Good morning, welcome to the presentation of the First Quarter Results for OKEA 2023. My name is Svein Liknes, I'm the CEO of OKEA. Together with me today, I also have Birte that will take you through the financial section a bit later on. We will have a Q&A session after this presentation, there will be a link on our homepage that you can go into and also submit questions as we present, but also there will be lines open so you can call questions afterwards. That will come after our presentation. I cannot talk about the first quarter of 2023 without going into the transaction we did earlier this year, when we acquired or at least signed a contract with Equinor to take over 28% of the Statfjord asset.
Statfjord is one of the greatest assets which has been on the Norwegian Continental Shelf and still has many years of production left. This will actually take the company OKEA from a daily production now of which we have guided this year between 22,000-25,000 to just short of 40,000 by the end of this year and beyond 40,000 next year. This is a truly transformational deal for OKEA which gives us a scale we are looking for. It is 28%, as I said, of the whole Statfjord area, which consists of four different fields. It's a material increase in the 2C reserves for the company. I'll get back to the details a little bit later on. It also gives us a much more diversified portfolio of a product base.
It also initiates OKEA going into new licenses and also working closely with Equinor on Statfjord, which we are looking forward to learn on mid to late life assets. It enhances OKEA's financial flexibility for the future and our future growth strategy. As you can see here, it will increase the production by 13-15 thousand barrels of oil equivalents per day this year, and it will be between 16,000-20,000 next year. As you can see on the portfolio here, it is a good balance between oil, gas and NGL in that portfolio. As I just mentioned, we are then moving OKEA from six fields in production to 10 fields in production, which is an increase of 67%. It increases our production by 60% this year.
It increases our two-period reserves to above 100 million barrels of oil equivalent from 60 to around 101. It also adds 2C resources of 8 million barrels. OKEA has also identified 14 million barrels of oil equivalents in addition to these 2C resources that we believe can be extracted from the area with future infill drilling in 2028 and beyond. This is then the curve or the journey that OKEA has been on. We are still committed to our strategy where we are finding value where others are divesting on the continental shelf, and we are delivering in accordance with the strategy that we set out in 2021 in October.
This is then, as you can see, in 2018, the big milestone when we took over Draugen, arrested the decline in production and then did transactions last year when we took over something from Neptune or increased stake in Ivar Aasen from Neptune and also did the Brage transaction. You can see the significance of doing this transaction with Equinor that definitely lifts the company into a new scale. That will continue. As you can see, we have a dotted line here that takes us beyond 40,000, and that is because we are not guiding 2024 production at this point in time, it will take us in excess of 40,000. I will get back to the exact number on a later presentation this year.
Bringing it down to this first quarter, what we have delivered is in excess of 22,000 barrels of oil equivalents per day. We have continued strong performance on Draugen, Ivar Aasen and on Gjøa. We are seeing increased performance on Yme and also continuing to drill wells on Yme. Nova, as announced last year, is now starting a program where we are drilling a sidetrack on the water injection track. We are also seeing improvements on Nova now. I've just mentioned on our portfolio that we have done the inorganic growth with the acquisition of 28% in the Statfjord area. I also would like to highlight that we're also working on organic growth. The Hasselmus project is progressing according to plan.
As you can see on the photo here last week, actually, this photo was taken when we started pulling in the flow line from the Hasselmus project, which still is online to actually start producing in Q4 this year, which will give us 4,400 barrels of oil on plateau of pure gas to Draugen. We also received or got four exploration licenses in the APA rounds in 2022, which was awarded to us very early this year in January. We are focusing both on our inorganic growth, but we are also maintaining a focus on organic growth in the company. Financials. We have a record high operating income this year of very close to NOK 3 billion.
We did take an Yme impairment again of NOK 94 million due to water cut in the wells that we have produced over the last quarter. We are reducing the reserves slightly there as well. We are again net debt-free in our cash position. We have continued to pay dividends in accordance with the plan we have previously announced with dividend paYments in March of NOK 1 per share. We are also continuing that program to also pay NOK 1 per share in June for the second quarter of this year, in accordance with what we have communicated previously. Quarterly key figures. Serious incident frequency has increased. That is due to two isolated dropped objects on our platforms. One was related to during a hurricane during New Year Eve.
That actually is one of them. That trend is something we need to address and also arrest. You can see the CO2 emissions intensity of that is still 22, and that will significantly drop as we are electrifying Draugen, which is currently happening in 2027. Obviously the intensity will also drop as we are increasing and ramping up production both on Nova and also on Yme. Production numbers, as I mentioned, 22,200 barrels of oil per day. We are maintaining the guidance between 22,000-25,000 for this year. We have arrested the production expense which has increased during last year and as you can see here, we have now reduced it slightly in this quarter again.
We have very strong cash flow from our operations and as I just mentioned on a previous slide, we have continued to pay the dividend in accordance with the plan that we have previously communicated. Production and reliability. Very strong production reliability on all our assets. What you can see on Brage there is a slight drop from 99% - 92%, but that is mainly due to planned well maintenance and there was also power generation trip in January that contributed to that. You can also see on Ivar Aasen that the production reliability has dropped slightly, but that was due to a planned six-day outage that the Ivar Aasen asset had during the quarter.
On the top figure here, you can see that, you know, maintaining good production from all our assets, actually all our assets is increasing and we are then up to 22,200 for the quarter and are continuing to increase that number during the second quarter. My final slide before we hand over to finance and Birte is the operational update. I'll go through this in short. On Draugen platform, as I just mentioned, we are continuing with the Hasselmus tieback progress. Actually we do have a turnaround on Draugen right now. There will be a 2021-day outage from Draugen this month. A lot of the work associated with the Hasselmus tieback will happen during this month. That will then increase production in Q4 when we start the Hasselmus.
We have also submitted a lifetime extension application for Draugen from 2024 to 2040, which is in the heart of actually our strategy to go into assets, find value, and then extend the lifetime of these assets as we are extracting that value. Going to our second operated asset, Brage. Production has been impacted by some wells which had more water ingress during the Q4 or Q3 actually last year during the turnaround. That is gradually being produced out. Production there, as you could see on the previous slide, is also increasing.
Interesting thing on Brage as well is that we are working very closely with DNO now to actually develop and see if we can mature the Brekke discovery, which is 30 million barrels of oil, 13 kilometers south of Brage, and develop a case where we actually can mature this into the Brage platform. That work is now ongoing. Very good performance on Ivar Aasen and very well operated, so very steady production and very high, actually 100% production reliability during the quarter. We are working together with the other license partners to see how we can develop the Hamlet discovery that was discovered last year into Ivar Aasen, maybe together with other resources in the area. Ivar Aasen, very strong performance. Slight power outage in the power from shore actually during the quarter but that they recovered good from.
Strong performance also from Ivar Aasen during the quarter. When it comes to Yme, we are now completed the Bay du Nord drilling campaign. New wells is being added. We are producing in excess of 3,000 barrels of oil per day on Yme currently, and we do expect 5,000 when we reach plateau at the mid of this year. We are continuing to drill new wells in the Gamma reservoir now, and those wells will be completed in July and also in August. That will then bring the Yme asset up to the plateau level. When it comes to Nova, we are actually entering the water injector there as we speak this month to do a sidetrack to reestablish the water injection that we have previously also communicated was disappointing last year.
Now we are reestablishing that water injection in Nova that will bring it up to the production level that was in the original plans. There will also be a new water injector on Nova drilled next year to further increase recovery from that asset. With that, I will hand over to Birte that will take you through the financial section. Then I'll come back for a quick summary before we go into the Q&A session thereafter. With that, I'll hand over to you, Birte.
Thank you, Svein. This quarter is the first quarter with the full effect in the profit and loss statement of the portfolio of assets acquired by Wintershall Dea . It's a quarter that's also characterized by recovery of previously built up underlift positions at Brage, Draugen, and Ivar Aasen, as well as significant realized gains on physical gas hedging, which drives up the realized gas price. Jointly, these effects resulted in a record high operating income for the quarter. It also results in a strong cash generation, and at the end of the quarter, our cash position exceeded our remaining outstanding bond debt. Let's dig into the details and starting with our production and sales. We produced 22.2 thousand barrels of oil equivalents per day in the quarter, which is an increase of 2.3 thousand barrels compared to previous quarter.
Draugen, Gjøa, and Ivar Aasen continue to produce well, and as Svein outlined, production at Yme, Brage, and Nova is improving. Due to recovery of a significant underlift position at the end of 2022, sold volumes was nearly 38,000 barrels per day on average. This includes two liftings at Draugen compared to normally one in a quarter, one lifting each at both Brage and Ivar Aasen, and several liftings from Yme. Net compensation volumes from Duva and Nova amounted to 448 barrels of oil equivalents per day. Gas prices have been relatively stable during the quarter, and the average realized price for natural gas of $116.3 per barrel was a slight increase from the previous quarter.
Note that the realized price is higher than the observable market prices for NBP, as it includes a gain from fixed price contracts equivalent to $21.1 per barrel. As a result of physical contracts, these hedging gains are recognized directly in the realized price rather than in other income, as is the case for the gain on the derivative financial instruments. Liquids have fluctuated somewhat more during the quarter, and the average realized price for liquids was $77.7 per barrel. Overall, this resulted in total petroleum revenue of $2,929 million. Despite some fluctuations in the crude price during the quarter, the price started and ended around $80 per barrel. The graph to the left illustrates the OKEA allocated liftings of crude over the last five quarters in blue.
Following the increase in production and the overlift position realized, OKEA had 11 cargos with crude lifted in the quarter. We also illustrate the planned cargos for the second quarter, marked here in gray. We expect a 646,000 barrels lifting from Draugen in May and a total of three liftings, amounting to 201,000 barrels from Yme. In June, we expect 300,000 barrels from Ivar Aasen and 350,000 barrels from Brage. The timing of the Brage lift is expected at the very end of June, and in case of a slight rescheduling, it could slip into the third quarter. The graph to the right outlines the difference between the average market price of Brent for the quarter of $81.1 per barrel compared to the average realized price for OKEA.
The difference partly relates to timing effects since both of the Draugen cargos were lifted when prices were at lower levels than the average, and this is only partially offset by both the Ivar Aasen and the Brage lifting taking place when the prices were at higher levels. The adverse impact from NGLs this quarter was equivalent to $2.9 per barrel, which is more significant than normal, and this is due to larger than usual amounts of NGL volumes being lifted in the quarter. Here we illustrate the average volumes of gas sold per month since January last year and the observable monthly average market prices in the same period. We still export most of our gas to UK on NBP day-ahead prices. Following extremely volatile prices over the last year, prices were relatively stable during this first quarter.
The mentioned realized gain on fixed price contracts drives Aker's realized gas prices above the observable NBP prices. Let's move on to the profit and loss statement. As mentioned, we deliver a record high operating income of NOK 2,954 million, consisting of the petroleum revenue of NOK 2,929 million and other income of NOK 25 million. Included in the petroleum revenue is the gain on forward sale of gas, which amounted to NOK 117 million. Other income mainly comprises NOK 32 million in tariff income at Yme and a net hedging gain of NOK 6 million relating to financial derivative instruments. This is offset by an unrealized loss of NOK 15 million related to the estimated value of the contingent consideration due to Wintershall. This is mainly due to foreign currency.
Production expense amounted to NOK 518 million or NOK 242 kroner per barrel. The production expense per barrel was somewhat higher than the expected average rate for the year, mainly due to the higher produced volumes expected from Yme and Brage in the second half of the year as new production wells come on stream. We recognize an impairment of NOK 94 million related to the Yme asset. This is due to higher water cut than expected in the wells already in production, which reduces recoverable reserves somewhat. We like to again remind that as the Yme asset is recognized at fair value, it means that any changes in the macro conditions and or asset performance will result in further impairments or full or partial reversal of previous impairments. As such, there is potential for some volatility to the profit and loss statement relating to Yme specifically.
Drilling of new wells at Yme Gamma started in the second quarter, and there is some certainty around the in-place oil resources for one of these wells in particular. This is expected to be clarified during drilling, and should the outcome be in the lower range, there is a risk of further impairment at Yme. Exploration and operating expense amounted to NOK 51 million and comprise SG&A expense of NOK 28 million and exploration expense of NOK 23 million. The exploration expense mainly relate to general field evaluation activities, and the SG&A is more or less at the average run rate expected. Net financial expense amounted to NOK 49 million and mainly relates to a net currency loss of NOK 30 million. Following a weakening of Norwegian kroner relative to the U.S. dollars by about 6% in the quarter, the value of our dollar-nominated debt increased.
Net expense interest of NOK 21 million relates to interest on the OKEA03 Bond and the Yme bareboat charter, and is partly offset by interest income on deposits. Tax expense amounted to NOK 894 million, which brings the net profit to NOK 226 million for the quarter, or NOK 2.18 per share. The balance sheets. cash and cash equivalents ended at NOK 1.634 billion. The increase from previous quarter mainly relates to the solid cash generation from operations. Tax payables was NOK 1.4 billion and mainly relates to the two last installments for 2022, which will be paid in the second quarter, and accrued tax for the first quarter of 2023.
Interest-bearing bond loans was just shy of NOK 1.3 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 528 million relates to our share of the future obligations under the bareboat charter of the Mærsk Inspirer rig at the Yme field. Asset retirement obligations ended the quarter just below NOK 6 billion, this is partly offset by asset retirement receivables from Shell and Wintershall Dea of NOK 3.8 billion. A result of steady performance and high sold volumes, cash generation from operations was a solid NOK 1.5 billion. Taxes paid of NOK 166 million relates to the 4th tax installments payable for 2022.
Note that the tax installments for 2022 have been reduced from NOK 509 million paid for each of the first three installments in 2022 to NOK 166 million payable for each of the last three installments in 2023. Cash use in investment activities amounted to NOK 412 million and mainly relate to investments in Hasselmus and Brage Drilling. Cash paid in business combination consists of NOK 263 million in deposit paid to Equinor in relation to the Statfjord transaction, and NOK 12 million paid to Wintershall in the final pro rata settlement. Dividend in the quarter of NOK 104 million represents NOK 1 per share paid in March in line with our dividend plan. Total cash balance ended in excess of NOK 1.6 billion.
In total, we paid dividends of NOK 2.90 per share in 2022. We have communicated an intention to pay NOK 4 per share in 2023. NOK 1 was paid in March. The board has now resolved also to pay NOK 1 per share in June according to our plan. The board is also reaffirming its intention to distribute the same amount in the two following quarters of 2023. The dividend plan for the year of NOK 4 per share represents a dividend yield of about 13%. Production guiding for 2023 is unchanged at the range of 22,000-25,000 barrels of oil equivalents per day. Production from Draugen in the second quarter will be impacted by the planned turnaround, which started in April and with expected downtime of 21 days.
CapEx guiding for 2023 is also unchanged in the range of NOK 1.7 billion-NOK 2.1 billion. Note that none of the guiding include the effects from the acquisition of 28% working interest in the Statfjord area from Equinor. We have previously stated that we expect production from Statfjord for 2023 to be in the range of 13,000-15,000 barrels of oil equivalents per day net to OKEA. That's all from me for now, and I'll give the word back to Svein Liknes for some closing remarks. Thank you.
Thank you, Birte. I will take you through a quick summary. Before we do that, I would like to remind you that we have a question and answer session after this one. There is a link on our homepage where you can ask questions, and there's also a possibility to call in during the Q&A session thereafter. Before we get to that point, let me give you a very quick summary. OKEA is continuing to deliver on the strategy we presented in October 2021. We have delivered several transactions, and a significant transaction during the 1st quarter this year was signed by Equinor, where we are taking over 28% of the Statfjord field, which is significantly increasing production on OKEA. In addition, we are also focusing on our organic growth through our projects.
Hasselmus project will be delivered in Q4 this year, increasing also production over Draugen. We do have a record high operating income this year or this quarter. We have a very solid cash position to actually continue the path we are actually on, and we are also delivering in accordance with the dividend plan as we have previously announced, and we would like to continue to do so. With that, I will thank you for your attendance during this presentation this morning. We will now have the Q&A session, and we hope that you will stay behind and ask some questions, and we will try to answer as good as we can before you are jumping into the Equinor call at 11:00 A.M. this morning. Thank you very much.
Thank you. If you do wish to ask a question, press five star on your telephone keypad. To withdraw your question, 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 SB1 Markets. Please go ahead. Your line will now be unmuted.
Yes. Thanks for taking my questions. Congrats on the strong set of numbers. A few questions from me. First of all, on the general capital allocation framework. As you highlighted, Svein, you now have a net cash position. Should we expect the company to be running with a net cash position going forward? Second question is on cash. That's actually two questions. Did I interpret you correctly, Birte, that you said that second quarter cash tax paYment will be NOK 166 times two, or what do you expect as cash tax paYment in second quarter? The second question on tax is that if you could provide an estimate of the tax payable for Statfjord that OKEA will pay in 2024.
Final question from me that is related to the cost of the overlift of Brage. I definitely understand the dynamics there with the allocated purchase price that have been expensed this quarter. Should we expect the size of the overlift cost to be the same at the high overlifts of Brage for next quarter? What is that one off in the first quarter? That's all. Thanks.
To answer the capital allocation, yes, you are correct in observing that we are now net cash positive, but bear in mind we also have the settlement of the Statfjord transaction coming up this year. We have at the moment quite low leverage. We only have the outstanding bond of $120 million, OKEA03, which also matures at the end of next year. It is a natural time for us to start looking into how our capital structure should look like going forward. However, the market conditions doesn't appear to be quite right at the moment to have any urgency in that respect. You also asked about the tax to be paid in the second quarter, and you have interpreted our presentation correctly.
We expect the two remaining installments for 2022 to be paid, each amounting to NOK 166 million. As for this tax on Statfjord, we do not provide any guidance on that, and that will also depend on how prices and how the units and the wells performs the rest of the year. It's not something we generally guide on our expecting tax paYments. Finally, the cost of the overlift on Brage. Yes, it is correct that that is a one-off in a sense because on the because of the Purchase Price Allocation, we acquired in fact quite a significant volume of oil on tank when we took over the assets on effective date at the 31st of October.
That is for Purchase Price Allocation purposes recognized at fair value, which basically means the market price of oil at completion date. That is now being lifted, so that is not to be repeated in future quarters, to that extent at least.
That's clear. Thank you.
Thank you, Theodor. The next question is from the line of John Olaisen from ABG. Please go ahead. Your line will now be unmuted.
Thank you very much. We had a huge overlift in Q1, but over time, over and underlifts in net equals production. I just wonder, at the end of Q1, what is your net position? Are you in a position where you have, over time lifted more than your underlying production, i.e. in net we should expect underlifts going forward or vice versa? Is it possible to give an indication about that, please?
I think it's fair to say, John, that we had a quite unusually large underlift position built up by the end of 2022. As you know, particularly, Draugen, for example we have between four to five lifts generally each year allocated to OKEA. We had two lifts in January, which kind of recovers our underlift position more or less. The effect of Brage was unusually high because of at least for how it's recognized in the P&L because of the recognition at fair value. Basically the cost was more or less the same as the revenue on the volumes that was on tank at the 31st of October. It is an unusual situation. We could see some over and underlifts going forward as well, but unlikely to this extent that we saw in this quarter. I'd like to say also that cash-wise, this has less of an impact because for most of our volumes, we receive paYment on a monthly basis.
This is more an accounting recognition topic rather than a cash flow matter.
I guess it's cash flow as well 'cause you get the lifts of volume physically, don't you? So you-
Yes, we get.
The cash flow is related to revenue, right?
The paYments occur on a production basis. Based on monthly production, we get paid for most of our volumes.
Right. Right. The physical is just... All right. I didn't realize that. Is that how it works in all your fields?
Can you repeat that, John?
Is that how it works in all your fields? Cause I thought normally you wouldn't get paid in cash, you get your proportion of the volume every time you lift. Isn't that the case normally?
We have included it in most of our new agreements, so I think the exceptions to this rule is Draugen and Yme. For Brage, Nova, Gjøa.
Okay
we receive the paYments on a monthly basis.
All right. All right. If I can just make sure I understood you correctly. It means basically you are now in an over under lift position which is fairly neutral. For the average for the rest of the year, we should expect, or of course it could depends a lot on Q4, but normally over lifted volume and produced volume for the rest of the year would be the same number. There's no reason to expect a huge reversal of the over lift for the average for the year, for the rest of the year.
We cannot guarantee anything on this because we don't control all the lifting schedules ourselves. Of course this is something we are also focused on. I think importantly, most importantly to us is the cash part component of it, and less so with the actual timing. I don't expect a such a significant over under lift situation that we saw now in Q1.
My final question is just on some details on the CapEx distribution for the rest of the year. Is it possible to give some indication of which quarter will be more heavy on CapEx, please?
It will be, as you have seen from this quarter, it will be a bit more capital intensive at the remainder of the year. We don't provide guiding on a quarter by quarter basis.
Okay. Thank you very much. Have a nice day. Thank you, Birte.
Thank you.
Thank you, John. As a reminder, press five star on your telephone keypad to ask a question. The next question is from the line of Steffen Evjen from DNB Markets. Please go ahead, your line will now be unmuted.
Yeah. Hi, guys. Thanks for taking my question. I have three questions. First one is on your discoveries on Brasse and Hamlet. Could you share some more color on the timeline here and what sort of progress you're making on those discoveries, and if we can expect any PDOs this year? My second question is on Uar. I think production there has been fairly stable and I guess someone has expected the specific gas production there to decline going forward. Do you have any reflections on what we can expect from Uar for the rest of this year and into next year? Thirdly, could you provide an update on the exploration wells you're spudding this year, and any resource estimates as well would be highly appreciated. Thank you.
Yeah. On the Brasse and Hamlet, the Brasse discovery, obviously, we are now working together with the operator, DNO, to see if there's a viable solution. Obviously we will not get to a PDO stage on Hamlet. No, sorry, on Brasse. Most likely we will in the middle of the summer, I think, we will get to a point where we can have more firm, you know, decisions on if we want to take the project further. Obviously, no PDO for this year. We have decided to continue the study now, and obviously that's a good indication that we think it's viable. Obviously we are maturing the project. When it comes to Hamlet, we did not sanction the Hamlet last year.
We are working together with the other license partners in Hamlet, also looking on area solutions on how that actually can be developed jointly together with other resources and then take it back to Uar. That is also ongoing, but we do not have any schedule for a PDO for Hamlet this year as well because the other resources in the area still needs to be further appraised. The focus on Uar, as you correctly mentioned, Uar has been an extremely steady performer and producer. We have no reason to believe that it should not continue. Obviously we are also producing Nova over Uar, so the asset performance from Uar is quite important for us.
As all other assets on the sector, you know, we are working continuously to fill the hub port to ensure that the plant is full on Uar. There is no reason to expect any significant decline in production from Uar this year. For exploration wells, this year, we do have one well that we are planning on spudding, but we do not have any estimates on the volumes for it currently. Last year, I think we took part in three wells. This year, most likely it is one well, and that is, you know, we are trying to take part in one to three wells per year.
This year it is only one, but that is because in the sequence of wells, it didn't stack up to be three wells this year. We do have quite a raft of decisions on new wells coming up in Q1 and Q2 next year. For this year there will be only one well.
Thank you. That's very clear. Thanks.
Thank you, Steffen. As there are no further questions on the call at this moment, I will hand it back to the speakers for any written questions.
Thank you so much. Good morning, everyone. I'm Anca Jalba, heading up Investor Relations and Communication in OKEA. I'm going to read the questions submitted via the chat here. The first questions come from John Olaisen in ABG. The first one is adding up the planned liftings in the second quarter from the outlook section in the first quarter report. It seems that 16.5 thousand barrels per day is planned to be lifted net to OKEA in if there are no liftings occurring in April. Can we thus expect an under-lift position for the second quarter in the range of 5,000 barrels per day? How should we think about the volatility in under/over-lift going forward?
Yes, I think we have replied to some of this already through the questions from John. I think the mathematics here, this is just probably only considering the oil, bearing in mind that about 25% of our production is gas, which is, it goes through the pipelines every day, so not lifted as the oil is. As mentioned, I think we are now more or less on an even position under over-lift, that could change going forward, but not to the extent that we have seen in this quarter.
Thank you, Birte. The second question from John Olaisen: Assuming the in-place oil resources of the to-be-drilled production well at Yme is in the lower range of expectations, will plateau of 5,000 barrels per day be impacted, or will lower expected reserves only lead to a more aggressive depletion rate?
The answer to that is obviously the well potential will impact the production rate of the platform. It could be impacted on the overall daily production volumes. There is two wells actually to be completed in the Gamma reservoir on Yme, one which is handed over in July and one in August, we have one injector also to be drilled later on this year. When we have the full well stock up running as well, further optimization and also trying to identify further targets is obviously a potential in the area. That is something we will continue to look at when it comes to the depletion rate, but it can be impacted, the plateau, overall production on results from this well.
Thank you, Svein. The next question submitted comes from Roald Hartvigsen in Clarksons Securities. Can we give some color on how new production wells on Yme and Brage are expected to impact production costs over the next quarter? Can you elaborate on how lower gas prices are affecting your hedging strategy for gas?
Yes. Thank you, Roald, for the questions. Yes, as the volumes are increasing, as you see, we keep our guiding, and we are currently in the lower end of the guiding. We expect also a lower production now in second quarter due to the maintenance at Draugen, but following getting new wells on stream in the second half of the year, we expect that that will drive down the unit cost compared to what we are reporting in the current quarter. Your question on gas and hedging, I think we took quite an opportunistic view on hedging when we saw the very high and very volatile gas market last year.
We took a prudent and opportunistic approach to lock in prices when we saw they were at the, I would say, maybe even more than acceptable levels. Obviously, when prices have come down, that is a strategy that is revised, and we're always, or continuously I should say, assessing our hedging strategy in view of the market and our own liquidity position. Obviously it has changed compared to the hedging positions that we entered into last year.
Thank you, Birte. The next question submitted comes from Sander Solheim Nilsen in Fearnley Securities. We have four questions here, even though a couple of them have already been addressed in the previous answers. I will read them all, though. What are the main drivers for the reduced 2022 tax payable in the first half of 2023? Second, how should we look at capital allocation beyond 2023? The third, how will Statfjord impact the emissions intensity for the overall portfolio in 2023, if applicable, and 2024? The last question, in a perfect world, how fast could Bressa be developed?
Okay, maybe I can take the first two, and then you take the second two, Svein. The main drivers for the reduced tax payable in the first half is, you know, when we first report our expected tax payable for the full year, we consider how the market looks at the time. We look at lifting schedules and all our everything in our forecast. I think the key drivers for the change that has taken place when we provide our updated tax estimate is, one, that the revenue has come down. We've seen prices come down. Also we have there's some reallocation in the lifting schedule. For example, as you have seen, we have quite significant liftings in the first quarter, and then they are taxable in as part of the 2023 tax.
If we had lifted in December, it would have been taxable for 2022. Changes to lifting schedules like this, as well as a reduction in revenue in general is the key drivers. Capital allocation beyond 2023, you know, our principles still remain. We are always trying to balance direct distributions to shareholders to value accretive growth. It will depend on how we what targets are in the market and how we succeed in our M&A efforts. I think that's over to you, Svein.
Yeah. On the Statfjord transaction on the CO2, actually it's pretty much in line with what we have in our emissions currently. There is a slight increase, but also the Statfjord asset has already started projects on how to reduce CO2 emissions on the field. We will over the next couple of years as well go a bit up and then down again when it comes to CO2 emissions. The biggest impact in our portfolio is obviously the electrification of Draugen which will take place in 2027, which will have a significant impact on our CO2 emissions. In a perfect world, how fast could Brasse be developed? Well, we do have a line of sight now to actually mature the project going forward.
I would say anything sooner than 2026 I think will be unrealistic when it comes to Brasse. If a fast-track project could be executed, I would say 2026, and P50 most likely early 2027 in a normal kind of project development scenario.
Thank you so much. This concludes the submitted questions in writing. I'll hand it over to the operator to see if there's any more questions on the line.
No, there are still no questions on the call at this moment. Yeah, I'll just hand it back to you for any closing remarks.
Yeah. Thank you very much for calling in and also taking part in our presentation for this quarter. Again, very strong quarter for OKEA. Obviously we are looking forward to meet you again for our second quarter presentation later on in July. Thank you very much for your attendance.