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 1 I have our CFO, Birte Norheim, who will take you through the financial details. 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. There will be links, both the 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.
For OKEA, we've had strong performance and strong operations performance, both on Draugen and on our Gjøa asset during the quarter. We've had a slower ramp-up on Yme that I will get back to when I go through the details, which means that we have also adjusted our guidance 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. 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 are 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 acquisition of a substantial portfolio from Wintershall Dea that I will take you through more detail a bit later.
We have announced early this quarter 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 project, which is the Power from Shore on Draugen and also from 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. Going back to the point on volatile prices, as you can see here, we've had a strong increase in prices earlier this year. During this quarter in particular, and especially on the gas price, we have seen a 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. As you can also see here on the forward curve, we do expect a very strong market for gas pricing also this winter. It seems like the pricing is converging later on this fall. Also the U.K. prices 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 our products.
Production volumes, we've increased our production volumes again compared to the last quarter. 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 reliability on Draugen. 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 guidance. For the exposure, we have 32% gas in the portfolio still. Very high reliability still, although a bit lower on Gjøa due to the tie-in of a new project, 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 one incident, and that's the power outage we had during the first quarter that was investigated. Due to the interruption of fire water protection on the platform for a very short period, we have classified that as a serious incident. That's added to the one with the loose handrail that we had last year. 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 real commitment to the HSE for our people working on our installations.
We still had zero hydrocarbon leaks, and for the CO2 emission, you 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 already electrified platforms and assets like Gjøa, like Yme also, will further reduce this number. The big impact will be when we are executing on the electrification project for Draugen that we are doing currently. Going to Draugen, very good performance, above 7,000 bbls 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 are 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 to spud the well that we will drill this year for the customers. Then we will initiate during the second half of the year, the top side installation on the Draugen. We are still planning for production start in Q4 in 2023, with an expected gas production of more than 4,400 bbls of oil equivalent 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 it 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 on the previous slide as well, reducing the CO2 emissions on Draugen by 95% when it's started. That is more than 200,000 tons of CO2 reduction from Draugen. And in addition, there will be 150,000 tons 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 on that one, and there's a public consultation process ongoing for that project.
Moving on to Ula, a very important asset still for OKEA. That's also the one that gives us most gas exposure today. That's also why we saw that we had a shortfall in the gas earlier this year because Ula was down for the planned tie-in job, very early in the quarter. Production very similar to Draugen, and a very high production reliability of 97%. We also, as I just mentioned earlier, we confirmed the Hamlet exploration well, earlier, this quarter. 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. Again, just a reminder on the volumes that we are talking about, the operator's preliminary estimate is 8 million-24 million. That is part of that development.
Then, Yme, average production during the quarter was 1,322 bbls, which as I just mentioned, is lower than we expected. The average production now from four existing wells that we have in operation now gives us a daily production of around 3,500 bbls of oil per day. It's increasing, but it's delayed compared to what the previous assumptions were. We do have two 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 programmed 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, the guidance for production this year for OKEA, but also a positive impact in 2023 as we are pushing it to the right. Ivar Aasen asset production of 550,000 bbls of oil per day. That has also increased. Ivar Aasen also had some issues during this quarter as they did not have you know, proper power supply from Edvard Grieg field. That happened around the 27th of March.
They started partial production on the 21st of April, and we're back in full production from the 24th of May and it's now, you know, producing in accordance with plan, which means that a daily production to OKEA is closer to 1,000 bbls of oil per day currently, but the average for last quarter was 550 bbls. 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.
We will now be very close to a 10% partner in Ivar Aasen. 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. We are in a very good position to do these kind of transactions with the financial position we have. As you will also see in this transaction, 80% of the decommissioning of Brage still remains with Wintershall Dea there, and that is also something we did back with Shell when we took the Draugen asset over. 80% remains with the current operator.
We also see as we are growing the organization, that we are seeing annual cost synergies of NOK 4 million-NOK 7 million across our operated portfolio. This is a significant move for OKEA on our growth strategy. We are moving then from four producing assets to actually six producing assets, so it's an increase of 50%. We did have a plan of 21,000 bbls of oil at the end of this year in production. With this transaction, we are adding 7,000 bbls more. This will also then diversify the portfolio that we have and go back to what I just mentioned on the volatility in the market. This will further strengthen OKEA when we have continued volatile markets as we will have more even production. This is important transaction for OKEA in many respects.
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 very near-term value creation. It gives us an opportunity to grow the organization to also take more assets in the future. It gives us, as I just mentioned, a larger and more robust portfolio that give us more resilience as a company.
One of the main drivers also for this transaction is that OKEA is already an operator on the Norwegian continental shelf, which is, you know, a prerequisite for actually executing on these kind of transactions and deliver more value from these assets. 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. With that, I'll hand over to you, Birte.
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. Today, we also announced a full buyback of the OKEA02 Bond, which will reduce our finance cost 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 guidance 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. Let's start with our production and sales.
In the second quarter, we produced 16,039 bbls of oil equivalent per day, which is an increase of 1,131 bbls compared to previous quarter. It is the solid performance from Draugen and Gjøa which drives the increase despite the eight days of planned shutdown at Gjøa in the quarter. The majority of the shutdown scope was related to tie-in projects for which Gjøa will be compensated. Yme contributed with 1,322 bbls per day, and Ivar Aasen contributed with 550 bbls 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 first 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 bbls of oil equivalent per day was an increase of 513 bbls 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 bbls 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 volume 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 $100.30 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 million, 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 two years, and the volatility has been high at high price levels in the last two quarters in particular. The graph to the left illustrates the OKEA-allocated liftings of liquids over the last five quarters. In the second quarter, OKEA had six partial cargoes with crude lifted, with the majority of the volumes received in April.
We had one lifting from Draugen at 632,000 bbls, two from Gjøa for a total of 74,000 bbls, and three liftings from Yme for a total of 132,000 bbls. We also illustrate the completed and planned cargoes for the third quarter. One lifting has already been completed and is marked in dark blue with 48,000 bbls from Yme in the beginning of July. Marked in light blue is the expected liftings for the third quarter, which includes 633,000 bbls from Draugen and 60,000 barrels from Ivar Aasen in July and 157,000 bbls from Gjøa in August. Although we expect further crude liftings from Yme in the third quarter, we still do not provide further guidance 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 periods. Currently, we export our physical flow of gas to U.K. on day-ahead prices.
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. 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 eight days of downtime at Ula 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. Let's look at the profit and loss.
The operating income of NOK 1,332 million mainly consists of petroleum revenue of NOK 1,254,000 ,000 and other income of NOK 78 million, which includes a net gain on hedging positions of NOK 41 million and tariff income at Ula of NOK 26 million. Production expense of NOK 381 million or 235 NOK per barrel, compares to 192 NOK per barrel in the previous quarter. Production expense is high this quarter, mainly due to high cost at Yme due to well re-completion 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 Ula and production interruptions at Ivar Aasen also increase 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 rounds 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 interest expense 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-denominated debt amounted to NOK 338 million.
This is partly offset by a gain of $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 1,060,000 ,000 and includes a partial prepayment on the Wintershall Dea transaction of NOK 97 million. Tax payable was NOK 1,298,000,000 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 2,182,000,000 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 spent on dividend distribution of NOK 93 million, and a buyback of OKEA 02 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 1,085,000,000 , and the taxes paid of NOK 286 million relates to the last two 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 OKEA 02 Bond and the semi-annual payment on the OKEA 03 Bond. 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 90 øre per share. Our solid cash development the first half of the year can be attributed to a strong market and good performance on Draugen and Yme.
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 the first of January this year, with the most prevalent feature of being a more cash-based system where capital expenditure is expensed immediately in the special tax and without any uplift.
Any 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 six years depreciation and uplift in the special tax under the former system. According to our estimates, the break-even discount rate between the two 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 bbls-20,000 bbls per day to a range of 16,000 bbls-17,000 bbls 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 a level around 28,000 bbls per day as at the end of the year when Yme is expected to be in full production and Nova is on stream. In addition to our own produced volumes, we expect between 900 bbls and 1,200 bbls 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 bbls-19,000 bbls per day to a range of 25,000 bbls-27,000 bbls 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 Vega. For 2023, the net effect is more or less zero, and the previous outlook of 600 bbls-800 bbls per day for 2023 are therefore removed. The CapEx guiding for 2022 remains in the range of NOK 950 million-NOK 1,150 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 90 øre per share for 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. The board has now resolved 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 and NOK 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 second of September, and the payment date will be on or about the 15th of September. 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 saving after tax is estimated to about NOK 55 million compared to settling the debt at maturity in June next year. That's all from me for now, and I'll give the word back to Svein for some closing remarks. Thank you.
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 the material acquisition from Wintershall Dea, which has been fully funded by cash that we have in the company. In addition to adding volumes, 7,000 bbls of oil equivalent, whereof 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 showed continuous 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. We expect continued strong performance from those two assets.
We have a delay on Yme. It's going slower than projected, but, you know, producing today much higher than what we have seen for an average over the last quarter. Yme will come, but we are moving then the plateau from third quarter to the fourth quarter or the end of the year. 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 aim to do the 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. We're also actively reducing our debt, which is further strengthening our position.
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. Before then, moving over to the Q&A session, I would like to thank everyone for your attendance and thank you for following OKEA. I would also use the opportunity to wish you a great summer. I'm looking forward to speak to you again latest in October when we are producing our Q3 numbers, but hopefully before that. With that, I would like to thank you all. Bye.
Ladies and gentlemen, if you have a question for the speakers, please press five star on your telephone keypad. To withdraw your question, please press five star again. We will have a brief pause while questions are being registered. The first question is from the line of Teodor Nilsen from SpareBank 1 Markets. Please go ahead, your line now will be unmuted.
Good morning, Svein and Birte, and thanks for the update. Three questions from me. First on the gas exposure TTF versus NBP after the closing of the Wintershall Dea deal. Will you still have full exposure to NBP or will that change after the deal closing? Second question, a general question on the NCS M&A market. Do you view that as a buyer or seller's market now? Would your preference be gas assets or oil assets going forward? My third question is also just a general industry question on cost increases. Looks like, well, in any industry these days, cost increases is increasingly important topic. So just wondering what do you see on your assets there? Thanks.
Yes. Hi, Teodor. As for, I can, I think I can answer your first question, and let Svein answer the two last ones. 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. We do have flexibility to route those to the continental Europe market. That will also be the case for the Hasselmus's gas when Hasselmus comes on stream next year. Svein?
Yeah. Morning, Teodor. Quickly on the two next one, the NCS M&A market, seller or buyer's market. I still believe it's possible to do, you know, strategic good transactions, like we did, like we have just done. Obviously, we are positioning us to do that. You asked if we are exposing ourselves toward gas or any preference between gas and oil, and I would say we have 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 a kind of diversity with both partner operator, but also the operated asset.
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 will be a, you know, price increase in the market. 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 pricing, in particular for cables, et cetera, for the Power from Shore project. They're not something that is challenging the project as such. We think the main exposure and the main constraints will be apparent next year.
Okay. Thank you.
As a reminder, please press five star on your telephone keypad to ask a question. We'll have a brief pause while questions are being registered. As there are no further questions at this moment, I will now hand the word back to the speakers.
Yeah. We have a question from the web as well from John Olaisen from ABG.
What is the production capacity at Yme given the production and what is Yme producing at volume? How I understood correctly will be lowered by portfolios free cashflow in terms of credit too. If so, it's possible to give some indication of the expected free cash flow? I presume CapEx that the Nova development will soon be the free cashflow down including the Nova CapEx.
Okay. I can answer the first part and then I will handle with a different. On the Yme production capacity, currently, it's around 25,000 bbls-26,000 bbls of oil per day from these four 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 we have been around 25,000 bbls of oil and that is from half of what we have now. The few production capacity is we have four more well that will create during the second half of the year and as we have said before the was expected to be in excess of 50,000 bbls of oil per day on Yme while it's.
Yes, I can take it over and if you have understood it correctly. Will be lower than the portolio's cashflows in 2022 prior to the competing date. And I could also emphasize that will be free cash flows prior to completion date. We have some indication providing guidance on that but I guess I can say it's quite significant than giving a rough indication of maybe around half. Of course, that's when.
Okay. If there are no more questions, I think we'll just wish you all a good summer, and thank you for participating. Do not hesitate to get in touch if you do have any other questions to Svein or myself. Thank you.