, Equinor shares in small gas discovery West Of Joao or East Of Vega, where we also are approved by the ministry as or appointed by the ministry as operator for this license. And we will work together with the partners now for the next few months to find a development solution.
And the only reasonable solution for to develop such a small gas discovery is to connect to already existing pipeline between Vega and Joao, hence, get capacity on Joao to develop this. So but we were just appointed operator on this field, so we embark on this project as we speak. So we have no further details about the future of Ruhr. But it is our strategy to pick up on discoveries to see can they be developed or not, and this is an example of such an opportunity. The Imwe project, which should have been in production by now, is still, as you probably know, delayed.
The rig is not finished on the yard yet. It is scheduled to complete all the onshore activities by the end of the year. And this is also a project that is impacted by the COVID restrictions, but it's not much work that remains. So we have hoped that Repsol managed to, together with Aker Solutions and Maersk, to have a sail away around the turn of the into the new year and that we will see production from finally in the second half of next year. When Yume comes on stream, it will have a significant contribution to Okea's income and will add another 7,000 barrels a day net to us.
So it is an important project when it finally gets there. So to end this presentation, I'll just have one slide showing the what we think the future look like for OKA. Here, you see in earthly colors the project that we have embarked on, where we have decisions in partnership to move to developments together with the fields that's already in production, of course. And you see that we will grow production during the next couple of years from the ongoing projects. And in the more maritime colors, you see the discoveries that we have in our portfolio and where we have added the development plans for these discoveries as well.
And that shows a quite of optimistic and a good picture going forward. And this is without any new licenses acquired through M and As or through licensing rounds. Rounds. So this is what we have here already. And these projects, as Witt already pointed out, can be carried out with our present financing, and no new equity equity is required to actually realize this kind of production growth.
We have continued to demonstrate our strong operating capabilities with the performance we have on our Droogen. And we are confident that we will reach what we have already announced, a production level of between 14,015 barrels a day on average for this year. And also, the CapEx estimate is close to what we announced, but the overrun and delays on EMEA had to we experience an investment growth of NOK 100,000,000 in that respect. So with those remarks, I'll end this presentation. And thank you, everyone, for listening in.
And please make contact for further discussions and details. Thank you very much.
Okay. Operator, then we can open up for a Q and A. Thank you. We have one question on the web part. That is from Jurgen Thustenten.
And that is how much do you expect to pay slash receive in cash tax for fourth quarter twenty, first quarter twenty one, second quarter twenty one at $30 of oil barrels of oil. Yeah. And then we open up for for questions. We have one question on the webcast that is from Jagan Postenson. That is how much do you expect to pay slash receive in cash tax for fourth quarter twenty, first quarter twenty one, and second quarter twenty one at circa $13 barrels of oil.
Yes. So basically, our estimated tax was calculated in June based on our best estimate. And we have now received one payment in this quarter. And as mentioned, we will receive two payments in the next quarter, less a settlement of $20.19 through that of 130,000,000 And then we have another payment in first quarter next year and two more payments in second quarter next year. So of course, the final number will depend on the actual oil price, total CapEx and the timing
of liftings and so on.
But as of today, the $924,000,000 for 2020 is our best estimate.
Okay. And then have question from Harman Lia from SEB. How are you? 2%. The first one is with the new COVID meeting restriction at the Norwegian Yard.
Do you see a risk of even first oil slipping into 2022?
Not really. We we oh, we are almost finished, and there's quite a quite a good headroom during the winter. So I think they're they're they're they're working, leaving the art as late as April, May before they actually skip into 2022. So I think that's
Is it likely to decrease versus 2020 as CapEx on you may be rolling off?
I think it will be preliminary to guide on next year's CapEx, but this is something that we will revert to in for in relation to fourth quarter.
The budget for the license is not approved yet, so we will receive those in later November or December.
Then we have a question from Telgor in. Why do you buy back bonds? Lack of investment opportunities or other?
So we have been able to buy back at the discount and delever the company, but we have kept some on our books and some we have canceled. So the $6.2 that we acquired earlier this year has been canceled, and the 6,300,000,000.0 that we bought this quarter remains on our books.
And a follow-up, therefore, from
Taylor and how does this compare
to the required rate of return for new projects?
Well, we have provided our discounts that we require that, but we have now excess liquidity that we have used to buy back from some of other companies. And we still have capital to to take on new projects.
From Teluguet, Gavan first oil, it seems like it's scheduled in 2024.
Yes. It's Gavan here is a data partly depending on our how good we are on oil price cost, but also on possibility to add new reserves or actually find that be a resource for the on the gambling. But with the specific time and the tentative agreements that we have with the, etcetera, and we managed to submit the PDO during 2022, then Sotel '24 is feasible.
One question from Amr Solta. Production for Q4 twenty twenty, how confident are you to meet your current guidance for 2020?
I would say that we are quite confident in that. We are already ahead and have accounted for the production measures already. So with the solid availability on our production,
we're quite confident that we will reach our guidance. That was the question from the talking on the webcast. Operator, are there any questions on the conference call?
Thank And we'll now take our first question from Anders Holzik from Kepler Cheuvreux.
Good morning, guys. Thanks for taking the follow-up to the Q and A on the web. It's just a question regarding your slide in the long term production outlook. Just curious to see how much of that production profile do you consider to be commercial as of today? And how much is then to be classified as contingent out of your outlook towards 2027?
Yes. I think all of them are realistic, but the one that is most fragile to oil prices kind of commercial framework is with the gambling development. We have managed to reduce the breakeven cost now below 40, which was the target when the oil price was $60.65. And but with the present oil oil price outlook that we we use is we have to push that down further to to to 30. And the way we can do that is is by additional reserves.
So I think every technically, everything is is okay. We are two we have two wells coming in south of of Gambling, and we're also looking opportunities to utilize the production unit on on all the discoveries. So to start that up up, we will not have the the final answer to that before the spring, summer next year. But apart from gambling, all the other projects looks quite promising in in in our project, but they are not mature enough to pass any decision gates in in the license licenses yet. That's why we separate them from from the from the other projects where where we actually have moved forward formally.
There's no sense there. Thank you. There's a on the list that that that these are actual discoveries and very concrete plans for for a a current for resources. So that's that is, of course, distinguish this from from just having a plan from developing things in your exploration portfolio. So we are not adding any successes in the exploration portfolio into this forecast.
Thank you.
And we'll now take our next question from Theodore Nielsen of SB1 Markets. Please go ahead.
Good morning and thanks for taking my questions. I have a couple of questions on Ilham and want to follow-up on the bond question that I posted. First, on Ilham, you said that you expected or it stated on Slide 20 that you expect 4,900 barrels production net to carry first year on production. And then I look at Slide 22. It looks like the EMA contribution is less than 4,900.
So it's probably something next year, sir. I don't understand. So can you clarify what number should we expect in 2021?
In 2021, the the forecast is that the ramp up on email is is slower than than in the PDO to say. That's right. Because the plan there is to to really try to get the better in the activity of the associated gas. So there there is a limitation, the first month of production. So the ramp up is is lower.
So that's why with the present plan, the '21 production is lower than the plateau that we expect in 2022.
Just really didn't understand that you could expect 4,900 barrels per day, the first day of production. Is that net total there?
Yeah.
Yeah. So Just that's that's that's correspond to the one side '22. I just wonder which number is the the correct one.
The it's distributed for twelve months, isn't it? So so it is not the actual production on the during production. The business net production to OKR, the first year distributed as if it was production from January 1. Understood. Starting August 1.
Okay, okay, understood. And then just on buybacks, of course, there is solid cash position, and you're in a good position to buy back. I'm just curious, how does like the implied yield that we see on the bottom side of the buyback, how does that number compare to your required rate in return for new projects when you get everything added down and the other opportunities in the portfolio? But we have now the the the
cash flow or the investment profile on all the projects, including both in and the EOR project on Tergen and the Huselmuss. We have substantial cash flow to cover those. And so within our cash flow, we actually have the repayment of of the bond as as just a timing issue. So so if we can buy one before, it does not really affect or it has its cash situation following the repayment of bond number two. But the Yeah.
So the
yield is for the latest buyback, it's in excess of 13%. And as Eric said, this is debt that would have matured in mid-twenty twenty three, and we are using our excess cash to buy back some of it early and then save interest payments and so on.
So does this mean you need to open that that right? You can interpret it as the way that they require return for project is below 13%, or is that forecast?
No. That is it is not the correct interpretation. But now we have capital to both fund our like we have said, we do not need new equity to manage our organic growth case and rather we have used some of our excess cash to buy back some of the bonds early. So it's not a correct interpretation to say that that is equal to our return requirement on new projects.
Okay. Thank you.
Yes. So that one is not complete with any project. I wanted to say it that way.
Appears we have no further questions at this time. I'd like to hand the call back to our host for any additional or closing remarks.
Okay. Then I think we will conclude the Q and A session. A lot of questions, If you have any more questions, please reach out and get in contact with us and we'll try to answer as best we can. But all in all, thanks for for joining and and watching and also asking questions. Thank