Aker BP ASA

OSE:AKRBP

Earnings Call Transcript 2021-Q2

[Kjetil Bakken, Vice President of Investor Relations]

Good morning, and welcome to Aker BP's Second Quarter 2021 Conference Call. My name is Kjetil Bakken, and I am Head of Investor Relations. Today's presentation will be given by our CEO, Karl Hersvik; and CFO, David Tønne. After the presentation, we will open for questions. And if you have any further follow-up questions, feel free to contact us after the call.And now without further ado, I give the word to our CEO, Karl Hersvik.

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you, Kjetil, and good morning to all of you listening in. Let us start with a high-level summary of the Aker BP's performance in the second quarter.On the operational side, the quarter were characterized by planned maintenance and modification activity. And as expected, this resulted in somewhat lower production compared to the previous quarter. Still, our revenues were stable due to increased oil and gas prices, and maybe more importantly, we delivered the significant maintenance and modification scope with safety, efficiency and cost discipline.One of the key features of Aker BP is our large hopper of organic growth opportunities. And we have previously shown you our list of prioritized project that we aim to FID before the end of 2022. The work to mature this project progressed well in the second quarter, and we ticked off the first item on the list when we submitted the PDO and the plan for development of our operations of Kobra East & Gekko, or KEG for short, in June. This is a subsea tieback to Alvheim. We also made good progress on the rest of the portfolio, including NOAKA, which we will come back to in a few minutes.On the financial side, we delivered record high operating cash flow in this quarter. We also issued our first bond in the euro market, which opened up an additional funding source for us and demonstrates the strong support for Aker BP in the capital markets. David will, of course, come back to this in his financial review.Now let's take a look at the operational performance in the quarter. The Q2 production ended at 199,000 barrels per day, roughly 10% down from Q1. And as already mentioned, this reduction was mainly driven by planned maintenance. Smart maintenance is one of the key elements of the Aker BP new operating model, and we have made several changes to our maintenance strategy over the last year to standardize the way we work across our asset base.One element in this strategy is to bundle maintenance activities together in campaigns, which are planned in detail to ensure high precision and high quality. This way, we aim to minimize the overall downtime of our assets and, hence, drive production efficiency up. We have established specialized maintenance teams to lead this work, which enable us to build competence and ensure sharing of expertise across our asset base.In Q2, the planned maintenance accounted for more than 2/3 of the gap in gross production efficiency. In volume terms, net to Aker BP, this amounts to a reduction of roughly 20,000 barrels per day. Half of this was driven by Skarv, where we, in addition to the normal testing and inspection activities, performed a major upgrade of the processing capacity to cater for start-up of Ærfugl Phase 2 as well as other future tie-ins. We also had maintenance campaigns at the rest of our operated hubs in Q2, which included mandatory emergency shutdown tests, repairs and upgrades of equipment and preparations for new tie-ins. All of these activities were successfully completed on schedule and in line with our high safety standards.Our overall safety performance continues to be very good. In the second quarter, we recorded one personal injury of moderate severity. This is, of course, one too many, but the trend is good, and the absolute level compares favorably to the industry average.Our CO2 emissions is also showing a good trend and currently stands at 4.2 kilos per barrel for the last 12 months. This is less than 1/3 of the global industry average and puts us firmly among the cleanest oil producers worldwide. As the cost of emitting CO2 is likely to increase over time, this is a competitive advantage for Aker BP also from a cost perspective.And we are not less resting on our laurels. We continue to work systematically to improve our CO2 footprint, focusing on process improvement and energy optimization. So far this year, our operations team have identified a combined potential to cut annual emissions from our operated assets by more than 40,000 tonnes of CO2 equivalents. This would represent roughly 5% of our global total -- of our total greenhouse gas emissions, far exceeding our own targets and would be a significant achievement.Before we leave the topic of operational performance, let's zoom out and take a look at where we stand after the first half of the year. As we have discussed, we have continued the positive trends for safety and emissions. The production efficiency has been lower than normal, mainly driven by significant maintenance and modification programs in the quarter, which is now behind us. This will enable our asset base to take on higher production volumes in the future. And we are within our guiding range for both production and cost at the half year mark. In that sense, I would go as far as to say that the Aker BP operational performance so far in 2021 has been strong.Now let's move on to the things that will shape the future of Aker BP, namely our field development projects. We currently have 3 major projects ongoing, and the overall message is that we are on schedule. On this picture, you can see the jacket for the new Hod platform, which was recently installed in the field. The topside module will follow in Q3, and then the drilling campaign will start. In parallel, we are also on track with the subsea scope and the tie-in preparations at Valhall.In the Skarv area, the main activity is the completion of the Ærfugl Phase 2 project, where offshore preparations are underway. Drilling was completed in Q1 and remain on track to start production from the last 2 Ærfugl wells in Q4 this year. In the meantime, we have also completed the Gråsel project, which is a small but highly profitable tieback with a breakeven price of around $15. Gråsel started production in June 6 -- in June, only 6 months after the investment decision and 4 months ahead of the original plan.And Johan Sverdrup Phase 2 is also progressing as planned. The jacket for the second processing platform was installed in the field in June, and the 3 topside modules have arrived at the yard in Haugesund and are being prepared for offshore installation in the first half of 2022. And as I mentioned in the introduction, we are now moving into another project -- we are now moving another project into the category of ongoing projects.Two weeks ago, we submitted the PDO for Kobra East & Gekko, or KEG for short, to the Norwegian authorities, and this is quite an interesting projects. Recoverable resources are estimated to around 40 million barrels. And to reach these barrels, we plan to drill 4 multi-branch wells in the reservoir. The wells will be drilled from 2 different locations and tied back to the Alvheim FPSO. And as usual, the subsea work will be executed by the subsea alliance with Aker Solutions and Subsea 7, and a significant drilling scope by the drilling and well alliance with Odfjell and Halliburton.Total CapEx is estimated to $1 billion, and the breakeven price on an NPV10 basis is below $30. When production starts in 2024, it will boost the Alvheim area production and contribute to significantly lower unit cost and emissions intensity. And the project is also an important enabler for extending the economic life of the Alvheim FPSO and, hence, unlock other opportunities in the area. With Kobra East & Gekko, we are writing a new chapter in the proud history of Alvheim, and there is more to come.We are also closing in on the next PDO in the Alvheim area, as the Frosk development is scheduled for final investment decision during the third quarter. For Trell and Trine, we are targeting a concept select by the end of '21 and an FID approximately 1 year from now. At Ivar Aasen, the concept select decision for Hanz was taken in the quarter, and we are now aiming for a final investment decision in Q4 this year. At Valhall, we are moving forward with concept studies for a new central platform, where we are targeting a concept select decision in Q3.For those who now believe that I forgot to talk about NOAKA and Skarv, I will, of course, cover these, but separately. Let us start with NOAKA.During the second quarter, we have completed the concept evaluation for NOA and Fulla, where Aker BP is the operator, and we are now ready for a formal concept selection decision in Q3, in line with the original plan. The development concept includes a fixed platform at Frigg Gamma Delta fields operated by Aker BP. This platform will function as an area hub with processing, drilling and living quarters, and we have already secured installation capacity with Allseas.The Frøy field will be redeveloped by a normally non-manned installation, a copy in fact of the Valhall Flank West and Hod platforms, which will be the third time we're actually doing this same platform. While Fulla, Langfjellet and Rind fields will be developed as subsea tiebacks to the area hub. The oil will be exported via the Oseberg transport system, and the gas will be exported through Statpipe. And we are planning for power from shore to ensure minimal carbon footprint.We have designed this concept with flexibility to tie in additional discoveries and IRR targets in the future. And one such potential discovery is Liatårnet, where we are planning to drill an appraisal well during the third quarter. We have already started planning for the next phase and will hit the ground running as soon as the formal concept select decision has been made. The next big milestone will be the final investment decision in the fourth quarter next year.The other area I would like to cover separately is the exciting development of Skarv, where we are following what we would like to call the Alvheim blueprint, turning Skarv into an area hub.We have already talked about the comprehensive maintenance and modification activity during the second quarter. This involved a significant capacity upgrade for the Skarv FPSO to cater for both existing and new discoveries in the area. The Ærfugl development is getting close to completion. Four of the 6 wells are now in production, and the last 2 wells were completed in Q1 and will start production in Q4, 2 years ahead of the original plan.In parallel, we have also completed the Gråsel development in record time, with first oil only 6 months after the investment decision was made and 4 months ahead of schedule. This was made possible by early access to a drilling rig, combined with a very agile project team that quickly turned around and seized the opportunity when it arose.We have several commercial discoveries in the Skarv area, which we have grouped together under the name Skarv satellites. One of these discoveries are Ørn, which was originally operated by Equinor. During the second quarter, the partnership chose Skarv as the preferred host installation, and Aker BP will now take over as operator of the license. We are targeting concept select for the Skarv satellites during the first half of next year and FID before the end of 2022. And production from these projects will be phased in gradually starting in 2024.The Skarv FPSO is a modern production unit with high capacity located in a very prospective area. Therefore, we are now planning a new multi-well exploration campaign in this area next year. The goal is to prove up additional resources which can contribute to sustained high capacity utilization in Skarv FPSO into the next decade.When it comes to this year's exploration program, we have completed 2 wells in the second quarter. The Garantiana well -- the Garantiana West well came in as a discovery with volumes in line with the predrill estimate, which means that it will most likely be included in the Garantiana field development operated by Equinor.In the Barents Sea, the Shenzhou well was dry. And we're currently drilling Stangnestind, which is the final well in our exploration campaign in the Barents. We have 5 more exploration wells coming up in Q3 and Q4, including the Lille Prinsen appraisal well, which was recently spudded. And as indicated, we have started to firm up new targets for next year's exploration program, which we will present at the next year's capital market update as usual.This concludes the operational update, and I will, as usual, leave the floor to CFO, David Tønne, to provide his perspective on the financial events in the second quarter. David, the floor is yours.

[David Torvik Tønne, Chief Financial Officer]

Thank you, Karl, and good morning, everyone.The second quarter has been a quarter of high activity and strong performance, not only operationally, but also financially. Increasing realized prices, cost discipline and low cash taxes contributed to a high operational cash flow. With project execution and capital spend in line with our plans, this translated into a strong free cash flow and a further deleveraging of our balance sheet.In parallel, this quarter, we have taken several proactive steps to further strengthen our financial position by extending debt maturities and diversifying our sources of funding. In combination, this further improves our ability to continue delivering on all our 3 capital allocation priorities as a pure-play E&P company in a market environment with high volatility and uncertainty.Now if I zoom in on the second quarter results, our net production in the quarter was 199,000 barrels of oil equivalents per day. The reduction from Q1 was mainly driven by the planned maintenance activities that Karl has already covered. Then due to a small underlift, sold volumes ended at 195,000 barrels per day or 17.8 million barrels in total.The realized crude price ended at $68.7 per barrel, in line with the average Brent dated in the period. Adjusting for NGL, our average liquids price was $66.9 per barrel, up 11% from Q1. Including gas, the realized average hydrocarbon price was $63.4, up approximately 13%. And consequently, we report a total income of $1.124 billion for the second quarter.Given the high activity level across several assets in the quarter, I'm glad to see that we were able to maintain productivity and cost discipline. Production costs related to oil and gas sold in the quarter amounted to $158 million, down 10% from Q1. Cost per produced unit amounted to $9 per barrel. The increase from Q1 was driven by lower production, as the underlying cost of operations was actually down quarter-on-quarter by $6 million or roughly 5%. For the first half of 2021, the average production cost per barrel was $8.8, in line with the full year guidance of $8.5 to $9.If we take a look at the other main P&L items and subtract both production costs of $158 million and other operating expenses of $9 million from total income, we get an EBITDAX of $957 million. Exploration expenses amounted to $102 million, of which $62 million was field evaluation costs, with almost 2/3 being the NOAKA project. NOAKA is now in its final stages before concept selection, and once it has been formally passed this key milestone, costs related to the project will be mostly categorized as CapEx. We had $16 million in dry well costs in the quarter, mainly related to the Equinor-operated Shenzhou well in the Barents Sea.Depreciation was $240 million or $13.3 per barrel. The small increase in depreciation rate from Q1 is driven by a change in the mix of production from the various fields. Net financial expenses were $62 million and included $24 million in costs related to an early redemption of a $750 million bond. Furthermore, net currency gains in the quarter were $37 million, where $22 million was related to a newly issued euro bond of EUR 750 million. I will come back to both these transactions later in my presentation.Summing this, this gives us a profit before tax of $552 million, up 10% from the first quarter. Tax expenses amounted to $399 million, which means an effective tax rate for the quarter of approximately 72%. Net profit in the quarter then ended at $154 million or $0.43 per share, up 21% from Q1. With stronger prices, cost discipline, no cash taxes and a positive contribution from working capital changes, the growth in operating cash flow was even higher than the growth in net profit.Operating cash flow in the second quarter ended at $1.108 billion, up 23% from Q1. Then investments, including payments on lease debt, amounted to $511 million across the various spend categories, with CapEx being over 75%. Investments increased with roughly 50% quarter-on-quarter, in line with our spending plan for the full year.Free cash flow before financing was $597 million, an increase of 7% compared to Q1. As already mentioned, during the quarter, we redeemed our last callable bond and issued a new bond in euros with a lower coupon. Net cash flow from these activities amounted to $132 million. Dividends paid in the quarter was $112.5 million. And interest paid and other finance items was $33 million. We then ended the quarter with a cash balance of $975 million, an increase of $583 million from end of Q1.In addition to the fairly large change in cash on the balance sheet, there are 2 other things worth highlighting. On the left-hand side, property, plant and equipment increased by $238 million. We had additions of $457 million, where investments at Valhall and Hod made up roughly 45%; and the 4 assets, Alvheim, Skarv, Ula and Johan Sverdrup, made up roughly 50%, with between 10% and 15% of the investment each.On the right-hand side, other current liabilities increased with $245 million. A key driver for this is the higher license-related liabilities which is typically caused by accruals for project work that has not yet been invoiced. An increase like this is something that we typically see when we increase project activity and investment spend like we have done from the first to the second quarter, and this has a positive effect on working capital. We would then typically see the opposite effect if activity is reduced.Although there is only a minor change in bonds and bank debt on the balance sheet, the underlying changes are quite material as we, in the second quarter, have continued our journey of optimizing the capital structure. The specific activities executed can be summarized in 3 main elements. Firstly, as I noted in our first quarter presentation, in April, we amended and extended the maturity of our working capital facility from 2022 to 2024, with the option to further extend to 2026. In addition, we utilized the remaining option on the liquidity facility to extend the maturity from 2025 to 2026. Both facilities are currently undrawn with a commitment fee of 35% of the applicable margin. With a weighted margin of 1.1%, the commitment fee today that we pay is less than 0.4%. These debt facilities provide significant financial flexibility, supporting both our organic investment program and enable us to react quickly to potential inorganic opportunities that may arise.The second activity is that we, in May, issued an inaugural euro bond of EUR 750 million. This has now opened up a new source of capital for us providing additional funding optionalities for the years to come. The bond issue attracted high demand and was significantly oversubscribed. This allowed us to price inside our existing U.S. yield curve and at a record low coupon of 1.125%.The third activity is that we have redeemed our last outstanding callable U.S. high-yield bond. This $750 million bond was issued back in 2019 and was originally maturing in 2024 with a coupon of 4.75%. By amending our bank facilities, retiring all debt and issuing new longer-dated bonds in euros, we have added optionality through new sources of funding, reduced our financing costs and extended our debt maturity profile. Following these transactions, our average drawn debt maturity is over 7 years. Our first maturity is $500 million in 2025, and we only have $1 billion of debt in total maturing before 2029. The results of the very strong cash flow generation and the refinancing activities are that at the end of the second quarter, net interest-bearing debt, excluding IFRS 16 leasing, have been reduced from Q1 with roughly $500 million, down to $2.6 billion. Leverage has been reduced down to 0.85x EBITDAX, and our available liquidity remains industry-leading, ending the quarter at $4.4 billion. This unique financial flexibility puts us in a very good position to deliver on our capital allocation priorities of maintaining financial capacity while we invest in profitable growth, and continuously return value back to our shareholders across various oil price scenarios the next decade.I'm also happy to see that the strong operational performance, combined with a more constructive price realization, means that we are now again moving into a taxpaying position. For the fiscal year 2021, we have now fixed the first 3 tax installments payable in Q3 and Q4 at $100 million and $200 million, respectively. As you can see from this slide, the size of installments in the second half of 2021 corresponds roughly to the $65 scenario, indicated for payments in Q1 and Q2 of 2022. This indicates that the assumed average Brent price for the full year 2021 used at fixing the first 3 installments in the second half of 2021 is roughly $65 Brent, using an exchange rate of NOK 8.5. This also means that if we end up in the $70 scenario for the full year 2021 indicated on the slide, the first 3 installments are a bit too low and will result in a catch-up effect in the Q1 and Q2 next year.Now to round off my presentation, I will, as always, walk you through the key guiding parameters for 2021. In short, we keep all our guiding parameters unchanged from our capital markets update in February and as also reiterated at our Q1 presentation. Production in the second quarter was, as expected, lower than the guided full year average due to planned maintenance. The large planned maintenance program impacting production in 2021 is now behind us. Year-to-date production is 210,400, and we expect production for the full year to end somewhere between 210,000 and 220,000 barrels of oil equivalents per day. Capital spend year-to-date is roughly $1 billion, and our project activity is progressing as planned.Abandonment activity is mostly done for the year, but CapEx activity will still be ramping up with, for example, several production wells being drilled at Alvheim and Hod towards the end of the year. In addition, spending on NOAKA will be categorized as CapEx after the concept selection in late Q3. Production cost of $8.8 per barrel year-to-date is, as already mentioned, in line with plan, and we keep the guidance between $8.5 and $9.Lastly, our proposed dividend of $450 million for 2021 remains unchanged, and the Board of Directors has resolved to pay a quarterly dividend of $112.5 million later in July.I will now leave the word back to Karl for some concluding remarks before we move on to the Q&A session. Thank you.

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you, David. Thorough as always.So to conclude on the quarter, and may I first guide you a direction to the illustration on this page. This is an illustration by a technology project that Aker BP has been executing with BRI NorHull, a project called RoboCoat. And what you're seeing here is an illustration from a test executed in April. I can also share with you that we have recently executed a test offshore at Alvheim, where RoboCoat has been working on the Alvheim hull. So this is one of the illustration of our quite comprehensive digitalization and innovation agenda and is certainly a world's first.So where are we after the second quarter? Well, in my mind, I think that this report says everything. We have strong safety records, low emissions. The production and cost is on schedule. The ongoing projects are on track. We are maturing our project portfolio as we planned and as outlined in the capital market update, and we aim to sanction roughly 500 million barrels of oil equivalents by end 2022. We are well underway to deliver on NOAKA, and we have very strong support from our alliance partners in this area of high activity.As David has already walked you through, we have significant financial flexibility with a very high cash flow and extremely strong financial position, and we're continuing to return value to our shareholders, all according to our original plan.So all in all, I think we can conclude the first half of 2021 by saying that Aker BP is following the strategy and the plan we laid out and lately communicated to the market at the capital market update. We are continuing to build stone on stone to become the leading independent E&P company by progressing our projects, delivering on our production and executing in a superior fashion. We truly believe that this will create superior value to the shareholders of Aker BP.So with that, I conclude the Q1 presentation, and we will now open up for questions.

[Operator]

[Operator Instructions] We will take our first question from Sasikanth Chilukuru from Morgan Stanley.

[Sasikanth Chilukuru, Research Associate]

I had 2 questions, please. The first one was related to this production guidance, which you have kept unchanged at 210,000 to 220,000 barrels per day for 2021. With first half production already averaging 210,000, I was just wondering if it was possible to narrow down this full year guidance. Also related to this, it appears that there's not much material planned maintenance activity in third quarter. Is it possible to confirm that?The second question was related to the $1.1 billion of operating cash flow generated in 2Q. You've highlighted a positive working capital impact this quarter. I was just wondering if it was possible to quantify that and also isolate this positive benefit from accruals due to higher activity. Do you expect this benefit of accruals to reverse in the second half of this year?

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you. So starting with the first question, I can confirm that there are no significant maintenance activities left in our schedule for the remaining part of 2021. When it comes to narrowing of the schedule, the remaining part of 2021 is primarily driven by phase-in of new wells, and we have, therefore, kept the original guidance unchanged.When it comes to the working capital changes, David?

[David Torvik Tønne, Chief Financial Officer]

Yes. Well, I can take that. So the impact of working capital changes is roughly $200 million. And the isolated effect of the change in current liabilities is probably roughly around $150 million.So just to recap a bit the main drivers for working capital changes in Aker BP. So I think you can look at it from 2 different areas. One is when we increase investments, you typically also increase trade creditors and current liabilities which has a positive effect. And then if you realize higher prices, combined with liftings late in the quarter, then that could have a negative effect on working capital as you've lifted volumes but not received payments for them yet. In the second half of the year, we don't see investments reducing in accordance with our guided investment plan, so that gives an indication on the isolated effect of the current liabilities.

[Operator]

We will take our next question from Karl Fredrik from ABG.

[Karl Fredrik Schjøtt-Pedersen]

First question is regarding capital allocation and the current commodity price environment. Given the steep out that we've had also in gas prices, should we -- or has internal discussions regarding capital allocation changed?And the second question is regarding M&A, and as you say, you hold a fairly substantial capital buffer in order to be able to act quickly. And how has asset prices transact -- moved during 2021? And does this to you now mean like a way to go? Or is it organic growth, which is the path for at least the next couple of years?

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you, Karl Fredrik. So on your first question of capital allocation, whether or not that's changed as a result of the higher prices so far in 2021, I would like to remind you that a lot of our capital allocation and principles are spanning more than 1 quarter. And while we are, of course, thankful for the high oil prices so far in 2021, we make these decisions based on strategic assumptions and beliefs and not necessarily on how oil prices changes from quarter-to-quarter. So that in short means that we have made no changes to our capital allocation policy as a result of the current prices.Second, your question on M&A, I would say that, as I usually say, there hasn't been a day that have been employed in Aker BP where we haven't had an ongoing M&A discussion, and that stands -- that still is the case. That being said, we have also been extremely disciplined as to what kind of M&A projects we are, in fact, executing. And with the current price environment, there are -- will, of course, in our M&A opportunities, but they will have to be significantly better than our organic growth opportunities for us to execute on them. So I think that's what I will say on that subject.

[Operator]

We will take our next question from Teodor Nilsen from SB1 Markets.

[Teodor Sveen-Nilsen]

First one, a little bit follow-up on Karl Fredrik's questions on M&A. We know that at this call, you had commented on that you have looked into 2 projects in Brazil and you also have a small license in U.K. So are you now spending more time on M&A outside Norway than before? That's my first question.And second question is just very specifically on the Lyderhorn exploration well, pretty low predrill resource range. So can you comment on the commercial threshold for that well?

[Karl Johnny Hersvik, Chief Executive Officer]

So your first question regarding whether we're spending time on M&A outside Norway, let me be atypically clear. We're not spending time on M&A activity outside Norway.On Lyderhorn, this is -- these predrill estimates are notoriously hard to pin down as these are injectite reservoirs, so into the Heimdal sand, into the Heimdal shale. And as a result, the predrill estimates are one of the realizations of the current year model. That being said, we know that we can develop these kind of resources.Our Frosk now will be developed with a tieback to Bøyla using the Bøyla infrastructure. And Lyderhorn is a little bit further south but can probably utilize the same kind of infrastructure. So the predrill estimate is well within the economic thresholds.

[Operator]

We will take our next question from Yoann Charenton from Societe Generale.

[Yoann Charenton, Equity Analyst]

I have 3 questions, if you don't mind. The first one will be basically following the completion of this quite extensive optimization of the debt structure. I'm just wondering if that may lead to a change in your hedging policy. So we'll be happy to hear about this.Second question is on a tieback, which is King Lear. I understand it's clearly not a priority as we speak, but that would be great if you could touch upon that one, please given you spent some $250 million a few years ago acquiring interest in King Lear.And the last question will be in relation to the climate change question now that you recently signed with the CDP a few days ago. And it looks like you provided a bit more color on the target that you have set, which is -- which has to do with covering basically company-wide energy consumption from nonrenewable source, and you are looking at reducing basically your energy consumption. Can you touch a bit -- can you please touch upon this, please? That would be great.

[Karl Johnny Hersvik, Chief Executive Officer]

Yes. Sure. So I suggest, David, you start with the optimization of the debt structure, and I can do King Lear and the energy optimization and ESG topics.

[David Torvik Tønne, Chief Financial Officer]

So short answer to that, Yoann, is no, we have not changed the hedging policies due to the changes in debt structure.

[Karl Johnny Hersvik, Chief Executive Officer]

So moving on to King Lear. Yes, you're absolutely right, we did acquire King Lear and the operatorship from Equinor a couple of years back. The original idea was then to develop it back to Ula, inject the gas into Ula to utilize [ admissible ] lag following the heavy gas from the high-pressure of King Lear field. Since then, the Ula model has been updated, and the residual gas at Ula field turned out to be lower than we expected. So Ula is no longer a tieback candidate. So currently, we are assessing development opportunities for King Lear. And I think I'll stop by saying that we come back with the field development opportunity on King Lear some time in the second half of 2021.When it comes to reducing emissions, there's quite a lot of activities ongoing in the assets with the focus on reducing emissions. So roughly, there is about, memory serves me right, a little bit more than 20 projects with a total of possibility of around 40,000 tonnes of CO2 reduction or around 5% of our total emissions that are currently being assessed and evaluated. And if you remember back to our capital market update, we are addressing this by attacking our primary emissions that this emissions that are resulting in higher CO2 content physical and are spending most of our time and energy doing that. But we'll also, of course, reduce our CO2 intensity and also increase oil production, for example, from KEG and Frosk and other tie-in projects. We'll also reduce CO2 intensity. And I think the third element is that new field developments will almost exclusively be powered from shore with very low or minimal CO2 footprint. So those are the 3 key elements in our carbon reduction strategy.

[Operator]

We will take our next question from Chris Wheaton from Stifel.

[Christopher Courtenay Wheaton, Analyst]

Well done on another excellent quarter of operations and safety performance. And 2 questions if I -- 3 questions, if I may. Karl Johnny, first to you, you said at the very end of the presentation, you're looking to sanction 500 million barrels of resource by the end of 2022. If that includes NOAKA, that seems quite a low number to me. Could you help me understand, please, that 500 million, how that breaks down? Because I would have thought if NOAKA's in there, that number will be a bit higher.

[Karl Johnny Hersvik, Chief Executive Officer]

So if we go back to the projects that are -- was illustrated in this presentation, so they account for -- I would say, NOAKA probably accounts for 2/3 of the total volume, something in that kind of range. And this is similar to the volume we illustrated at the capital market update. That being said, we are, of course, working with the resource estimates to all of these projects, and we'll come back with an updated resource estimate as we are progressing and entering into the formal concept select on NOAKA as well.

[Christopher Courtenay Wheaton, Analyst]

That's great. And my other couple of questions were firstly, on cost control. You talk about normalizing operations after the period of coronavirus and the extra restrictions you had to put in place. Could you talk about the potential impact on costs from that? Because you've been quite clear you really want to use this opportunity to permanently change the way the business works. And so I'm interested in how you're thinking about making sure costs don't creep back in as we sort of go back to the new normal. And then a question for David on tax, please. If I look at note 8 in the report, it suggests that your tax payables for the rest of the year are down on where they were at 1Q, but you haven't paid any tax, and you're guiding to $300 million in the second half of the year, which seems different to the number that's in the balance sheet. Could you help me understand how all those numbers stick together, please?

[Karl Johnny Hersvik, Chief Executive Officer]

Excellent. Thanks, Chris. So first of all, thanks for the positive remark on operational performance. I, of course, do concur. When it comes to costs associated to COVID, there's about NOK 1 million a day that is directly associated to COVID measures. That will, of course, be reduced as we are removing these measures.When it comes to cost creeping back in, that is mostly related to activities. So we've done 2 major changes, which are now being implemented actually in July offshore. So the first one is to implement a new standardized operation model across our assets, which is -- has an effect of reducing manning by approximately 50 individuals or 10%. That is predominantly covered by in-sourcing of activities from foreign or external vendors, which is, as a result, increasing our wrench time, so to speak, on our existing resources, also, of course, positively impacting our secondary cost curve. And so when we are looking at our prognosis that now includes all the activity that we have so far postponed, we do, in fact, not see a significant increase either in activity or lowering cost as we're normalizing, which means that we have been able to quite positively impact the productivity curve across our assets even if we are increasing activity. So I would say I'm actually quite comfortable and rather proud of the operational team that has been able to both execute so well during these 15 months of COVID-19. But also we've been able to increase productivity quite significantly in the same period of time, which are now resulting in stable cost even if the scope of work is slightly increasing as we approach the end of 2021.And then on payable taxes, David?

[David Torvik Tønne, Chief Financial Officer]

Yes. Chris, I think we can also follow up a bit separately on your specific question in detail if you'd like a walk-through of it. But I think the short answer is that in the first half of the year, we have received a tax refund, and we expect to pay taxes of around $300 million in the second half of the year in cash taxes. And then there might be some confusion with regards to note 8 if it's a balanced items or the change in quarter-on-quarter. But we can follow up on that.

[Operator]

We will take our next question from Anders Holte from Kepler.

[Anders Torgrim Holte, Equity Research Analyst]

Thanks for a good quarter. Now I know that's been asked a few questions about this before. I'm going to try at it another way. And given the fact that you're closing up on $1 billion of cash sitting on your balance sheet and you moved out the maturity of all of your callable bonds, if I'm not mistaken, there are no callable bonds actually left in your structure. At what point in time does the cash position just become simply too large? And what will you then prefer to do with it? Are you looking at extraordinary -- a potential extraordinary dividend? Or is this more kind of where you look into the broader dividend structure of the company in terms of increasing the guided dividend policy going forward?

[David Torvik Tønne, Chief Financial Officer]

Thank you, Anders. Good question. So I think the short answer is with regards to capital allocation priorities, that has not changed. Also the dividend policy as part of that is not changed. We recognize, of course, that we have a very robust balance sheet, and we have accumulated cash on the balance sheet and then at the same time also reduced the RCF facility somewhat. So the liquidity position of the company remains the same quarter-on-quarter from Q1 to Q2. Reminding also that we're not paying taxes in the first half of 2021, which, of course, boosts the position.So I think what you should really infer from what we're doing on the balance sheet is that we're optimizing for the future. As Karl has walked through, we have a heavy investment program going forward, and we would like the company to maintain financial robustness and flexibility through various oil price scenarios. So I think that's the long and short answer to that question.

[Operator]

We will take our next question from Mark Wilson from Jefferies.

[Mark Wilson, Oil and Gas Equity Analyst]

My question is that this year, you accelerated a lot of inflow drilling and CapEx taking advantage of the temporary fiscal regime. I was just wondering if the profile of forward CapEx, now that we're 6 months through the year, for 2022 and beyond still looks roughly the same. You'd expect development CapEx to fall off some in 2022 before building, obviously, contingent on sanction of NOAKA. But certainly, relative to this year, would you still expect development CapEx next year to fully lower?

[David Torvik Tønne, Chief Financial Officer]

Yes. Thanks, Mark. So to give exact guidance on 2022 CapEx is a bit too premature. But I think our base case still stands that we laid out on the capital markets update with a somewhat smaller CapEx in 2022 compared to what we had in 2021. So I would use the guidance that we gave at the capital markets update for the CapEx profile.

[Operator]

We will take our next question from Al Stanton from RBC.

[Al Stanton, MD & Oil & Gas Equity Analyst]

Yes. Just a quick question. I hear what you say about being a pure-play E&P company, but I'm just wondering whether that could change if you were looking to hedge your electricity price exposure. Just what are you doing with respect to hedging electricity prices?

[Karl Johnny Hersvik, Chief Executive Officer]

Yes. So far, we've actually -- we have actually chosen to do a mix between spot and longer-term contracts on electricity prices, most of it consumed for Valhall, of course. And we're currently -- we are always surveilling this market and evaluating different ways of hedging that oil price -- no, that electricity price.Currently, this is a very liquid market, so it's not a big topic with us. It is more a matter of optimization than anything else. And then, of course, you are right, we are a pure-play oil and gas company. And if we do see that there are movement in electricity prices, both longer and shorter term, there are sufficient opportunities to hedge those should we choose that, that is an effective way to deploy capital.

[Al Stanton, MD & Oil & Gas Equity Analyst]

So it will always be financial, not asset-based hedging?

[Karl Johnny Hersvik, Chief Executive Officer]

It will always be financial hedging with the current strategy, yes.

[Operator]

[Operator Instructions] It appears there are no further questions at this time.

[Kjetil Bakken, Vice President of Investor Relations]

Operator, we have one question that we've received via e-mail which I can read. And then I guess, this is a question that David can answer. It's from James Hosie of Barclays. And he asks, on the KEG project, can you say what peak production rates are expected to be on that development? And he also had a question on the cash balance, which I guess, has already been answered.

[Karl Johnny Hersvik, Chief Executive Officer]

Yes. On KEG, that will depend on the back out as this is being produced through the Volund development. We are estimating a net impact in the range of 15,000 to 20,000 of barrel equivalents, where it might have a slightly higher impact on the first year. But again, that is dependent on the back out and which will be a function of the performance at the Volund reservoir at that current year. So as always, we are optimizing the utilization of the infrastructure at Alvheim, but those are the assumptions that went into the calculations where we made the decision on KEG.

[Kjetil Bakken, Vice President of Investor Relations]

Thank you. Operator, do we have any more questions on the line?

[Operator]

[Operator Instructions] It appears there are no further questions at this time.

[Kjetil Bakken, Vice President of Investor Relations]

Thank you, and I guess, from all of us here in Oslo, we wish you all a great summer. And as always, if you have any follow-up questions, please contact us in the IR team at Aker BP.

[Karl Johnny Hersvik, Chief Executive Officer]

Thank you.

[David Torvik Tønne, Chief Financial Officer]

Thank you. Have a good summer.