Okea ASA

OSE:OKEA

Earnings Call Transcript 2022-Q2

[Svein Liknes, executive]

Good morning, and welcome to the presentation of the second quarter for OKEA. My name is Svein Liknes, I'm the CEO of the company. With me today, I have our CFO, Birte Norheim, who will take you through the financial details, but I will take you through the operational performance and some highlights for the quarter before Birte takes the financial part. There will also be a Q&A session when we are done, and there will be links, both to dial-in instructions, but also a link where you can ask questions on our website.

The second quarter of 2022 has been very much impacted by very volatile prices in the market, both for gas but also for oil. And for OKEA, we've had strong performance and strong operations performance both on the Draugen and Gjøa assets during the quarter. And we've had a slower ramp-up on Yme, that I will get to when I go through the details, which means that we have also adjusted our guiding for this year due to this. This is the production that will come later on this year, but also into next year.

We had a planned shutdown and tie in for maintenance on the Gjøa, which was completed in April, and that also impacted some of the gas pricing we had during this quarter, and Birte will get into details on the timing of that and the mechanisms behind it. Birte will also take you through the financial details, but I would like to point out the cash increase of NOK 289 million at the same time as we also paid dividend of NOK 93 million in June, which has further improved the cash position for the company.

We believe, based on this quarter as well that OKEA is still well positioned for value accretive growth. We have decided for the second dividend payment in September this year of NOK 1 per share that we also announced previously as an intention, that has now been confirmed. We are net debt free, and we are initiating full redemption of our bond OKEA02 now in July. We performed the acquisition of substantial portfolio from Wintershall Dea, that I will take you through more detail a bit later. And we have also announced earlier this quarter, we announced the discovery of the Hamlet well, which will be a tieback to Gjøa and the operator and the license is now working on the project with a goal for final investment decision by the end of 2022.

For other projects, which is the power from shore on Draugen and also for Njord in that respect. And also our Hasselmus gas project is continuing as planned. And I will go through those in more detail later on. But going back to the point on volatile prices. As you can see here, we've had a strong increase in prices earlier this year. And during this quarter, in particular, and especially on the gas price, we have seen very volatile pricing. We've also seen a gap between the gas delivered to the U.K. and also to the continent, and majority of the gas of OKEA is being delivered to the U.K. But as you can also see here on the forward curve, we do expect a very strong market for gas pricing also this winter. And it seems like the pricing is converging later on this fall. So also the U.K. price is on the rise now. So that will be more or less equalized as we go forward.

Building a portfolio and expanding on our portfolio like we have done with the transaction with Wintershall is also an important step for OKEA to make us less vulnerable to these kind of volatile pricing because then we will have a more evenly distributed sales of products.

Production volumes. We've increased our production volumes again compared to the last quarter. But as I just mentioned, we've been impacted by some planned shutdown on Gjøa for the tie-in of third-party tiebacks to Gjøa and very high production liability on Draugen. So we have increased our production. As you can see on the average here as well, we still have Yme, which has been lower than expected, and that is also the reason why we have adjusted the guiding. And for the exposure, we have 32% gas in the portfolio still.

Very high reliability still, although a bit lower on Gjøa due to the planned maintenance -- no, sorry, the tie-in of new projects, but still very high production efficiency on those assets.

Safety and emissions. From last time, you will see that the serious incident frequency has increased a bit. That is due to 1 incident, and that's the power outage we had during the first quarter that was investigated. And due to the interruption of firewater protection on the platform for a very short period. We have classified that as one as a serious incident. So that's added to the 1 with the loosened rail that we had last year. So that's the reason why we've had an increase in serious incident frequency.

When it comes to total recordable injuries harm to people, I'm glad to see that we are continuing the trend -- the downward trend and show that we show a real commitment to the HSE for our people working on our installations. We still had zero hydrocarbon leaks. And for the CO2 emission, you'll see that we are increasing the CO2 emissions. This is mainly due to lower production than planned and also high emissions coming from the Yme field, in addition to the normal increase of CO2 that we are seeing.

Adding production through all the electrified platforms and assets like Gjøa and like Ivar Aasen will further reduce this number. But the big impact will be when we are executing on the electrification project for Draugen that we are doing currently.

So going to Draugen. Very good performance, above 7,000 barrels of oil per day in production. Draugen is a typical mid- to late-life asset, where we are doing both decommissioning work as we have done the light well intervention campaign to prepare for the plugging of wells. At the same time, as we're executing on the greenfield development of the Hasselmus project, which is still according to plan. We have completed the subsea installation scope for this year. We are just about the spud of the well, that we will drill this year for the Hasselmus. And then we will initiate during the second half of the year, the topside installation on the Draugen. And we are still planning for a production start in Q4 in 2023 with an expected gas production of more than 4,400 barrels of oil equivalents per day. But this is pure gas. To set that into context, looking at from an OKEA perspective, that is very close to 30% increase of the gas produced today by OKEA, just to put into a context.

Also executing on the electrification of Draugen and Njord, which will have a significant impact on the CO2 that you just saw in the previous slide as well, reducing the CO2 emissions on Draugen by 95% when it started. That is more than 200,000 tonnes of CO2 reduction from Draugen. And in addition, there will be 150,000 tonnes of reduction of CO2 also from the Njord field, which is benefiting from the same project.

We are in the final stage of the FEED studies together with Aker Solutions [indiscernible], and there's a public consultation process ongoing for that project.

Moving on to Gjøa, a very important asset still for OKEA. That's also the one that gives us most gas exposure today. And that's also why we saw that we had a shortfall in the gas earlier this year because Gjøa was down for the planned tie-in job very early in the quarter. Production very similar to Draugen and then the very high production liability of 97%. We also, as I just mentioned earlier, we confirmed the Hamlet exploration well earlier this quarter. And we do have a goal to have a final investment decision by the end of this year and the license is working to get that done.

And again, just a reminder, on the volumes that we are talking about, the operators preliminary estimate is 8 million to 24 million, that is part of that development.

Then Yme. Average production during the quarter was 1,322, which, as I just mentioned, is lower than we expected. The average production now from 4 existing wells that we have in operation now gives us a daily production of around 3,500 barrels of oil per day. So it's increased, but it's delayed compared to what the previous assumptions were.

We do have 2 more wells to complete this quarter. Actually, one of them is being started up this week. And then there will be a second one. In addition, we have the Beta North drilling campaign and the Gamma also program to commence in the third quarter of 2022, that will add the final wells on Yme, which then will lead to the plateau production on Yme guidance for production this year for OKEA, but also a positive impact in 2023 as we are pushing it to the rate.

Ivar Aasen asset, production of 550,000 barrels of oil per day (sic) [ 550 barrels of oil per day ]. That has also increased. Ivar Aasen also had some issues during this quarter, as they did not have proper power supply from Edvard Grieg field. So -- and that happened around the 27th of March. They started partial production on the 21st of April, and we're back in full production from 24th of May and is now producing accordance with plan, which is meaning that a day production to OKEA is closer to 1,000 barrels of oil per day currently, but the average for last quarter was 550.

Significant activity for OKEA during the last quarter was when we announced the transaction that we have worked with Wintershall on, which means that we will take over a portfolio from Wintershall, which is in accordance with our strategy. It is an operated asset with a platform with crew, 140 people. But in addition, there's also a portfolio of partner-operated assets, which means that we are increasing our exposure in Ivar Aasen, which we are already in. So we will now be very close to a 10% partner in Ivar Aasen. And we're also adding volumes by having 6% from the Nova field into that portfolio, which will start production now in Q3 this year and produce over year.

The consideration for this -- the fixed consideration for this transaction is NOK 117.5 million, and that was paid by cash that's already in the company. So we are in a very good position to do these kind of transactions with the financial position we have. And as you will also see in this transaction, 80% of the decommissioning of Brage still remains with Wintershall Dea, and that is also something we did back with Shell when we took the Draugen asset over. So 80% remains with the current operator.

We also see, as we are growing the organization, that we are seeing annual cost synergies of $4 million to $7 million across our operated portfolio. So this is a significant move for OKEA on our growth strategy. We are moving them from 4 producing assets to actually 6 producing assets, so it's an increase of 50%. And we did have a plan of 21,000 barrels of oil at the end of this year in production. And with this transaction, we are adding 7,000 more. And this will also then diversify the portfolio that we have and go back to what I just mentioned on the volatility in the market, and this will further strengthen OKEA when we have continued volatile markets as we will have more even production. So this is important transaction for OKEA in many respects.

And it is -- in accordance with the strategy we announced last year. We wish and think we also are a leading mid- to late-life NCS operator. This gives us a very near-term value creation. It gives us an opportunity to grow the organization to also take more assets in the future. And it gives us, as I just mentioned, a larger and more robust portfolio that give us more resilience as a company. And one of the main drivers also for this transaction is that OKEA is already an operator on the Norwegian continental shelf, which is a prerequisite for actually executing on these kind of transactions and deliver more value from these assets.

So with that, I will hand over to Birte Norheim, our CFO, that will take you through the financial details before I then come back again and take you through a summary for the quarter, and then we go into the question and -- Q&A session. So with that, I'll hand over to you, Birte.

[Birte Norheim, executive]

Thank you, Svein. The second quarter has indeed been eventful for OKEA. We entered into an agreement with Wintershall Dea for a most significant acquisition since 2018, which we are funding by existing cash resources. We paid our first dividend payment and we reaffirm our dividend plan for 2022. And today, we also announced a full buyback of the OKEA02 bond, which will reduce our finance costs going forward.

On the more disappointing side, as Svein also mentioned, is the slower-than-anticipated progress at Yme, which resulted in a reduction of our guiding for the year. Despite the postponement of volumes from Yme, our cash position remains strong, and we have generated free cash of NOK 11 per share so far this year. But let's start with our production and sales.

In the second quarter, we produced 16,039 barrels of oil equivalents per day, which is an increase of 1,131 compared to previous quarter. It is the solid performance from Draugen and Gjøa, which drives the increase despite the 8 days of planned shutdown at Gjøa in the quarter. The majority of the shutdowns goal was related to tie-in projects for which Gjøa will be compensated. Yme contributed with 1,322 barrels per day, and Ivar Aasen contributed with 550 barrels per day, both at lower levels than what we expect to see going forward. This is partly due to the delay in ramp-up from Yme and partly due to the effect of the increased working interest in Ivar Aasen, which was effective from 1st of April, being partly offset by production interruptions due to an electrical failure on Edvard Grieg, as Ivar Aasen relies on Edvard Grieg for final processing and exports. Production at Ivar Aasen has been stable since the end of May.

Sold volumes of 15,957 barrels of oil equivalent per day was an increase of 513 compared to the previous quarter. This is mainly due to higher lifted crude volumes from Draugen and Yme, partly offset by lower lifted crude volumes from Gjøa. Compensation volumes from Duva amounted to 849 barrels of oil equivalent per day in the quarter. The market prices for both oil and gas were highly volatile during second quarter, and we have seen unprecedented price differentials in the European gas market. I will revert to this.

The average realized price for natural gas of $82.4 per barrel equivalent was less than half of the price realized in the previous quarter. However, it was about 50% higher than the price realized last year. The realized price here does not include the effect of the hedge, which we entered into earlier this year. We had effectively hedged about 25% of our volumes sold in the quarter at the price of about $200 per barrel equivalent. The average realized price, including the effect of the hedge, thus amounts to about $113 per barrel. The average realized price for liquids was $100.3 per barrel, which is $10.7 per barrel higher than last quarter and nearly 60% higher than last year. Overall, this resulted in a total petroleum revenue of NOK 1.254 billion, a decrease of NOK 262 million compared to previous quarter and more than double compared to last year.

Liquids prices have steadily increased over the last 2 years and the volatility has been high at high price levels in the last 2 quarters, in particular. The graph to the left illustrates the OKEA allocated liftings of liquids over the last 5 quarters. And in the second quarter, OKEA had 6 partial cargoes with crude lifted with the majority of the volumes received in April. We had 1 lifting from Draugen at 632,000 barrels, 2 from Gjøa for a total of 74,000 barrels and 3 liftings from Yme for a total of 132,000 barrels.

We also illustrated the completed and planned cargoes for the third quarter. One lifting has already been completed and is marked in dark blue with 48,000 barrels from Yme in the beginning of July. Marked in light blue is the expected liftings for the third quarter, which includes 633,000 barrels from Draugen and 60,000 barrels from Ivar Aasen in July and 157,000 barrels from Gjøa in August. Although we expect further crude liftings from Yme in the third quarter, we still do not provide further guiding on expected liftings due to the ongoing commissioning.

The graph to the right outlines the difference between the average market price of brent for the quarter of $113.9 per barrel compared to the average realized liquids price for OKEA of $100.3 per barrel. The key difference relates to the timing effect since the lifting of Draugen occurred in mid-April and at a time when prices were at lower levels compared to the remainder of the quarter.

The graph illustrates the average volumes of gas sold per month since April last year and the observable monthly average market prices in the same period. Currently, we export our physical flow of gas to U.K. on day-ahead prices. And following all-time high on European gas prices in March with prices in excess of $400 per barrel for a short period, gas prices in Continental Europe have been relatively stable at just below $200 per barrel in the second quarter. However, gas to U.K. have traded at a significant discount compared to Continental Europe prices. And historically, this discrepancy is without comparison, and we note that the forward curve suggests that the market expects alignment in the European gas market this fall.

The 8 days of downtime at Gjøa in the beginning of April coincided with the highest market prices in the quarter and the high production in May took place when the market prices were at its lowest in the quarter, which drives the average realized price down compared to the observable average market price.

So let's look at the profit and loss. The operating income of NOK 1.332 billion mainly consists of petroleum revenue of NOK 1.254 billion and other income of NOK 78 million, which includes a net gain on hedging positions of NOK 41 million and tariff income at Gjøa of NOK 26 million. Production expense of NOK 381 million or NOK 235 per barrel compared to NOK 192 per barrel in the previous quarter. Production expense is high this quarter mainly due to high cost at Yme due to well recompletion cost and combined with low produced volumes in the ramp-up phase, this drives the high production expense per barrel for the quarter. The downtime at Gjøa and production interruptions at Ivar Aasen also increased the cost per barrel.

Exploration and operating expense of NOK 84 million consists of SG&A cost of NOK 58 million and exploration expense of NOK 26 million. The SG&A cost is high this quarter, mainly due to corporate costs following the acquisition of assets from Wintershall Dea and the long-term incentive scheme, which was settled in May. Exploration expense in the quarter, mainly related to cost of the APA round for 2022 and various field evaluation activities. NOK 25 million in costs related to the Hamlet discovery were capitalized.

Net financial expenses amounted to NOK 231 million and mainly comprise a net foreign exchange loss of NOK 177 million and expense interest of NOK 51 million. As the Norwegian kroner has weakened by about 14% to the U.S. dollar in the quarter, unrealized loss on the dollar-nominated debt amounted to NOK 338 million. This is partly offset by a gain of NOK 161 million on bank accounts, nominated in dollars as we have accumulated dollars in cash to settle the bonds as well as the net purchase price of the acquisition from Wintershall Dea. Tax expense amounted to NOK 504 million, which brings the net profit for the quarter to NOK 28 million. The high effective tax rate in the second quarter was mainly due to the unrealized loss on foreign exchange being deductible at a lower tax rate of 22%.

As for the balance sheet, the cash balance improved by NOK 288 million in the quarter and ended at NOK 2.758 billion. In addition, NOK 210 million was placed in low-risk investments, which brings the total liquidity to nearly NOK 3 billion. Trade and other receivables amounted to NOK 1.060 billion, and includes a partial prepayment on the Wintershall Dea transaction of NOK 97 million. Tax payable was NOK 1.298 billion, and mainly relates to accrued tax payable for the first half of 2022 and residual tax payable for 2021. The interest-bearing bond loans amounted to NOK 2.182 billion, and the increase from previous quarter was due to the unrealized foreign exchange loss, partly offset by a reduction through buybacks of OKEA02 in total of NOK 105 million.

The bonds bought back in the mandatory offer tied to the dividend payment of NOK 95 million was settled in July and has therefore been reclassified as trade and other payables as per the end of the second quarter. Please note also that the OKEA02 bond was reclassified to a current liability as the maturity date is the 28th of June next year and hence, less than 12 months from balance sheet date.

Other interest-bearing liabilities of NOK 527 million represents the net present value of our future obligations under the bareboat charter for the Inspirer rig at the Yme field. Total asset retirement obligations of NOK 3.7 billion is partly offset by the asset retirement receivable from Shell of NOK 2.6 billion. Both amounts are reduced compared to the previous quarter due to the general increase in interest rates, which increases the discount rates applied for the estimation of the net present value related to the asset retirement activities.

Our cash position continued to improve with a net increase of NOK 289 million on top of the cash spend on dividend distribution of NOK 93 million and a buyback of OKEA02 bonds of NOK 10 million. This represents a total cash generation of about NOK 4 per share for the quarter, and total liquidity ended just shy of NOK 3 billion. Cash flows from operations was a solid NOK 1.85 billion and the taxes paid of NOK 286 million relates to the last 2 installments of tax payable for 2021.

Cash used in investment activities was NOK 304 million, which includes NOK 91 million in net cash paid in relation to acquisitions. NOK 25 million in exploration drilling activities, mainly relating to Hamlet and NOK 187 million used in other investment activities, including Hasselmus, Yme and Draugen. The interest payment of NOK 76 million relates to the quarterly payment on interest of the OKEA02 bond and the semiannual payment on the OKEA03 bond. And as we have said, a milestone was reached in June when OKEA was in a position to pay our first dividend payment of NOK 93 million or NOK 90 per share.

Our solid cash development in the first half of the year can be attributed to a strong market and good performance on Draugen and Gjøa. The total improvement in our liquidity position was NOK 720 million, on top of the dividend payment of NOK 93 million and total buyback of OKEA02 bonds of NOK 299 million. In total, this represents a cash generation of NOK 11 per share for the first half of the year. NOK 580 million was paid in taxes, NOK 105 million was paid in interest and NOK 590 million was invested in developments, drilling activities and acquisitions.

In June, the Norwegian Parliament enacted the new tax regime, which has been expected since last fall. The new rules are effective from 1st of January this year, with the most prevailing feature of being a more cash-based system where capital expenditure is expensed immediately in the special tax and without any uplift. And in tax values of losses in the special tax are also reimbursed as part of the ordinary tax settlement each year. The temporary rules, which were introduced in the summer of 2020 still applies for qualifying projects with certain technical changes, including a reduction in uplift from 24% to 17.69%.

I will not go into detail of the tax changes here, but focus on the key implications for OKEA, which is an improvement in cash in the near term and a reduction in tax shield over time. In other words, an increase in tax expense. At the right-hand side, we illustrate the effect on cash and net present value for an investment of NOK 100 million. This is an example only where we, for this purpose, use a 10% discount rate and where we do not consider other benefits from the illustrated investment but merely look at the expenditure net of cash.

As can be seen, although the tax shield was higher under the previous tax regime, the net present value increases due to the immediate deductibility compared to 6 years depreciation and uplift in the special tax under the former system. According to our estimates, the breakeven discount rate between the 2 systems with respect to capital investments, is 6.85%. Valuation for companies with higher weighted average cost of capital than this will thus increase under the new system.

Also worth noting is that the technical changes also result in an improvement in valuation for projects qualifying for the temporary tax regime, as the effect of the higher special tax rate more than offsets the effect of the reduced uplift. For OKEA, this applies to the Hasselmus gas project and the power from shore project at Draugen.

As we also indicated in our first quarter reporting, the ramp-up at Yme has progressed slower than what we anticipated. This development has continued in the second quarter and the updated prognosis from the operator indicates that plateau production will be pushed back from third quarter to the end of the year, which leads us to revise our production guiding for 2022 from a range of 18,500 to 20,000 barrels per day to a range of 16,000 to 17,000 barrels per day.

Note that the guiding level for 2022 does not include volumes from the Wintershall Dea transaction as timing of completion is not confirmed, which will impact what will be recognized in the balance sheet as part of the purchase price allocation and what will be recognized in the income statement. However, as Svein stated, the combined production will be at the level of around 28,000 barrels per day at the end of the year when Yme is expected to be in full production and Nova is onstream. In addition to our own produced volumes, we expect between 900 and 1,200 barrels per day as in-kind compensation volumes from Duva and Nova in 2022, which additionally will increase our sales and cash flow.

Production outlook for 2023 is expected to increase from a range of 17,000 to 19,000 barrels per day to a range of 25,000 to 27,000 barrels per day. The increase is mainly due to the acquisition of assets from Wintershall Dea, but also to an increased contribution from Yme as the plateau production is now expected to take full effect in 2023. Note that following the acquisition from Wintershall Dea, OKEA, as owner of Nova, will be liable for in-kind compensation to Gjøa and Brage. For 2023, the net effect is more or less zero. And the previous outlook of 600 to 800 barrels per day for 2023 are therefore removed. The CapEx guiding for 2022 remains in the range of NOK 950 million to NOK 150 million and excludes capitalized interest. Also, the CapEx number excludes the effect of CapEx from the Wintershall Dea transaction.

Following the announcement of our dividend plan for 2022 in May, we paid our first cash dividend of NOK 0.90 per share or a total of NOK 93.5 million in June. We also stated an intention to pay NOK 1 per share, both in the third and in the fourth quarter this year. And the Board has now resold to pay NOK 1 per share in September and is reaffirming the intention to distribute the same amount in the fourth quarter. In total, this amounts to NOK 2.90 per share or a total of NOK 301.2 million, which is the max capacity allowed in the bond terms this year.

The ex date for the dividend payment will be 2nd of September, and the payment date will be on or above the 15th of September. And today, we have also announced that we are undertaking a full voluntary early redemption of the OKEA02 bond. We have already bought back $80 million of the $180 million initial issue in the market, which means that we are now calling a net amount of $100 million. The current call price is 102.75, which is 175 basis points higher than the price at maturity. The repayment will be settled on the 27th of July, and the net savings after tax is estimated to about NOK 55 million compared to settling the debt at maturity in June next year.

That's all for 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. As a final summary before we go to the Q&A session. For this quarter, OKEA has been delivering on our growth strategy that we announced with a material acquisition from Wintershall Dea, which has been fully funded by cash that we have in the company. And in addition to adding volumes, 7,000 barrels of oil equivalents, where 20% is gas to our portfolio, it also makes OKEA much more resilient for the future when we are going into volatile price markets that we have seen during the last quarter.

We have shown continued solid performance on Draugen and new operations, which should continue. There's no planned shutdowns or anything on Draugen for the rest of the year. So we expect continued strong performance from those 2 assets. We have a delay on Yme. It's going slower than projected, but producing today much higher than what we have seen for an average over the last quarter. But Yme will come, but we are moving then the plateau from third quarter to the fourth quarter or the end of the year. So that will come as well. We are following that quite closely.

We are delivering on organic projects, both the Hasselmus, which is progressing according to plan and an aim to do an FID on the power from shore on Draugen later on this year. We are in a very solid cash position as a company still. We have initiated a cash dividend plan and paying out that now and are also actively reducing our debt, which is further then strengthening our position. So I would say OKEA have still delivered a very strong performance during this quarter and are well positioned to actually execute further on our growth.

So before then moving over to the Q&A session, I would like to thank everyone for your attendance, and thank you for following OKEA. And I will also use the opportunity to wish you a great summer, and I'm looking forward to speak to you again latest in October when we are producing our Q3 numbers, but hopefully before that. So with that, I would like to thank you all. Bye.

[Operator]

[Operator Instructions] The first question is from the line of Teodor Nilsen from SpareBank 1 Markets.

[Teodor Nilsen, analyst]

Three questions from me. First, on the gas exporter, TTF versus NBP after the closing of the Wintershall Dea. Will we still have full exposure to NBP or that change after the deal closing? Second question, a general question on NCS M&A market? Is that do you view that as a buyer or sellers' market now? And would your preference be gas assets or oil assets going forward? And my third question is also just a general industry question on cost increases. It looks like in any industry, is there's cost increases that is increasingly important topic. So just wonder what do you see on your assets there?

[Birte Norheim, executive]

Yes. Teodor, I think I can answer on your first question, and I'll let Svein answer the 2 last ones. But as for gas, as of today, as we say, we export all our gas to the U.K. market of the portfolio that we are acquiring from Wintershall Dea, about 20% of that -- those volumes are gas. And we do have flexibility to route those to the Continental Europe market. That will also be the case for the Hasselmus gas when Hasselmus comes onstream next year.

[Svein Liknes, executive]

Quickly on the 2 next ones. The NCS M&A market, seller or buyers' market? I still believe it's possible to do strategic good transactions like we did -- like we have just done. And obviously, we are positioning us to do that. And you asked if we are exposing ourselves towards gas or any preference between gas and oil, and I would say we have a preference for both. We are value-driven and looking at opportunities as we have done previously as well. The most important thing for us is to ensure that if we do a transaction, then we can see that we can extract more value from the asset. And also that the portfolio in the transaction has kind of a diverse -- diversity with both partner operator but also the operated assets. So I still think the M&A market will continue for the rest of the year with the conditions we have now.

Cost increase, we believe there is -- we believe that there will be a price increase in the market, but it's not something that we are very much exposed to currently on the Hasselmus project. We do see some increases within the expected range on pricings, in particular for cables, et cetera, for the power from shore project, but something that is challenging the project as such. But do we think the main exposure and the main constraints will be apparent next year.

[Operator]

[Operator Instructions] As there are no further questions at this moment, I will now hand the word back to the speakers.

[Unknown Executive]

Yes. We have a question from the web as well [indiscernible]. What is the production capacity at Yme given the 4 wells currently in production? And what is Yme producing at the moment?

Have I understood it correctly, the Wintershall payment of USD 117.5 million will be lowered by the portfolio's free cash flow in 2022. If so, is it possible to give some indication of the expected free cash flow? I presume CapEx at the Nova development built to all the free cash flow down. We expect a positive free cash flow from the Wintershall development including the Nova CapEx.

[Svein Liknes, executive]

Okay. I can answer the first part, and then I'll hand over to Birte. On the Yme, production capacity currently is around 25,000 to 26,000 barrels of oil per day from these 4 wells. And we are actually ramping up the fifth well as we speak. So that will further increase the capacity of Yme. So on an average for the last week or so, we have been around 25,000 barrels of oil. So that is from half of what we have now. The future production capacity, we have 4 more wells that will be put onstream during the second half of the year. And as we have said before, the plateau is expected to be in excess of 50,000 barrels of oil per day on Yme when it's on plateau.

[Birte Norheim, executive]

Yes. And I can take over. And yes, [indiscernible], you have understood correctly that the Wintershall payment will be lowered by the portfolio's cash flows in 2022 prior to the completion date. So -- and I could also emphasize that, that will be the pretax free cash flows in 2022 prior to completion date. Yes, some indication. We haven't provided guiding on that, but I guess I can say it's quite significant. And to give a rough indication, maybe around half, of course, that will depend on the timing of completion, which we have said we expect in the fourth quarter. And even if there is CapEx at the Nova development, we do expect positive free cash flows. And as we stated when we launched the deal, we expect that transaction will be repaid by the end of next year through the cash flows generated by those new assets.

[Unknown Executive]

That was all questions posted online. I'll hand over to the moderator to...

[Birte Norheim, executive]

Okay. So if there are no more questions, I think we just wish you all a good summer and thank you for participating. And do not hesitate to get in touch if you do have any other questions to Svein or myself. Thank you.