Okea ASA

OSE:OKEA

Earnings Call Transcript 2022-Q4

[Svein Liknes, executive]

Good morning, and welcome to the presentation of the fourth quarter results from 2022 for OKEA. My name is Svein Liknes, I'm the CEO of the company. And together with me today, I also have Birte Norheim, our CFO, that will take you through the financials after I've given you an operational update.

Before I start, I would also like to remind you that you can ask questions using the link on our homepage. And you can also ask questions directly by calling in on the Q&A session after this presentation.

So last quarter then in one slide. The operations, we had continuous strong performance from Draugen, Ivar Aasen and Gjøa during the quarter. We did have some reduced plant availability on Yme and also on Nova that I will get back to a little bit later on.

That impacted some of the production last year in the quarter, and the production ended up with just shy of 20,000 barrels of oil per day. That is actually 2 months of production from the acquired Wintershall Dea assets. And if you divide it into the whole quarter, it would have been 21,500 barrels per day.

On our portfolio, the biggest events there, we completed the transaction with the Wintershall Dea that we spent quite some time last year on completing so that was completed on November 1.

We have proceeded on the Hasselmus project, which is a gas tieback to Draugen, which will have first gas in the fourth quarter of this year. And we have also sanctioned the electrification project for Draugen also together with the Njord asset because this is a joint project we are running both with OKEA and also Equinor for the Njord asset.

And we have added 4 licenses in the APA rounds for last year. In addition, at the tail end of December, we also made an agreement with the DNO where we entered the Brasse asset or Brasse license, which is just south of Brage for a potential development to Brage.

From a financial point of view, we do have a record high net profit after tax from the fourth quarter of NOK 324 million. We have, again, some impairments during the quarter of NOK 251 million, which is due to phasing of the production or the production efficiency we have put into 2023.

So there is no reduction. We are just moving it a bit to the right. Still expecting the [indiscernible] production from Yme during the mid of this year.

And we executed on dividend payments in the fourth quarter of NOK 1 per share, and we have also decided that we will also pay NOK 1 per share in Q1 this year. So that will then happen in March. So the intention that was communicated last year continues now into a firm decision for Q1 this year.

Main figures for the quarter. Serious incident frequency of 1.5. There is a slight creep there. We had 1 incident during that quarter on Draugen, and this is now also a combined metric based on both the acquired Wintershall Dea and also the previously known OKEA assets. So that is relatively stable.

We do have a CO2 emission of 21 kilos per BOE. That is an annual average because we only measure that annually. So that ended up with 21.

As I just mentioned, production during the last quarter was just shy of 20,000 barrels of oil per day equivalence. And the production expense, you can see, is NOK 258 million. And you can also see that we arrested the increase of production expenses that we have seen throughout 2022 on the fourth quarter.

The net cash flow from operations ended up at NOK 390 million, which is lower than the previous quarter, which is mainly related to NOK 1.2 billion paid in taxes over the last quarter. And as I mentioned as well, dividends were paid in Q4 and will continue to also be paid in Q1 2023 of NOK 104 million total.

Production volumes. If you look on the graph on the slide here, you will see that we are still evenly distributed between our assets. You can see the significance from Draugen and also the significance from our Gjøa operations. And one of the main drivers for us also to grow the company is that you are adding diversification to the portfolio and also reducing the sensitivity to fluctuations. So I'm happy to see that we have also added more production into this graph.

You can see the Nova came in, and we've seen an increase of Ivar Aasen, obviously, and also the Brage asset that you are seeing and also a slight increase from Yme during the quarter.

Very stable production efficiency in our assets. The scale here may fool you, but the scale goes from 100 to 80. So we are still on the top range in the 90s. Draugen had 2 unplanned events during the quarter with the production of power turbine.

Gjøa had also slightly reduced production efficiency of 3% lower than the previous quarter when they also had to change out the turbine. That turbine was changed in 1 week. I would call that world record performance.

And we've had very high production reliability also on the Brage. The Brage had a very long shutdown during September. And with these mature assets, when you have the wells that we have on Brage, it takes some time to dewater the wells and get the flowing again, hence, slightly lower production, but high production efficiency.

Ivar Aasen have had nothing but planned losses over the quarter, which was already planned. So very stable performance from Ivar Aasen.

Quick operational update going through the assets we actually have, starting on the top, our operated assets. Draugen, as I mentioned, the Hasselmus gas project, a very important project for us, is progressing in accordance with plan.

We completed the drilling last year. So we are now progressing that project for Q4 startup, which will then add 4,400 barrels of oil equivalent of gas to Draugen. And also, again, converted Draugen from a gas import of power generation to actually become a gas export again.

We have also executed on the -- handed in the plan for development and operation for the electrification of Draugen in December last year, big project that I will talk a little bit more of in more detail a bit later.

Brage asset acquired as part of the Wintershall Dea transaction. In addition to the assets itself, we also took over 150 new employees coming in from Wintershall Dea. So 100% of those in-scope accepted to actually join OKEA, which is key for our future success for Brage.

Brage is an asset where you need continuous infill drilling, something we are doing currently and will continue also to do. And at the end of last year, we also entered the Brasse asset or the Brasse license, which is just south of the Brage field at no cost to OKEA. So 50% in the Brasse field.

And basically, Brasse is 30 million barrels of oil, and it's only 13 kilometers away from Brage. So what we are doing now is we are leaning forward together with DNO which is still operator, but we are now in partnership with them to try to develop Brasse into Brage and also look at other solutions for the Brasse field.

We should not be in a position where we have to leave those kind of resources in the ground, and that is something we think OKEA can do something about.

Yme, asset, very important asset, continues to be a very important asset for us and also excellently operated by Neptune Energy, a very high production efficiency. We did have the Hamlet discovery in what we call the Njord last year. And we did not take a final investment decision on that. So there is still continuous evaluations of the resources, which is in the Hamlet discovery and if that can be produced and developed together with other resources in the area.

We also got a license very close the year in the APA rounds for 2022, which is operated by Neptune.

Ivar Aasen, we have increased our stake in Ivar Aasen now to, well, 9.23% in excess of that, very steady production from Ivar Aasen, successful infill drilling program and also Ivar Aasen was electrified during the Q4 of last year, which means that it has a good impact on our CO2 balance as well as in our portfolio.

Yme, still working interest of 15%. We're not going to repeat what we said during the last quarter there. We expect to have plateau production of Yme mid- this year, which will add 6,600 barrels of oil to OKEA. And they are drilling, and they are cleaning and they are handing over wells now from drilling to operations on the Yme field.

And Nova, last but not least, it was part of the Wintershall Dea transaction as well. In October, we experienced some problem with the water injection on Nova, which resulted in -- that we had to stop production for a while until the situation was assessed.

The operator of Wintershall Dea, explored the problem and also went in with some corrective work and managed to reestablish water injection just before the end of last year. So actually, water injection was resumed.

The pressure in the reservoir was also resumed, and production continued and still continues, but there will be 1 sidetrack on one of the water injection wells in Nova during 2023. The production was reestablished at the end of last year, which is very positive.

So electrification of Draugen. Electrification of Draugen is extremely important for OKEA and is also part of the ambition to actually reduce emissions from our industry that we have committed to. Our strategy as well is to extend the lifetime of these assets.

Shell was an asset which had cease of production in 2027, when it was Shell operated. We extended it to 2035. We have now extended it to 2040, and we are also looking beyond. So in addition to be a commercial project, it's also the right thing to do if you want to stay relevant as an operator on the Norwegian continental shelf even for mid- to late life assets.

It's a big project, and we are also happy to do this project in cooperation with Equinor, which is in the vicinity of Draugen. So the project will go from onshore up to Draugen and then to the seabed again and then out to Njord, which is also electrifying their operation in Q1 in 2027 through this solution.

We are reducing the CO2 emissions on Draugen in 2027 by 95%, which is around 200,000 tonnes of CO2 per year. In addition, Njord orders also reducing their emissions by 150,000 tonnes a year.

The next one that I'm going to show you is the Wintershall Dea asset onboarded. That is a transaction we did last year. We communicated a lot about it last year. But in Q4, it was completed on time. 1st of November, all the approvals from the Ministry and from PSA and others was obtained long before the actual due date, and we had a successful transfer on November 1.

In addition to the actual assets that I just mentioned, we are also taking over 150 employees -- 150 long-term employees, which has been with Brage for quite some time, which will be the success factor to actually deliver the value that we have recognized we can't deliver in Brage.

And it is a significant transaction for OKEA. It increases both our reserves, 2P and also 2C resources. And we have an ambition and a plan to increase the production from this portfolio from around 5,500 barrels of oil per day to 7,000 to 8,000 barrels of oil per day when we have done the infill drilling, et cetera, that we are doing.

So very important to OKEA that we actually are executing on the strategy we established and also communicated in 2021, '22 that we actually can deliver on this one, and we still see this great value potential in the Njord asset.

Our reserves in OKEA has also increased and are currently around 60 million BOE. That is up 29% compared to the end of 2021. Mostly, this has happened through maturation. I just mentioned the electrification project of Draugen, if you're going to extend lifetime, then you also have to electrify.

So then we could mature and get more reserves, into Draugen that we could actually book and obviously, also the volumes we acquired through the acquisition of Wintershall Dea in addition to minor revisions. So very good and healthy additional reserves also during last year for OKEA.

And we are not just an inorganic growth company. We are also focusing on organic growth, mainly around our hubs. And so we are very happy with the awards we got in the APA rounds last year.

We've got 4 rounds, 2 as operator, which is close to Draugen and Brage assets that we already operate and then 2 licenses where we are partner in, which is very close to both Gjøa and Njord.

In addition, last year, the Calypso well, which is also inorganic -- no organic opportunity for us to grow, which is very close to the Draugen field. No sanctioning has happened on that one, but it's in the ground, and we are developing how can this actually be matured and become -- get into production.

And as I also mentioned, the transaction or the deal we did with DNO at the end of last year, makes perfect sense for DNO, but it also makes perfect sense for OKEA that we actually now jointly go into this area and see, in what way, thinking differently, doing things differently, can these resources be turned into reserves that can also be produced over the Brage asset.

We are now working intensely together with DNO to actually make this happen. So again, there is 30 million barrels of oil, 13 kilometers away from an asset. This should be possible to actually produce.

And going back to the original DNA of OKEA, which was a marginal discovery producer and developer in Norway, this is exactly also what we are doing, but now in the hub growth strategy.

My last slide before I hand over to Birte is again to show what did the last quarter look like in Q4. Again, extreme volatility in the commodity pricing. We did see some more bearish market for the oil and also the gas during the last -- well, the last part of last year.

But again, we still see strong oil prices and the gas price has been, well, basically all over the place and very volatile, and that is something we believe will continue.

Something that we communicated last year was that we did expect that the gap between the U.K. market and also the European market would tighten in. So that will be [ more or less ] disappear and that is something we have seen lately as well is that, that gap has actually diminished and they are now trading very closely to each other.

So with that backdrop, I will hand over to Birte, who will take you through the financial results for the quarter before I then come back again and give a summary and before we then go into the Q&A session. So over to you, Birte.

[Birte Norheim, executive]

Thank you, Svein. The financial statements for the fourth quarter are largely characterized by the completion of the Wintershall Dea transaction, which took place on November 1.

With an effective date of 1st of January, all activities in the 10-month period prior to completion were reflected in the balance sheet at fair value. Only activities in November and December are reflected in profit and loss and other key figures, including volumes.

Despite some production challenges. We deliver a solid quarter and a record high net profit of NOK 324 million after tax. But let's go in a bit more detail and start with our production and sales.

We produced 19,807 barrels of oil equivalent per day or 21,450, including the full quarter from the new assets. This is an increase of 1/3 compared to previous quarter. Draugen, Gjøa and Ivar Aasen continue to deliver and production efficiency at Yme is improving.

Production at Brage was impacted by start-up issues following the turnaround, and production at Nova was impacted by the issues with the water injectors. As Svein mentioned, mitigating work here is progressing.

In the quarter, we had a significant underlift position, which limits sold volumes to 16, 322 barrels of oil equivalent per day. At the end of the year, we have underlift positions at Draugen, Brage and Ivar Aasen, which will be lifted in the first quarter.

Compensation volumes from Duva and Nova amounted to 633 barrels of oil equivalent per day in the quarter.

Gas prices continues to fluctuate and the average realized price for natural gas of $112.6 per barrel was nearly half the price realized in the previous quarter. This does not include the realized hedging gain in the quarter, which on a pretax basis, was equivalent to an additional $34 per barrel.

Liquids prices have been relatively more stable, and the average realized price for liquids was $95.2 per barrel. Overall, this resulted in total petroleum revenue of NOK 1.516 billion.

Liquids prices came down somewhat during the quarter from above $19 per barrel early in the quarter to just above $80 per barrel at the end of the quarter.

The graph to the left illustrates the OKEA allocated liftings of crude over the last 5 quarters. And in the fourth quarter, OKEA had 3 partial cargoes with crude lifted with the majority of the volumes received in November.

We also illustrate some of the completed and planned cargoes for the first quarter. Marked in dark blue is the already completed liftings, which includes 653,000 barrels from Draugen, 133,000 barrels from Yme and 600,000 barrels from Ivar Aasen.

Marked in light blue is the expected liftings, which include a 630,000 barrel lifting from Brage and 2 liftings of 67,000 barrels each from Yme in February and another 67,000 barrels from Yme and 101,000 barrels from Gjøa expected in March.

The graph to the right outlines the difference between the average market price of Brent for the quarter of $88.4 per barrel compared to the average realized liquids price for OKEA of $95.2 per barrel.

The difference partly relates to the timing effect since the majority of volumes were lifted in November and prior to the reduction in prices later in the quarter. And in addition, we had positive price adjustments for the crude on Draugen, Gjøa and Ivar Aasen.

Here, we illustrate the average volumes of gas sold per month since October last year and the observable monthly average market prices in the same period. We currently export most of our gas to the U.K. on NBP day-ahead prices.

And as mentioned, the prices have been extremely volatile over the last year, and this has also been the case in the fourth quarter with NBP prices fluctuating between $20 and $280 per barrel.

Let's move to the profit and loss statement. We delivered operating income of NOK 1.664 billion, consisting of the petroleum revenue of NOK 1.516 billion and other income of NOK 149 million.

Other income mainly comprised NOK 40 million in tariff income at Gjøa and a net hedging gain of NOK 86 million relating to forward sale of gas. Production expenses amounted to NOK 522 million or NOK 258 per barrel.

The increase in absolute cost was mainly due to the new assets in our portfolio from first of November, and the cost per barrel was impacted by relatively lower volumes due to the production disturbances.

We recognized an impairment of NOK 251 million related to the Yme assets in the quarter. Due to lower expected plant availability in 2023, part of the production has been pushed back in time, which impacts the fair value estimate for Yme. The total reserves estimate remains unchanged compared to our third quarter update.

The related tax income effect is NOK 196 million, resulting in a net profit and loss impact of NOK 55 million relating to the impairment.

And please also be reminded that following these impairments, the Yme asset is recognized at fair value, which means that any changes in macro conditions and/or asset performance will result in further impairments or full or partial reversal of impairments going forward.

As such, there is the potential for some volatility in the profit and loss statement going forward relating to Yme specifically.

Exploration and operating expenses amounted to NOK 277 million, consisting of SG&A expense of NOK 87 million and exploration expense of NOK 190 million. The exploration expense relate to NOK 79 million on the Hamlet well and seismic purchases of NOK 86 million.

SG&A was higher than our average run cost this quarter, mainly due to transition activities related to the transfer of operatorship of Brage and an annual recalculation of activities distributable to licenses.

Net financial income amounted to NOK 94 million and mainly relates to a net currency gain of NOK 115 million. As the Norwegian kroner strengthened by about 9% relative to the dollar this quarter, the value of our dollar-nominated debt is reduced and results in an unrealized currency gain.

Net interest expense of NOK 23 million is lower than previous quarters, following the buyback of OKEA02 in July.

Tax expense amounted to NOK 335 million, which represents an effective tax rate of 51%. The low rate was mainly due to foreign exchange and hedging gains being taxable at 22%. This brings the net profit to a record high NOK 324 million for the quarter or more than NOK 3 per share.

The balance sheet includes some significant movements resulting from the completion of the Wintershall Dea transaction on 1st of November. As mentioned, all activities in the 10-month period prior to completion were reflected in the balance sheet at fair value.

This includes fair value of the crude inventory at Brage on 31st of October of 446,000 barrels, which is expected to be lifted in February. The related impact on the profit and loss from those volumes will be the difference between the realized price in the first quarter and the recognized fair value.

Goodwill amounted to NOK 1.3 billion. The increase of NOK 496 million relates to technical Goodwill on the new assets acquired.

Cash and cash equivalents ended at NOK 1.1 billion, and the reduction from third quarter was mainly due to payment of taxes as well as the settlement of the consideration related to the acquired assets.

Tax payable was NOK 477 million and mainly relates to accrued tax payable for the 3 last installments for 2022, which are to be paid in the first half of 2023.

Interest-bearing bond loans was just shy of NOK 1.2 billion at the end of the quarter and relates to the OKEA03 bond, which carries a fixed coupon of 8.75% and matures at the end of 2024.

Other interest-bearing liabilities of NOK 508 million relates to OKEA's share of the future obligations under the bareboat charter of the Inspirer rig at the Yme field.

Trade and other payables amounted to NOK 2.2 billion. The increase mainly relates to payment quantity agreements for the new volumes and general working capital improvements.

The increase in asset retirement obligation was mainly due to the new assets and ended at NOK 5.9 billion. This liability is partly offset by the combined asset retirement receivable from Shell and Wintershall Dea of NOK 3.7 billion.

The cash flow development in the quarter was, as expected, significantly impacted by the settlement of the acquired assets, where NOK 1.1 billion was paid at completion.

In addition, NOK 1.2 billion was paid in tax in the quarter, which include 2 tax installments for 2022 of NOK 509 million each and residual tax for 2021 of NOK 182 million.

Cash is expected to increase in 2023 as revenue also from the new assets is generated. In addition, the updated estimate for 2022 tax reduces payments for the next 3 installments from NOK 509 million paid in each of the first 3 installments in the second half of 2022 to NOK 164 million to be paid in each of the last 3 installments in the first half of 2023.

Cash used in other investment activities amounted to NOK 635 million and mainly relates to drilling of the Calypso exploration well, Hasselmus and drilling activities on Yme and Brage. Interest payment of NOK 64 million mainly relates to the OKEA03 bond, which is payable semiannually.

Dividend in the quarter of NOK 104 million represents NOK 1 per share paid in December. And the total liquidity position amounted to NOK 1.1 billion at year-end.

For the full year, OKEA had strong cash generation from operations of NOK 5.6 billion resulting from high realized prices during the year and solid performance at our key assets.

This has enabled an early buyback of OKEA02 and acquisition of new assets, both without any new financing. In addition, OKEA paid cash dividends to our shareholders of NOK 301 million during the year.

In total, we paid dividends of NOK 2.90 per share in 2022. And in the previous quarter update, we also stated an intention to pay NOK 1 per share in each quarter of 2023.

The Board has now resolved to pay NOK 1 per share in March, and the Board is also reaffirming its intention to distribute the same amount in each of the following quarters in 2023. The dividend plan for the year of NOK 4 per share represents a dividend yield of about 12%.

Production for the full year, excluding volumes from the new assets ended at 15,822 barrels of oil equivalent per day, which is in line with the latest guiding. Production guiding for 2023 is set to a range of 22,000 to 25,000 barrels of oil equivalent per day, which is unchanged from the latest outlook provided.

CapEx for the full year, excluding capitalized interest and exploration CapEx ended at NOK 1.089 billion and in line with the guiding. CapEx guiding for 2023 is set to a range of NOK 1.7 billion to NOK 2.1 billion.

That's all from me for now, and I'll give the word back to you, Svein for some closing remarks. Thank you.

[Svein Liknes, executive]

Thank you, Birte. So before we go to the Q&A session, and let me try to summarize where we are.

Okay, we are delivering on a growth strategy. We have demonstrated again that we can do complex transactions and also improve the assets where we are going in. So that is a core of the strategy we actually are embarking on here. So that is also demonstrated in the last quarter.

We do have continued high performance, both in Draugen, Gjøa and also Ivar Aasen and the challenges we have seen on Yme and also Nova has clear improvement plans, so those will be addressed during the year.

We are progressing on our projects, both the Hasselmus, which is in accordance with plan and on budget and set to deliver in Q4, but also the electrification project, which is an important but also a big project for us.

In addition to the inorganic growth focus we have, we also focus on organic growth around our assets. That is also something we have demonstrated with our commitment in the APA rounds and also the awards that we have been given.

And we do have a record high net profit after tax for the last quarter, and we are continuing to pay dividends as set out in the plan that we have communicated earlier. So that is the summary for OKEA.

So we are continuing on the strategy we laid out 1.5 years ago. We are going to grow. We have demonstrated we are going to grow. We are still going to grow where we see that we can actually extract more value.

And we have also to demonstrate capital discipline when we are doing so, both in these volatile markets we are seeing, but also because we are here for the long run in a cyclical business, we have to demonstrate that we really go for the targets and also for the barrels we think will be value accretive for the future.

So 2023 now, new opportunities, new challenges, but still the same strategy that we want to continue on.

So with that, I would like to invite Birte as well back, and then we'll hand set over to the Q&A session. And as I mentioned before, questions can be asked using the link, but also for the call in the following minutes. Thank you.

[Operator]

[Operator Instructions] As there are no questions at this moment in this call. I'll hand the word back to the speakers for the webcast questions.

[Anca Jalba, executive]

Good morning, everyone. This is Anca Jalba, I am heading up IR in OKEA. We will go through the questions submitted on the chat. The first one comes from Teodor Sveen-Nilsen in Sparebank.

He has three questions. The first one is electrification of Draugen. How much will be invested in '23 and '24, respectively, how much OpEx and tax reduction do you expect as a result of the electrification?

The second question is Nova production. Should we expect higher '23 exit rate than current production? And the last question is on cost inflation. In which parts of the value chain do you see the most cost inflation? Svein and Birte?

[Svein Liknes, executive]

Yes. On the electrification, the total CapEx for the project is NOK 7.3 billion. where of NOK 4.3 billion is Draugen, and the remaining is for the Njord asset. The phasing is pretty much even for the next couple of years until we have actually the project electrification started in 2027.

When it comes to the cost inflation, we have seen some cost inflation exactly when it comes to the electrification project when it comes to the cabling, et cetera. When it comes to our Hasselmus project, all the main contracts and all the main procurements was already done before we saw the influx.

So I would say that we are not very influenced by the inflation we have seen or which we expect will come, but we have seen some inflation in the costing for the electrification project, but that is already in the modeling that we have done for that project.

The other question was...

[Anca Jalba, executive]

Nova production. Should we expect higher '23 exit rate...

[Svein Liknes, executive]

The Nova production. Yes, we will expect higher production at the end of the year. We are currently producing on Nova as we just mentioned as well. We did see some issues with the water injection last year, but that was restored.

But there is still optimization that can be done on the water injections, in particular on one of the injector wells, and there will be a side track next year -- well, sorry, this year in the license where we will increase the efficiency of that. So the exit rate will be higher than we see today.

[Anca Jalba, executive]

Thank you, Svein. Next question comes from Thomas Larsen. He has two questions. Can you give any color on production cost per barrel for '23? And the second one, can we expect production percentage from oil, gas, NGL to remain similar through '22 into '23?

[Birte Norheim, executive]

Yes. We don't -- we guide on production costs for any years actually. But I guess what we can say is that we expect production cost to come down somewhat compared to what we deliver in the fourth quarter. And generally, we expect it to hover in excess of $20 per barrel.

As for the production of oil and gas and NGL, we expect the gas portion to come down somewhat when we get Yme in normal production as well as the new portfolio from Wintershall had somewhat lower gas portion than our existing -- our previous portfolio.

So whereas that was 1/3 about gas in our previous portfolio, about 20% gas in the Wintershall Dea acquired assets. So it should come down somewhat.

[Svein Liknes, executive]

And maybe also important to mention that it's actually the percentage which is going down. The overall volume of gas remains pretty much the same, but this is due to increase of the oil portion of what we are producing.

[Birte Norheim, executive]

Yes. And obviously, the gas production will also increase when we get Hasselmus up and running towards the end of the year.

[Svein Liknes, executive]

Certainly.

[Anca Jalba, executive]

Thank you both so much. Next, we have 3 questions from Daniel Stenslet, in Arctic Securities. The first one is, can we give a breakdown of the '23 CapEx guidance? How much relates to Hasselmus, the identification, Brage fields [ billings ] and so on?

The second question, what is the oil versus gas split related to the 8.8 million barrels reserve addition on Draugen? And the last question is what is the total gross CapEx associated with Draugen electrification not just for '23 but for the full multiyear scope?

[Svein Liknes, executive]

Yes. And if I look on the question #2 and 3, Birte can then look on the CapEx guidance. But the -- as I just mentioned, the total CapEx for the electrification project is NOK 7.3 billion, where of NOK 4.3 billion is on Draugen for the full scope. On the oil versus gas split for the reserves addition is around 80% oil, 20% gas in those additions.

[Birte Norheim, executive]

And as for the breakdown of the CapEx, roughly 20% related to Hasselmus, roughly 20% relates to the electrification and roughly 30% relates to the 3 infill wells planned for Brage in 2023.

[Anca Jalba, executive]

Thank you so much. Next on the call, we have questions from John A. Olaisen in ABG. Two questions from him as well, at least the first one goes on the Draugen electrification. We already discussed and touched on the CapEx for the project here.

He also asks if it's a profitable investment. If so, how? Could you give a quick overview of the economics, please? And the second part goes on, would it be possible to give some indication on unit OpEx and unit depreciation for '23?

[Svein Liknes, executive]

Yes. On the Draugen question there, I think we have mentioned the overall CapEx for the project a few times now. And it is still a profitable investment, which is positive economics, but also worth noting here is that through this project, we are also extending the lifetime of Draugen.

Shell had a cease of production in 2027. We moved into 2035 to start with. We have now moved into 2040, and we are also now looking at long-range plans, which takes Draugen beyond 2040. So it's still a profitable project.

And also, it is in addition to being a good project as such. It's also the right thing to do if you're going to be relevant producer in 2040. And we still believe you have to do what you can do to actually reduce your emissions from the assets you actually operate.

So I think this is an excellent example of where OKEA actually not only adds value but also has a future-fit strategy for the asset.

[Birte Norheim, executive]

And as for the unit OpEx and depreciation, as mentioned, we do not guide on these items, but we expect OpEx to be in just in excess of $20 per barrel in 2023.

[Anca Jalba, executive]

Thank you. Next to John, 2 questions from Ola Eikanger in SEB. The first question is, given the current cash position and CapEx guidance, in addition to your inorganic growth strategy, also recurring capital, what kind of oil price would on the downside will start impacting the dividend level of NOK 1 per share.

And if you have to choose between pursuing inorganic growth and pay dividends, where would you prioritize capital allocation? The second part of his question is looking at production past 2023? Or do you see OKEA going longer term?

[Svein Liknes, executive]

Yes. If you take the first one, Birte, then I can look -- elaborate a bit on the production past 2023.

[Birte Norheim, executive]

Yes, I can. So there's obviously many factors impacting the dividend level. So we'll not provide any firm answer on that. But as we have stated today, we are reaffirming our intention to continue to pay NOK 1 per quarter in 2023.

We have also stated our capital allocation principles, which is, amongst others, a healthy balance between growth and dividends. And I should mention also in that respect that when we are now targeting producing assets, dividend capacity is one of the key investment criteria.

So obviously, it could be that in 1 or 2 periods, dividend could be impacted, but it shouldn't really be impacted in the longer term, at least not with a negative rather on the contrary.

[Svein Liknes, executive]

When it comes to long-term production, we have never kind of been very exact on how much production levels should OKEA have in 2023, 2024, et cetera. Obviously, we are on a growth path, so there will be more barrels added.

But something we have been very clear on is that when we go for this growth, we want to see value accretive growth. If the target was to produce 50,000 barrels of oil, I guess, we could have achieved it already, but we are definitely targeting that those barrels that we're actually adding to our portfolio are the most value-accretive ones.

So there will be more, obviously. And in the growth strategy that we have both on asset transactions and other transactions that we are looking at. we will add barrels, but we do not have any specific target. Our main focus is that the barrels we actually are adding are the most value-accretive ones.

[Anca Jalba, executive]

Thank you so much. This question comes from David Mirzai. Why has the peak production level on Yme being reduced and not deferred, yet the ultimate reserves not downgraded? How has your view on the Yme reservoir changed? And why was this not understood before?

[Svein Liknes, executive]

Yes. Just on a high level there, we did reduce the -- we did downgrade the reserves last year or in Q3 basically. That was done then. The reason why we have reduced the production level now is mainly related to production efficiency.

So do you expect 98% of time, do you expect 95% of time or you want to take a more conservative approach? We have decided to take a more conservative approach for 2023. So that's the reason we are seeing the movement in the production profile and not that we are taking down the reserve. That was something we did last year.

The rest of it changed, not understood before, to actually get a proper model and expectation and adjust your model when it comes to the reserves you have. You need stable and a period of continuous flowing conditions to monitor your wells.

And that was the reason last year, where we did the impairment was because we did have half year of steady flowing conditions of these wells and saw higher water cut. Therefore, we did the change last year. So you need some time to actually do the right analysis of the reservoir.

[Anca Jalba, executive]

Thank you. Next set of questions are coming from [ Ruhal Harvingsons ] in Clarksons. We have 5 of the questions from him. The first one goes on Brage, [indiscernible] resources increased to 15.5 million barrels.

This is a large setup from the 10.6 million barrels you reported for all the industrial assets combined upon announcement of the transaction. Can you elaborate on the key factors allowing for such a significant expansion of the Brage resources?

The second one, you expect the electrification of Draugen to drive down operating costs. Can you quantify a range for cost savings on a unit basis here following the electrification? How should we think about the CapEx distribution on the Draugen electrification from now and until completion in 2027?

The third, you guide for CapEx of NOK between NOK 1.7 billion to NOK 2.1 billion. How much of that pertains to projects under the temporary tax regime?

The fourth question, we already answered some -- and to some extent hear, but it's a different nuance of the question. Production cost remains relatively high at NOK 258 per barrel. How should we think about production costs on a unit basis when production on new field stabilize?

And the last one is the Hamlet project did not deliver a PDO before year-end. Can you give some color on how you are thinking your regards -- with regards to a potential development of this discovery? And what are your main scenarios with regards to timing?

[Svein Liknes, executive]

Yes. We can start from the bottom there. If you go as well down to the bottom. The Hamlet project did not pass the FID last year. It was a lot of effort put into Hamlet to actually mature the project and try to develop it under the temporary tax regime and also to develop that area, which is an important growth area for the [indiscernible] asset.

We did not get to that point last year. But obviously, the resources in the ground are still being matured, and we are looking into, can these resources become the reserves and also produce in parallel with other resources in the area, which has also been discovered last year. So the resources are still there.

And I think actually it was a healthy decision last year that we are able to actually make mature decisions on how to develop these projects, and we are still continuing to work on Hamlet to get that into year at some stage.

I guess production costs that we have elaborated on the guiding there, just above $20 per barrel. When it comes to the CapEx for the temporary tax regime, I'm not quite sure if we do have that breakdown, how much is actually related to that, Birte?

[Birte Norheim, executive]

It's between 40% and 50% roughly, largely relating to Hasselmus and the power from shore project as well as some of the drilling planned for Brage.

[Svein Liknes, executive]

And the CapEx for the Draugen electrification project, we have mentioned several times already. So pretty much evenly distributed throughout the project between now and 2027, Q1. And also the total volume of CapEx, we have also mentioned previously, and the increase of the 2C resources on Brage, the detailed breakdown there.

[Birte Norheim, executive]

Yes. We don't have a detailed breakdown, but it's more a practical -- it's more of how we actually approach it. So when we do an acquisition, we are risking these volumes. There are different principles when we include volumes in annual statement of reserves.

So basically, this includes 2C resources and more and less mature resources in the report versus the numbers provided in relation to the announcement of the acquisitions was risked, I think that's the key difference.

[Svein Liknes, executive]

Yes. And when it comes to the range for cost savings on a unit basis, that is very hard to kind of quantify. The project is a positive project commercially, so basically, those are the kind of metrics we are looking at, that it actually is an overall positive project for the Draugen asset.

And the real kind of cost saving we will see on Draugen when it comes to production expenses is when the Hasselmus gas enters Draugen later on this year when we actually stop importing gas to Draugen for power generation and actually turn Draugen again to a gas exporter. So that's basically the biggest cost saver on Draugen.

[Anca Jalba, executive]

Thank you much, both, and now we go to the last question submitted on the call comes from in Ina Golikja. Can you please give a bit of color on the contingent payment to Wintershall Dea?

[Birte Norheim, executive]

Yes, the contingent payment is based on a realized oil price above $80 per barrel. It applies for the period 2022 to 2024. And it consists of 6 months period. So it would have to be the average realized price in each of the 6 months period.

And the division in 2023 and 2024 is 57.5% of that on a net tax basis to OKEA. In other words, the price above $80, and the remaining goes to Wintershall Dea as part of the contingent payment.

[Anca Jalba, executive]

Thank you so much. And with that, we have finalized the questions submitted on the call. Thank you so much. We'll hand it over to the operator.

[Operator]

There are still no questions in this call. So I'll hand it back to the speakers for any closing remarks.

[Svein Liknes, executive]

Yes. No, again, just to sum everything up, very good quarter for, and also a very good year for OKEA. Thank you all for taking part in the presentation and also for your good questions. I hope that you have got the answers you were looking for. And if there is anything else we can do to kind of inform you about OKEA, please reach out and make contact, and we will continue to answer if you have any further questions. So thank you for your attendance.