Welcome to this third quarter presentation from OKEA. We will, following this presentation, also have a Q&A session, which you can log on to. The third quarter has been a challenging quarter for a lot of industries, our industry included. 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 Draugen nor onshore in our organization. We have had an excellent performance. Also, the turnaround that we have had on Draugen 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 Yme do impact the net results of the company, as Birte will present soon.
We are positioned for growth, and we will just return to our future opportunities following Birte's presentation of the financial results. I leave the word to Birte to present our figures.
Thank you, Erik. Despite the very high production reliability of 99%, both at Gjøa and at Draugen for the quarter, produced volumes were 27% lower than last year due to the planned shutdowns at Gjøa and Draugen. During the quarter, we had 20 days of downtime at Draugen due to the turnaround, which started on 23rd of June, and production was back up again on 21st of July. In addition, we had 70 days of downtime at Gjøa in relation to tie-in projects. For Gjøa, we will be compensated for the deferred production when Duva and Nova comes on stream. Sold volumes were 15% compared to last year, mainly due to the planned maintenance and a general decline at Gjøa. 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 were still 27% lower than last year. The result of the lower volume sold and the lower price of petroleum products was a reduction in revenue of 40% compared to last year, ending at NOK 365 million . When accounting for the effect from the May cargo at Draugen, the petroleum revenues recognized in the quarter amounted to 308 million NOK. 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 arrangements, 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, NOK 321 million , which mainly consists of the petroleum revenue of NOK 308 million, as outlined on the previous slide, and also tariff revenue from Gjøa. Production expense amounted to NOK 154 million or equivalent to NOK 180 a barrel compared to NOK 80 last year. The main driver of the increase per barrel was the lower produced volumes, mainly due to the planned shutdowns. Impairments amounted to NOK 572 million, mainly relating to Yme, 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 NOK 16 million in exploration expense, mainly relating to field evaluation at Hasselmus as the activity level is picking up on the project. Net SD&A cost to OKEA was NOK 4 million. This is a bit lower than usual, partly due to cost-cutting initiatives that have been implemented and higher allocation of cost during the quarter, following a year-to-date true up. Net financial items represents a gain of NOK 76 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 NOK 508 million, which results in an effective tax rate of 96%. Also in relation to the third quarter, we observed some impairment indicators. Let's start on the positive side.
Improved market conditions resulted in a positive headroom at Draugen and Gjøa compared to second quarter. The improved market conditions were not enough to compensate for the delay and the CapEx increase for the Yme new development project as we announced earlier this month. These adverse changes reduces the recoverable amount on Yme, which impacts the third quarter results for OKEA significantly. In total, we recognize an impairment of NOK 572 million, divided between two assets, oil and gas properties relating to Yme of NOK 125 million, plus a deferred tax effect of NOK 444 million. In total, NOK 569 million relating to Yme, and technical goodwill relating to Ivar Aasen of NOK 4 million. Of the total NOK 572 million recognized in impairment, the impact on equity, the post-tax impact, amounted to NOK 129 million.
As for the cash development, the cash at the start of the quarter was in excess of NOK 900 million, cash at the end of the quarter was just shy of NOK 900 million. Cash from operating activities amounted to NOK 216 million, taxes received amounted to NOK 154 million. 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 is amounted to roughly NOK 130 million. Cash to investment activities amounted to NOK 323 million mainly related to Yme, the P1 project at Gjøa, and the Draugen gas import project. Interest paid amounted to NOK 28 million relates to OKEA 02.
During the quarter, we also did a partial buyback of OKEA 02, amounting to a cash effect of NOK 53 million for a buyback equivalent to $6.2 million in nominal value. The world has changed quite dramatically over the year, but we are now seemingly moving in the positive direction for our industry. We have started seeing the effect of already this quarter, the temporary tax amendments have significantly improved OKEA's financial position and is a trigger for a 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. For the existing financing under our two bond loans, we have secured a comfortable buffer to the covenant requirements until the end of 2021. The first maturity is in June 2023, and OKEA 03 matures in December 2024.
During the quarter, as mentioned, we bought back $6.3 million in OKEA 02 at a discount of 11%, which is an addition to the buyback of OKEA 02 earlier this year, total of $6.2 million, at a discount of approximately 23%. Finally, the organic growth case, which Erik will outline in further detail, is planned to take place without the need to issue more shares. On that note, I'll leave the word back to you, Erik. Thank you.
Thank you, Birte. 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, both the second quarter and third quarter are anomalies in this story, partly because of the COVID situation and the maintenance stuff, but also on Gjøa where there has been a modification because of tie-in projects. Our operation had, as I mentioned, no serious incidents, very high reliability when we have been in production. We have also completed the reduced production permit with the way we organized the turnaround. On Gjøa, we have had incidents concerning the production drilling on the P1 project, which PSA has announced that they will investigate. Apart from that, also the Gjøa operations operated by Neptune has gone very well, both in reliability and in terms of incidents.
OKEA is a proud producer of reliable and affordable energy. As you see on this graph, our reliability is quite impressive. We have had a change since we took over the Draugen field, where we have managed to empower people both in the operation center in Kristiansund and on board Draugen 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 Draugen, if we can maintain this kind of successful production going forward. We will, as announced, also look at the costs of operations, and we have already received a significant reduction in our operating cost, but we are embarking on a project where we look at additional savings going forward.
We will also, of course, work on the income side by trying to increase production, and we do that partly by regularity, of course. 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 Draugen, which will be a part of the lifetime extension of Draugen. We think it's very realistic that with the reservoir we have in Draugen, we can reach a 70% recovery rate. Of course, if we invest in more wells, et cetera, that will also impact the investment volumes as seen here. We would like to, again, remind investors and the audience about that the way we finance the purchase of both Draugen and Gjøa implies that Shell will cover the abandonment cost when that happened. Innovation is extremely important to OKEA.
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. We have this on the agenda all the time. One of the successful innovative project that we have just concluded is the way we run scale squeezes on Draugen, which is normally done by quite heavy supply vessels and service vessels. We challenged the organization, and they challenged themselves in a way to see, can this be done with a smaller vessel? Since we have Siem Pride on a long-term charter working for OKEA on Draugen, is it possible to utilize this vessel, which is significantly smaller than the normal vessel used for this kind of job? We managed to do that.
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 of one of the bigger vessels, and there's not enough beds on board to host everyone who would like to be on a vessel during such operations. Some of the activities has to be carried out from shore. For example, running the ROE was done from Bergen and not from the vessel. This has not been possible without the very good collaboration with our suppliers, and particularly in this case, Siem Offshore, Subsea 7, IKM, and others did contribute to this success.
Draugen energy supply is an issue that was addressed by Shell when they operated this. That is also on OKEA's agenda. From the start in 1993, there was no gas infrastructure at all on Haltenbanken, and Draugen gas was partly injected and partly used as a power supply for the Draugen field. Associated gas covered the energy need on Draugen up until 2018. Since 2018, we have used a mix of associated gas and diesel, and diesel was imported from shore, of course. Now we are turning from gas export, which used to be the case in the early 2000s, to gas import to Draugen.
That means that we import gas for fuel for our turbines and thereby replacing 54,000 tons of diesel up until the Hasselmus project which I will return to come on stream, because then we can use gas from Hasselmus as a supply for energy as well as export from Draugen. However, we are looking at another phase of energy supply for Draugen, 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 Aker Carbon Capture, a possibility of continue to use gas as a power supply, but combined with carbon capture systems. 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 Draugen during at least early next year.
The project that will be our first actual new development will be Hasselmus. It is a gas discovery just northwest of Draugen. This can be developed in a rather simple manner, so that the breakeven cost will be less than $30 a barrel, which is the kind of new norm for making development decisions. We expect the first gas to be on the platform by in early 2023. This was a project that was halted due to the COVID situation and the market turmoil that we saw in March. Due to the tax incentives that the Parliament passed in the summer, this project was restarted and we work now intimately with SIA, which is a joint venture between Subsea 7 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 Draugen, which has a very promising prospect called Calypso. This is a Neptune-operated license, and we're going to drill this one in early 2023 or mid-2022, sorry, and/or possibly in 2021. If a discovery is made here, a tie-in to either Njord or Draugen will be the development solution. We also acquired from Equinor, Equinor shares in a small gas discovery west of Gjøa or east of Vega, where we also are approved by the ministry or appointed by the ministry as operator for this license. We will work together with the partners now for the next few months to find a development solution.
The only reasonable solution to develop such a small gas discovery is to connect to already existing pipeline between Vega and Gjøa, hence, get capacity on Gjøa to develop this. We were just appointed operator on this field, so we embark on this project as we speak. We have no further details about the future of Gjøa. 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 Yme 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. This is also a project that is impacted by the COVID restrictions.
It's not much work that remains, so we have hope that Repsol manage to gather with Aker Solutions and Maersk to have a sail away around the turn of into the new year, and that we will see production from Yme finally in the second half of next year. When Yme comes on stream, it will have a significant contribution to OKEA's income and add another 7,000 barrels a day to us. It is an important project when it finally gets there. To end this presentation, I'll just have one slide showing what we think the future look like for OKEA. Here you see in earthly colors the project that we have embarked on, where we have decisions in the partnership to move to developments, together with the fields that's already in production, of course.
You see that we will grow production during the next couple of years from the ongoing projects. 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. That shows quite an optimistic and a good picture going forward. This is without any new licenses acquired through M&As or through licensing rounds. This is what we have here already. These projects, as Birte already pointed out, can be carried out with our present financing and no new equity is required to actually realize this kind of production growth. We have continued to demonstrate our strong operator capabilities with the performance we have on Draugen.
We are confident that we will reach what we have already announced, a production level of between 14,000 and 15,000 barrels a day on average for this year. Also the CapEx estimate is close to what we announced, but the overrun and delays on Yme, we will experience an investment growth of NOK 100 million in that respect. 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, we can open up for a Q&A. Thank you. We have one question on the web call that is from Jørgen Torstensen., and that is, how much do you expect to pay/receive in cash tax for fourth quarter 2020, first quarter 2021, second quarter 2021 at $40 barrels of oil? Yeah. We open up for questions. We have one question on the web call that is from Jørgen Torstensen., that is, how much do you expect to pay/receive in cash tax for fourth quarter 2020, first quarter 2021, and second quarter 2021 at $40 barrels of oil?
Yeah. Basically our estimate of tax was calculated in June based on our best estimate. We have now received one payment in this quarter. As mentioned, we will receive two payments in the next quarter, less a settlement of 2019 [audio distortion] of NOK 130. We have another payment in first quarter next year and two more payments in second quarter next year. Of course, the final number will depend on the actual oil price, the total CapEx and the timing of listings and so on. As of today, the NOK 924 for 2020 is our best estimate.
A question from Halvor Nygård from SEB. We have two questions. The first one is, with the new COVID-19 restriction at the Norwegian yards, do you see a risk of [audio distortion] first oil slipping into 2022?
Not really. We are almost finished, and there's quite a good headroom during the winter. I think they may delay the work leaving the yard as late as April, May before they actually slip into 2022. I think that would be a quite extreme scenario, but you never know.
Mm-hmm. Further from Halvor: how should we think about next year's CapEx project? Is it likely to decrease versus 2020 as CapEx on Yme is rolling off?
I think it's a bit preliminary to guide on next year's CapEx, but this is something that we will revert to in relation to fourth quarter.
The budget for the licenses is not approved yet, so we will receive those in later November, early December.
We have a question from Teodor in SB1. Why do you buy back bonds? Lack of investment opportunities or other?
Because they are cheap.
We have been able to buy back at a discount and delever the company. We have kept some on our books and some we have canceled. The $ 6.2 million that we acquired early this year has been canceled, and the $ 6.3 million that we bought this quarter remains on our books.
A follow-up there from Teodor on how this compare to required rate of return from your project?
We have provided our discounts that we acquired [audio distortion]. We have now excess liquidity that we have used to buy back bonds and delever the company. We still have capital to take on new projects.
From Teodor, regarding first oil it seems like it's scheduled in 2024?
Yes. It is, Grevling is partly depending on how good we are on oil price, of course, but also on. Possibility to add new reserves or actually find a bigger [audio distortion] there on the Grevling. With the billing time and the tentative agreements that we have with the yards, et cetera, and we managed to submit the PDO during 2022, start-up in 2024 is feasible.
One question from Anders Holte, production for Q4 2020. How confident are you to meet your current guidance for 2020?
I would say that we're quite confident in that. We are already ahead and have accounted for production cost measures already. With a solid availability on our production, we're quite confident that we will reach our guidance.
That was the question from the type-in on the webcast. Operator, are there any questions on the conference call?
Thank you. Once again, 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 make sure your mute function is turned off to allow your signal to reach our equipment. Again, press star one to ask a question. We'll now take our first question from Anders Holte from Kepler Cheuvreux.
Good morning, guys. Thanks for taking the follow-up to the Q&A on the web. It's just a question regarding your slide on the long-term production outlook. Just curious to see how much of that production profile you consider to be commercial as of today. How much is then to be classified as contingent out of your outlook towards 2027?
I think all of them are realistic, but the one that is most fragile to oil prices, or kind of commercial framework is the Grevling development. We have managed to reduce the break-even cost now below $40, which was the target when the oil price was $60, $65. With the present oil price outlook that we use, we have to push that down further to $30. The way we can do that is by additional reserves. I think technically everything is okay. We have two wells coming in south of Grevling. We're also looking at opportunities to utilize the production unit on other discoveries. To confirm that up, we will not have the final answer to that before the spring, summer next year. Apart from Grevling, all the other projects looks quite promising in our project.
They are not mature enough to pass any decision gates in the license this year. That's why we separate them from the other projects where we actually have moved forward formally. In one sense, they [audio distortion] , but these are actual discoveries and very concrete plans for confirmed resources. That is, of course, distinguish this from just having plans or developing things in your exploration portfolio. We are not adding any successes in the exploration portfolio into this forecast.
Thank you.
We'll now take our next question from Teodor Nilsen of SB1 Markets. Please go ahead.
Good morning, thanks for taking my questions. I have a couple of questions on the Yme, and one follow up on the one question that I posted. First on Yme, you said that you expect, or it stated on slide 20 that you expect 4,900 barrels production net to OKEA the first year of production. Now looking at slide 22, it looks like the Yme contribution is less than 4,900. It's probably resulting in net [audio distortion] there I don't understand. Please clarify what numbers should we expect in 2021?
In 2021, the forecast is that the ramp-up on Yme is slower than in the PDO, to say it that way. The plan there is to drill a sidetrack to get the better injectivity of the associated gas. There is a limitation the first month of production. The ramp up is lower. That's why with the present plan, the 2021 production is lower than the plateau that we expect in 2022.
I just didn't understand it because it said 4,900 bpd , the first year of production. Is that net to OKEA?
[crosstalk]
This correspond to the one slide 22. I just wonder which numbers is the correct one?
It's distributed for 12 months, isn't it? It is not the actual production during production. That is net production to OKEA, the first year distributed as if it was production from 1st of January.
Okay, understood.
Starting first of August.
Okay. Yeah, understood. Just on buybacks, of course, solid cash position and you are in a good position to buy back. I am just curious, how does the implied yield that we see on the bottom side, the buyback, how does that number compare to your required rate of return for new projects when you look at delivering [audio distortion] and the other opportunities in your portfolio?
We have now the cash draw on the investment profile on the older projects, including those in and the Gjøa project on Draugen and Hasselmus. We have substantial cash flow to cover those. Within our cash flow, we actually have the repayment of the bond as just a timing issue. If we can buy bond before, it does not really affect our cash situation following the repayment of bond number two.
Yeah. The yield is for the latest buyback, this is in excess of 13%. As Erik said, this is debt that would have matured in mid-2023. We are using our excess cash to buy back some of it early and then save interest payments and so on.
You interpret that as the [audio distortion] for project is below 13%, or is that far-fetched?
No, that is not the correct interpretation. Now we have capital to both. We do not need new equity to manage our organic growth case. Rather we have used some of our excess cash to buy back some of the bonds early. It's not the correct interpretation to say that that is equal to our return requirement on new projects.
Okay, thank you.
Yeah. That money is not competing with any project money, to say it that way.
It 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, I think we did a good Q&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. All in all, thanks for joining and watching and also asking questions. Thank you.