Okea ASA

OSE:OKEA

Earnings Call Transcript 2020-Q3

[Erik Haugane, Founder & CEO]

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. 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 Draugen or onshore in our organization. So we have had an excellent performance. And also, the turnaround that we have had on Draugen has been perform 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 Yme do impact the net results of the company, as Birte will present soon. So we are positioned for growth and we'll just return to our future opportunities following Birte's presentation of the financial results. So then I'll leave the word to Birte to present our figures.

[Birte Norheim, Chief Financial Officer]

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. So 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. And 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 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 volumes 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 NOK 308 million. 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 productions for approximately half of the after-tax oil exposure for the following 3 quarters at an average strike of $40 a barrel. This reduces the downside risk relating to down -- 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 refer 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 SG&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 and let's start on the positive side. Our improved market conditions resulted in a positive headroom at Draugen and Gjøa compared to second quarter. However, 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 recognized an impairment of NOK 572 million, divided between 2 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 and cash at the end of the quarter was just shy of SEK 900 million. Cash from operating activities amounted to NOK 216 million, and taxes received amounted to NOK 154 million. And that relates to the first of 6 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 2 such payments and also pay the final settlement for 2019, which amounts to roughly NOK 130 million. Cash to investment activities amounted to NOK 323 million and mainly related to Yme, the P1 project at Gjøa and the Draugen gas import project. Interest paid amounted to NOK 28 million and relates to OKEA02. And during the quarter, we also did a partial buyback of OKEA02, 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. As 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. As for the existing financing under our 2 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 OKEA03 matures in December 24. During the quarter, as mentioned, we bought back $6.3 million in OKEA02 at a discount of 11%, which is an addition to the buyback of OKEA02 earlier this year, total of 6.2, at a discount in the -- 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.

[Erik Haugane, Founder & CEO]

Thank you, Birte. 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 anomalies in this story, partly because of the COVID situation and the maintenance stop, but also on Gjøa, 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 Gjøa, 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. OKEA is a proud producer of reliable and affordable energy. And as you see on this graph, our reliability is quite impressing. We have had the -- a change since we took over the Draugen field, where we have managed to empower people, both in the operations center in Kristiansund and onboard 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, that 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 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 where -- which we target to reach during the next year or 2. We also see the opportunity of increasing production from Draugen, which is -- will be a part of the lifetime extension of Draugen. And we think it's very realistic that with the reservoir we have in Draugen, we can reach a 70% recovery rate. But of course, if we invest in more wells, et cetera, we'll -- 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 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. And we are -- we 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 Draugen, 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 Siem Pride on our long-term charter working for OKEA on the Draugen, is it possible to use, utilize this life 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 of one of the bigger vessels. And there's not enough beds on board to host everyone who would like to be on the 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 a very good collaboration with our suppliers. And particularly in this case, CM 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 and that is also on OKEA's agenda. From the start in 1993, there was no gas infrastructure at all on [ Halton ] Bakken, and Draugen gas was partly injected and partly used as a power supply for the Draugen field. So associated gas covered the energy need on Draugen up until 2018. And since 2018, we have used a mix of associated gas and diesel with -- 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 Draugen. That means that we import gas for fuel for our turbines, and thereby replacing 55 -- 54,000 tons of diesel up until the Hasselmus project, which will return to common 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 face of energy supply for Draugen, and that is the possibility of taking electricity from shore, with as its operational benefits as well as reduced CO2 taxes for OKEA. We are also studying, together with Aker Carbon Capture, a possibility of us to 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 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, 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 2023. 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 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, tie into either Njord or Draugen is -- will be the development solution. We also acquired from Equinor, Equinor shares in small gas discovery west of Gjøa 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 the already existing pipeline between Vega and Gjøa, hence, have -- get capacity on Gjøa to develop this. But we were just appointed operator on this field, so we've embarked on this project as we speak. So we have no further details about the future of Gjøa. 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 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. And this is also a project that is impacted by the COVID restrictions. But there's not much work that remains, so we have hoped that Repsol managed, together with Aker Solutions and Maersk, to have a sale away around the turnover there 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 will add another 7,000 barrels a day 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 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. 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 optimistic and a good picture going forward. And this is without any new licenses acquired through M&As or through licensing rounds. So this is what we have here already. And 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. And we are confident that we will reach what we have already announced, a production level of between 14,000 and 15,000 thousand 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 Yme had to -- will -- we will experience an investment growth of about NOK 100 million 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.

[Unknown Executive]

Okay. Operator and then we can open up for a Q&A. Thank you. We have one question which is 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 '20, first quarter '21, second quarter '21 at circa $40 of oil -- barrels of oil?

[Birte Norheim, Chief Financial Officer]

Yes. So basically, our estimated tax was calculated in June based on our debt investment. And we have now received one payment in this quarter. And as mentioned, we will receive 2 payments in the next quarter, less a settlement of 2019 to us of [ 130 ]. And then we have another payment in the first quarter next year and 2 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 leasing and so on. But as of today, the 924 for 2020 is our best estimate.

[Unknown Executive]

Okay. And then question from Halvor Nygård from SEB. And we have 2 questions. The first one is, with the new COVID-19 restriction at the Norwegian yards, do you see a risk of even first oil slipping into 2022?

[Erik Haugane, Founder & CEO]

Not really. We are almost finished and there's quite a good headroom during the winter. So I think they will be late work leaving the yard, as late as April, May before they actually slip into 2022. So I think that's the -- that definitely will be a quite extreme scenario, but you never know.

[Unknown Executive]

Further from Halvor, how should we think about next year's CapEx budget? Is it likely to decrease versus 2020 as CapEx on Yme is rolling off?

[Birte Norheim, Chief Financial Officer]

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.

[Erik Haugane, Founder & CEO]

The budgets for the licenses is not approved yet, so we will receive those in -- later in November, early December.

[Unknown Executive]

Then we have a question from Teodor in SB1. Why do you buy back bonds? Lack of investment opportunities or other?

[Erik Haugane, Founder & CEO]

Because they are cheap.

[Birte Norheim, Chief Financial Officer]

So we have been able to buy back at a 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 early this year has been canceled. And the 6.3 that we bought this quarter, it remains on our books.

[Erik Haugane, Founder & CEO]

And a follow-up there from Teodor. And how does this compare to required rate of return for new projects?

[Birte Norheim, Chief Financial Officer]

We have provided our discounts that we acquire [ debt ], but we have now excess liquidity that we haven't used to buy back once and we use to [ delever ] the company. And we still have capital to take on new projects.

[Unknown Executive]

From Teodor, regarding first oil, it seems like it's scheduled in 2024?

[Erik Haugane, Founder & CEO]

Yes, it -- again here, it is partly depending on our output on oil price, of course, but also on possibility to add new reserves or actually find a bigger [ resource ] [indiscernible]. But with the building time and the tentative agreements that we have with the yards, et cetera, we managed to submit the PDO during 2022, then 2024 is feasible.

[Unknown Executive]

One question from Anders Holte, production for Q4 '20. How confident are you to meet your current guidance for 2020?

[Birte Norheim, Chief Financial Officer]

I would say that we are quite confident in that. We are already ahead and have accounted for the production cap measures already. So with the solid availability on our production, we're quite confident that we will reach our guidance.

[Unknown Executive]

That was the question from the -- typed in on the webcast. Operator, are there any questions on the conference call?

[Operator]

[Operator Instructions] And we'll now take our first question from Anders Holte from Kepler Cheuvreux.

[Anders Torgrim Holte, Equity Research Analyst]

It's just a question regarding your slide on 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 reclassified as contingents out of your outlook towards 2027?

[Erik Haugane, Founder & CEO]

Yes. 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 breakeven cost now below $40, which was the target when the oil price was $60, $65. And -- but with the present oil price outlook at [indiscernible], we have to push that down further to $30. And the way we can do that is by additional reserves. So I think every -- technically, everything is okay. We are 2 -- have 2 wells coming in south of Grevling. And we're also looking at the opportunities to utilize the production unit on other discoveries. So to [ store ] that up there, we will not have the final answer to that before the spring/summer next year. But apart from Grevling, all the other projects looks quite promising in our projects, but they are not mature enough to pass any decision gates in the licenses yet. That's why we separate them from the other projects where we actually have move forward formally. So [ one ] sense there [indiscernible] on the risk, but these are actual discoveries and very concrete plans for a current -- for resources. So that is, of course, distinguished this from just having a plan for or developing things in your exploration portfolio. So we have not added any successes in the exploration portfolio into this forecast.

[Operator]

And we'll now take our next question from Teodor Nilsen of SB1 Markets.

[Teodor Sveen-Nilsen]

A couple of questions on the -- then a follow-up on the bond question that point. First, on Yme, you said that you expect rate on Slide 20, that you expect 4,900 barrels production network at the first year of production. And then I look at Slide 22, it looks like the Yme contribution is less than 4,900. So it's probably something [indiscernible], I don't understand. So can you clarify? What number should we expect in 2021?

[Erik Haugane, Founder & CEO]

Technically, that's wrong. The forecast is that the ramp-up on the Yme is slower than in the PDO to say -- that's right, because the plan there is to drill a [ 5 ] jack to get the better injectivity of the associated gas. So there is a limitation, the first month of production. So the ramp-up is lower, so that's why with the present plan, the '21 production is lower than the plateau that we expect in '22.

[Teodor Sveen-Nilsen]

I still didn't understand, because it says 4,900 barrels per day, the first year of production. Is that net all here?

[Erik Haugane, Founder & CEO]

[indiscernible]

[Birte Norheim, Chief Financial Officer]

[indiscernible]

[Teodor Sveen-Nilsen]

Let's correspond to the one on Slide 22, so I just wonder which numbers is the correct one.

[Erik Haugane, Founder & CEO]

It's distributed for 12-months business. So it is not the actual production on the -- during production. That is net production to OKEA, the first year distributed as if it was production from 1st of January, starting 1st of August.

[Teodor Sveen-Nilsen]

Okay, okay. Understood. And then just on buybacks, of course, have a solid cash position, you're in position to buy back. I'm just curious, how does that imply yield? There we still [indiscernible] buy back, how does that number compare to your required rate return for new projects when you look at delivering [indiscernible] and the opportunities in portfolio?

[Erik Haugane, Founder & CEO]

But we have now the cash draw -- or the investment profile on all the projects, including both Yme and the Gjøa project on Draugen and Hasselmus. We have substantial cash flow to cover those. So within our cash flow, we actually have the repayment of the bond as just a timing issue. So if we can buy one before, it does not really affect our cash situation following the repayment of bond #2. But, Birte?

[Birte Norheim, Chief Financial Officer]

So the yield is -- for the maintenance buyback on Gjøa, it's in excess of 13%, and that's the area [indiscernible] would have matured in mid-2023. And we are using our excess cash to buy back some of it early and then save interest payments on -- and so on.

[Teodor Sveen-Nilsen]

So if you interpret license -- [indiscernible] the required return from projects is below 13%, or is that farfetched?

[Birte Norheim, Chief Financial Officer]

No. That -- it's 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 had used some of our excess cash to buy back some of the bonds early. So it's not the correct interpretation to say that, that is equal to our return requirement on new projects.

[Erik Haugane, Founder & CEO]

So that one is not completed with any project, am I to say it that way.

[Operator]

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.

[Unknown Executive]

Okay. Then I think it was 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 we can. But all in all, thanks for joining and watching and also asking questions. Thank you.