Earnings Transcript for AKRBP.OL - Q3 Fiscal Year 2021

Kjetil Bakken: Good morning and welcome to Aker BP's Third Quarter 2021 Conference Call. As always, today's speakers are CEO, Karl Hersvik, and CFO, David Tønne. And after their presentation, we will open up for questions. And with that, here is CEO, Karl Johnny Hersvik.

Karl Johnny Hersvik: Thank you, Kjetil. And good morning to all of you listening in. And I can promise you for the CMU or the fourth quarter presentation, there will be a physical meeting. I think we're all looking forward to that. So, let's get down to business. Q3 has been another eventful quarter behind us. The macro environment has definitely been on our side, with continued growth in oil price and with European gas prices reaching new record heights. Combined with continued stable operation, this leads to very strong financial results for the third quarter for Aker BP. And this is, of course, very good news. However, let me emphasize. This is not the time to be complacent. Our ambition is to be the leading company in our industry. And this requires full focus on the things that we can impact and improve. Safety, capital efficiency and emissions are key focus areas in this respect. As we are approaching the end of 2021, we continue to work relentlessly to progress our prioritized projects. During the quarter, we have passed several important milestones. The picture on this slide shows the new platform at Hod where the jacket and top sides were safely installed in July and August. And on the early phase side, we have, among other things, done the concept select for NOA Fulla and we have started on the FEED phase. I will refer to this later. And on the financial side, the strong operating cash flow this quarter has added further to our financial strength and balance sheet robustness. As a result, the board has decided to increase the annualized dividend level from $450 million to $600 million effective from the fourth quarter this year. I'm sure David would come back to this in his financial review. So, let us first zoom in on operational performance in the quarter. Q3 production ended at 210,000 barrels per day, up roughly 6% compared to the second quarter. The increase was driven by higher production efficiency, which was back to more normal levels in Q3 after Q2 where production was lower due to high maintenance activity. Looking into the crystal ball, we now expect to end up towards the lower end of the guided range of 210,000 to 220,000 barrels per day for the full year of 2021. The main deviations from our initial estimates are related to a temporary power outage at Ivar Aasen and lower production from the Ula area. The Ivar Aasen field is powered with electricity which is delivered from the Edvard Grieg platform. Unfortunately, this power solution has over time been less reliable than we would have liked. And this has had negative effect on the production efficiency at Ivar Aasen over time. On the 10th of September, Edvard Grieg was affected by a power outage which damaged the power transformer that serves Ivar Aasen. That transformer had to be shipped to shore for repairs. And despite production being negatively impacted while the transformer is being repaired and made ready for installation at Edvard Grieg, I'm pleased to see that the persistent efforts from the Ivar Aasen team and partners allow us to maintain a production level which is pretty impressive while the situation is being resolved. We expect the transformer to be re installed within a few weeks. In Johan Sverdrup, phase 2 comes onstream next year. Ivar Aasen will receive power from shore which will hopefully eliminate such issues in the future. In the Ula area, production has been below our expectations this year. And this is caused by a combination of factors, including lower productivity than expected from certain wells and less available gas for WAG injection than anticipated. These issues are also reflected in the impairment charge for Ula this quarter. Finally, on production, we are pleased to see Skarv making a strong comeback in the quarter following a major upgrade of the processing capacity where that was carried out in the second quarter to cater for the startup of Ærfugl phase 2 as well as other future tie backs. Now, let's turn to safety, environmental performance for the quarter. Safety is always our first priority. And we are working relentlessly to build and maintain a strong safety culture at Aker BP. The long-term safety trend has been moving in the right direction. In the third quarter, we recorded six minor injuries to our personnel. Consequently, our TRIF indicator went up to 1.5 this quarter. Even though none of these injuries were serious, our goal is always zero and we will follow up each incident systematically to learn and improve. Our CO2 emissions intensity stands at 4.4 kilo per barrel on average for the last 12 months and notched up from the previous quarter due to higher drilling activity this quarter, but still well within our range to be below 5 kilograms per barrel and still less than a third of the global industry average. As the cost of emitting CO2 are increasing and as access to capital is increasingly linked to the environmental performance of a company, this puts Aker BP in a very strong position. But also here, our ultimate goal is zero. And we continue to work systematically to lower our CO2 emissions, focusing on process improvements and energy optimization. So far this year, our operations team have identified a combined potential to cut emissions from our operated asset with roughly 25,000 tonnes of CO2 equivalents and realized CO2 emission reductions of approximately 10,000 tonnes. This demonstrates our ability to identify and implement measures to reduce our carbon footprint. And before we leave the topic of operational performance, let us zoom out and take a look at where we stand after the end of the third quarter. When it comes to our financial performance this quarter, I don't want to steal David's thunder, but there is three points that I'd like to highlight. Firstly, production cost was stable at $9 a barrel in Q3. For the first nine months, we are now at $8.9 a barrel; and for the full year, we expect to be in the higher end of the guidance range from $8.5 to $9, mirroring my comments on production. Second, operating cash flow in the first nine months has exceeded $3 billion, which is more than two times the capital spend in the same period. And thirdly on capital spend, as David will revert to, we are today reducing our full-year guidance by $100 million, which is driven by a combination of efficient project execution and phasing of activities. And that brings us to the next main topic of today – our projects. As you know, Aker BP has a large hopper of development projects. These projects represent the foundation for organic growth plans, and consequently, progressing and executing these projects according to plan is the top of our agenda. Since our last quarterly report, we have passed important milestones on several of our projects. On Ærfugl phase 3, it's now completed and production from the last two wells is expected to start in just a few days. This will enable us to increase our gas exports, which is very good news in the current market conditions. It will also contribute to higher capacity utilization and hence lower CO2 emissions per barrel at Skarv. During the quarter, we submitted the PDO for the Frosk to authorities. Together with Kobra East & Gekko, where we submitted a PDO in Q2, this project will contribute to increased production, lower unit cost, lower emissions and longer lifetime for the Alvheim area. And when it comes to our largest project, NOAKA we have completed concept studies and started on the fieldwork for the NOA Fulla area, leading up to the final investment decision in Q4 next year. I'll get back to this in a minute. We have also made a couple of changes to our project list at this time. At Valhall, we have been working on the new central platform, also called NCP, for some time. In parallel, we have been evaluating alternatives for the King Lear gas discovery and we have now selected a tieback to Valhall NCP as the best solution. This will contribute to make the NCP project more economically robust and, at the same time, unlock significant resources in the King Lear area. We are targeting concept select before year-end and a final investment decision by the end of 2022. And finally, we have decided to postpone the Garantiana development. This has been done to optimize the tie in the host platforms Snorre B and to provide some more time to explore for additional resources in the area. The new timeline includes an FID in 2026 and production start in 2029. At NOAKA, I'm pleased to announce that we have paused the DG2 milestone for the NOA Fula where Aker BP is an operator and we expect to do the same for Krafla within a few days. On this slide, we have now, on a preliminary basis, including the key financial metrics for the project. Compared to the previous estimates, the project has grown in size. The resource base has been upgraded to around 600 million barrels as we have optimized the design and placement of wells as well as updated reservoir models. Gross investments are expected to be approximately $10 billion and the breakeven price meets our hurdle of $20 per barrel. The concept is based on a flexible design which allows for efficient tie in of additional discoveries in the future. And while 600 million barrels leaves a very robust project, we see further upside potential in several of the surrounding structures. We have now mobilized our alliance partner across the value chain and have already placed FEED contracts of approximately $80 million. The regulatory process, including environmental impact assessments, have been initiated. And finally, we are on track to deliver PDO on this project by the end of 2022. The bottom line, NOAKA is a project that will deliver substantial value to Aker BP and the other partners. It will create significant positive ripple effects for the industry, as well as for the Norwegian society at large. And with power from shore, it will also contribute to further improving the environmental footprint of the Norwegian oil and gas. And before I leave the floor to David, let me briefly comment on exploration in this quarter. Q3 was our most active quarter this year on the exploration side. The Stangnestind well was completed early in the quarter and came in as a minor gas discovery, which is not considered to be commercial. This actually marks the end of our exploration campaign in the Barents Sea, and we have currently no plans for further activity in the area. The Liatårnet did not give us the clear answers we've hoped for and the volume estimate for the discovery is expected to go down, although it's too early to disregard Liatårnet completely. At Lille Prinsen, the exploration and appraisal programs were successful and confirm the resource range in the range of 12 million to 16 million barrels. The operator Lundin is now maturing the development plan with Ivar Aasen as one of the potential host platforms and are aiming for an investment decision in 2022. And on the last two wells, Gomez came in as an oil discovery, but with its related to the mobility of the oil, so it's a bit early to conclude, while the Merckx Ty was dry. We have two more exploration wells coming up in Q4, including the Mugnetind which is currently drilling. And this concludes the operational update and I leave the floor to our CFO, David Tønne.

David Tønne : Thank you, Karl. And good morning to all of you. It is a pleasure to present another quarter with record high revenues and strong financial results. Aker BP's revenues increased by almost 40% from the second quarter and is up nearly 130% from the third quarter of 2020. Net production in the quarter was 210,000 barrels per day and the increase from Q2 was mainly driven by the planned maintenance activities that we had in the second quarter. Q2 In the third quarter, we also over lifted and sold volumes ended at 225,000 barrels per day or 20.7 million barrels in total. The realized crude price was $72.7 per barrel. And adjusting for NGL, our average liquids price was $71.5 per barrel, up 7% from Q2. Including gas, where prices increased by over 100%, the realized average hydrocarbon price was $75.2 per barrel of oil equivalents, up approximately 19%. Consequently, we report a record high total income of $1.563 billion for the third quarter. And although it benefits us as producers in the short term, the rapid increase in European gas prices should give us all some concern. To me, it illustrates the gentle balance between supply and demand in the energy markets and the need to ensure that we also invest in low cost, low carbon oil and gas assets at a sufficiently high level in the years to come. Now moving on to the development in cost. Production cost per barrel produced were stable at $9 quarter-on-quarter. Underlying addressable costs were slightly down while we experienced an increase in costs related to power on Valhall and tariffs and environmental taxes on Skarv as production increased after the maintenance slowdown this summer. Production costs related to oil and gas sold amounted to $209 million. The increase from Q2 is mainly driven by the mentioned overlift. And as these barrels also carry an element of depreciation, this gives them accounting-wise a relative high cost per barrel. For the first nine months, the average production cost per barrel produced were $8.9, n line with the full-year guidance of $8.5 to $9. We now expect production cost per barrel to end towards the higher end of our guided range for the full year. Absolute costs are pretty much in line with plan, but as production is expected in the lower end of the guided range, production cost per barrel converges to the high end. Taking a look at the other main P&L items and subtract both production cost of $209 million and other operating expenses of $7 million from total income, we get an EBITDAX of $1.347 billion. Exploration expenses amounted to $97 million, of which $43 million was field evaluation cost, with almost 60% related to the NOAKA project. As the project is now formally passing concept select and DG2, costs related to the project will be categorized as CapEx going forward. We have $38 million in dry well costs in the quarter, mainly related to the Stangnestind well. Depreciation was $247 million or $12.8 per barrel. This is slightly down from Q2 and is driven by the change in mix of production from the various fields. In the third quarter, we recorded an impairment of net $154 million. And the main reasons is the revisions of future costs and production profiles for the Ula area. Net financial expenses were $47 million and included net losses and reduction in fair value of currency derivatives of approximately $22 million. These losses were offset by $30 million in net currency gains in the quarter, where $21 million was related to our $750 million euro bond. Interest expenses decreased $7 million quarter-on-quarter, which is the result of our continuous efforts to drive down funding costs by replacing old bonds carrying higher coupons with new bonds with lower interest rates. In sum, this gives a profit before tax of $802 million, up 45% from the second quarter. Tax expenses amounted to $596 million, which means an effective tax rate for the quarter of approximately 74%. Net profits in the third quarter then ended at $206 million or $0.57 per share, up 34% from the second quarter. Moving on to cash flow. Operating cash flow in the third quarter ended at $1.063 billion. This is slightly down from the second quarter as it includes a negative effect of working capital changes of roughly $1 50 million, mainly due to increased receivables related to oil and gas sales late in the quarter. In addition, after receiving tax refunds in the first half of 2021, we in the third quarter again started paying taxes with one installment of $94 million. Investments, including payments on lease debt, amounted to $453 million, with CapEx being over 80%. This is slightly down from $511 million in the second quarter. Thus, free cash flow before financing ended at $610 million, slightly up from Q2, and free cash flow generated for the first nine months of the year stands at almost $1.8 billion or $4.9 per share. Dividends paid in the quarter was $112.5 million and interest paid and other finance items were $51 million. We then ended the quarter with a cash balance of $1.421 billion, an increase of $447 million from the end of Q2. It is, however, worth noting that with the current oil and gas prices, we are currently paying too little cash taxes as the installments for the second half of the year were set in June. This has a positive impact on cash balances now in Q3 and Q4, but it will be balanced with higher tax payments in the first half of next year. And I will come back to tax shortly. In addition to the increase in cash and cash equivalents, there is a few other things worth highlighting in the balance sheet. On the left hand side, other intangible assets decreased by $94 million. The decrease is mainly related to reclassification of the NOA Fulla part of the NOAKA project from exploration to asset under construction. This is a direct consequence of the project formally passing concept selection and DG2 during the quarter, as already mentioned. Receivables and other assets increased by $129 million. The increase is mainly due to larger receivables related to oil and gas sales, as mentioned when I talked about our working capital changes. On the right hand side, the main changes are related to an increase in deferred tax and tax payables. But in addition, it's also worth noting that other provisions for liabilities, including P&A, has decreased with $41 million. The decrease is related to asset retirement obligations where we've had a downward revision of the estimates. This is mainly driven by discounting effects after the approval of the lifetime extension of the Alvheim area, which was triggered by the PDO submission of the Kobra East & Gekko project. The number one capital allocation priority for Aker BP is to maintain a strong financial capacity and, with it, a high financial flexibility. This is the foundation for our ability to invest in profitable growth and distributing value back to our stakeholders. Over the years, we have worked to optimize the capital structure, and in 2021, we have continued the journey. With the strong cash flow generation in the third quarter, we have further fortified our unique financial position with a balance sheet that's never been more robust. Net debt excluding leases now stand below $2.2 billion and our leverage ratio is below 0.6 times EBITDAX. Liquidity is high, with the combination of an undrawn credit facility of $3.4 billion and $1.4 billion in cash. And currently, we have no debt maturities before 2025. The third element in our capital allocation framework is how we think about returning value creation. In February, we presented our updated dividend policy developed together with our board of directors. The policy's purpose is to support our goal of maximizing long-term value creation. And a key principle is that dividends shall reflect the distribution capacity through the cycle, considering the long-term financial outlook and the credit profile of the company. In line with this policy, and based on a holistic assessment of our financial capacity and future investment plans, the board of directors has decided to increase the annualized dividend level from $450 million to $600 million, starting with the payment in the fourth quarter this year. This means that the total dividend paid in 2021 will increase from $450 million to $487.5 million. Furthermore, this implies a planned dividend of $600 million to be paid in four quarterly installments in 2022. In addition to distributing value back to our shareholders, we are also glad to distribute value back to the society. We do this in many ways, but perhaps the most important is through tax payments. In September, then sitting, now former government, of Norway presented a proposal for an adjusted tax system for the oil and gas industry. This proposal is now on hearing and is expected to go through Parliament during the first half of 2022. The proposal appears to have broad political support, also from the new government. At Aker BP, we support the main principles behind the proposal and welcome the effort to provide transparency and longer term stability around the fiscal framework post the temporary tax system. Stability in the fiscal framework has always been the key strength of the Norwegian continental shelf, and it's especially important now when investing in an industry in transition in a volatile macro environment. Now, if I zoom in on the next three quarters, there is a few things to note. At the end of the second quarter, we fixed the tax instalments to be paid in Q3 and Q4 based on an assumed oil and gas price of roughly $65 per barrel for the full year. We paid $94 million in Q3 and expect to pay twice that in the fourth quarter. However, as oil prices and, in particular, gas prices have rallied significantly higher since the end of Q2, the tax instalments paid in Q3 and Q4 are too low compared to the financial results generated for the full fiscal year 2021. We, therefore, adjust the forecasted payments due in Q1 and Q2 of 2022 accordingly. To round off my presentation, I would like to provide an update on our key guiding parameters for 2021. We have already covered production and production cost per barrel thoroughly in today's presentation. On production, we now expect to end in the lower end of the range, in particular due to the lower-than-expected production on Ula and the issues with power supply from Edvard Grieg impacting Ivar Aasen production in the second half of the year. As we keep our absolute production costs in line with the original plan, the direct consequence from forecasting production in the lower end of the range is that we expect to end in the higher end of the range on production cost per barrel. Total capital spend across the three categories is roughly $1.5 billion year-to-date. Of this, CapEx is $985 million. The original guidance for CapEx for the full year was $1.6 billion. All projects are progressing according to plan. But due to strong performance, in particular, on the drilling side and phase of spend, we reduced our guidance for the full year to $1.5 billion. With abandonment and exploration spend in line with the original plan, the total capital spend guidance is therefore adjusted down $100 million to $2.1 billion to $2.2 billion. And lastly, as mentioned, the board of directors has resolved to increase the annualized dividend level from $450 million to $600 million effective from Q4 this year. This means that the Board of Directors also has resolved to pay a quarterly dividend of $150 million in November, bringing the total dividends paid in 2021 to $487.5 million. That concludes the third quarter financial review. And I will leave the word back to Karl for some concluding remarks before the Q&A session starts. Thank you.

Karl Johnny Hersvik : Thank you, David. And I can assure you he was actually smiling the whole time. Today's presentation has been structured around three main dimensions. The first one is the operational side of our business, and this is where we convert values in the ground into money in the bank. And our key priorities here are pretty simple. We want to maximize production efficiency, which basically means to maximize value creation from our assets, with high safety performance, low cost and low emissions. Done properly, this will be a huge source of capital for Aker BP. The second dimension is our organic growth agenda. We have a unique resource hopper that we want to develop and produce. And our goal is to sanction projects with around 600 million barrels of resources before the end of next year. This, of course, is no small challenge. And it will once again put our project execution capabilities to the test. Including alliances with key suppliers, we have developed a strong execution capability over the last five years. And obviously, this plan also means that we are going to invest a lot of capital in the years to come. Which brings me to the third and final point. We are now in a historically strong financial position with high liquidity, low leverage and strong cash flow from our producing assets. This does not only put us in a favorable position towards finding our growth ambitions, but it also leaves headroom for increasing the dividend levels as we have announced today. And with that, I would like to thank you all for your attention and will now open for questions. Operator?

Operator: . Speakers, we have our first question. It's from Mr. Anders Holte of Kepler Cheuvreux.

Anders Holte: Congrats on a strong quarter. Of course, a very strong position of the balance sheet. Now I think you probably know what I'm going to ask, and that is – I'm not going to press you about dividend increases, but I am going to try to see if we get something out of you on what we should expect Aker BP to hold in terms of cash on its balance sheets going forwards. Because you mentioned, David, you are now in a historically strong position balance sheet wise. I'm just wondering where should we keep the cash position of Aker BP for the foreseeable future?

David Tønne: I think it's a fair question to be asking. We're in bit of a unique situation now with the increase in oil and gas prices, meaning that we're also paying too little cash taxes in the second half of this year, which is obviously then bringing the cash balance a bit unnaturally high in the third and the fourth quarter of this year. Going forward, we will, of course, work to optimize the cash at hand. But keep in mind also that we are investing heavily going forward in our project portfolio, which means that we would probably have more cash on the balance sheet now than what we've had in the past.

Operator: . We have our next question from Teodor Nilsen from SB1.

Teodor Sveen-Nilsen: Congrats on strong results. Two question from me, if I may. Karl, you mentioned that you probably drilled your last well in the Barents Sea, which I definitely understand. But I just wonder what has actually gone wrong in advance here? And do you think that the industry now will leave the Barents Sea for good? Second question is on the value chain. Of course, we hear from other industries that there is substantial bottlenecks in certain parts of the value chain. What do you see are the bottlenecks now and has anything of the supply chain challenges impacted you and do you think that will impact you over the next few quarters and years?

Karl Johnny Hersvik: Excellent questions, as always. So, when it comes to the Barents Sea, yeah, what's actually gone wrong? That's a pretty long question. I think, in reality, we have proven that there are two or three play models that actually work. And subsequently, there are – I think we've tested seven, maybe eight, that does not work. So, the western margin, of course, we are in Castberg, in Goliat and all of this, that works. And then the northern parts with Wisting, et cetera, also works. The eastern parts have proven very unreliable and the Tertiary is pretty dense and with low expected, call it, productivity. That does not necessarily mean that it would never be produced. But it certainly means that there is a lot of infrastructure that needs to be invested prior to such production. Will the industry leave the Barents Sea? I don't think so. If you're positioned in the western margin or in the norther parts of the Barents Sea, you're likely to keep that position and execute on that exploration model. The industry is likely to keep innovating to try to discover new exploration models and test those as time goes by. But from an Aker BP perspective, even though we're trying to learn from the 20-odd wells we've drilled or participated in the Barents Sea, we have no plans to continue drilling in the Barents Sea. Second, on your question on the bottlenecks, I think that's also a bit of a sophisticated question. So, probably two types of – or maybe three types of bottlenecks. So, the first one is basically deliverability. And I don't think we've ended up in a situation anywhere. Neither Aker BP nor the industry where things can't be delivered. But it's obvious that the industry is now catering for that event by booking production slots, et cetera, to ensure that they have a deliverability on the line of sight in their projects. Second is about prices, which I'm sure you have noticed, as many others, have gone up driven by underlying fundamentals, such as steel prices and other material prices, but also by the rather large increase in investment, particularly in North Sea, but also in Brazil and Gulf of Mexico. So, Aker BP is, of course, exposed to these underlying price changes as everybody else. But the alliance mechanisms allows us to counter that to a certain degree. And then, the third one, which is the quality of the products to be delivered, as consumption is going up and production capacity needs to raise, it's quite common that the quality is also challenged. And this is where the execution model that Aker BP has been developed for a lot of years, since 2016. It's really coming into play. So we feel like we're getting brownfield . We are getting priority with our vendors. We've been working with these guys since 2016. We know them well. We know that they are delivering equipment and services from well-established value chains. So, I don't see that much of a challenge in that third category. But it is something that we are, of course, keenly aware of and working to mitigate every day.

Teodor Sveen-Nilsen: Just a quick follow-up on the number two you mentioned, prices. I'm just curious about the high electricity prices we now see in Norway. Will that impact your fourth quarter OpEx? David, you mentioned some power cost at Valhall during the third quarter.

David Tønne: Yeah, but to a minor degree. Because, remember, a lot of what we're now consuming was acquired six to nine months ago. And prices locked in at that point in time. When it comes to power prices, these are basically following the spot prices in Norway. And a way of thinking about this is to follow the spot prices and then use, let's say, around 100 megawatt as continued capacity on Valhall. That should give you a rough idea of the effect on OpEx. It's not significant.

Operator: Our next question comes from Karl Pedersen at ABG.

Karl Fredrik Schjøtt-Pedersen: With regards to the revised CapEx guidance, you said, David, that it's a function of a combination of more effective drilling, but also, to some extent, timing. And I expect that the timing will be then – CapEx is pushed into 2022. So, how much of the $100 million in reduction can be ascribed to timing and how much is actual cost savings?

David Tønne: I think the short answer to that is roughly 50/50. So, we've had strong drilling performance on several of the wells that we've been drilling, in particular on Ula and also some on the Alvheim area, which has brought costs down and then there are some phasing of cost into 2022. We've seen some, for example, on the Johan Sverdrup phase 2 project, which is phasing and not progress on the project, per se.

Karl Fredrik Schjøtt-Pedersen: The resource increase on NOAKA, can you elaborate a bit more on what has driven that increase and is there more potential especially in your part of the NOAKA area?

Karl Johnny Hersvik: To answer that question, when we're doing the feasibility phase, we're usually just using the assessment that was made as a result of the exploration phase. And when we're then progressing to DG2, we actually work all this data bottom up once again. We get consistent models, the same type of modeling across consistent seismic processing, et cetera, et cetera. So, the first part of the increase is actually that we work the models up again in a consistent manner. And that has resulted in larger volumes across several of these fields. Second, as we're progressing into DG2, we're also optimizing drainage strategy and well placement, which has also added volumes to this mix. And thirdly, we have identified significant upsides, which have also meant that we are now investing in roughly double the well slots that is needed to drill out 600 million barrels. And while it may be too early to indicate what such upside potential would be, I think you understand that we would not have invested in this amount of well slots if we did not believe in further upside in the resource.

Karl Fredrik Schjøtt-Pedersen: And any indications on how that upside will play out in terms of timing?

Karl Johnny Hersvik: So, that upside will probably be played out as we get towards the DG2. It will indicate so-called IOR potential in the fields in the PDO. And then, of course, this will be drilled out once we start production whenever that may be, let's say, in 2026, 2027. It will of course come after that original drilling program that is now planned.

Operator: Our next question comes from Chris Wheaton at Stifel.

Chris Wheaton: Thank you very much indeed for the third quarter results showing what happens when you run an oil company properly. So, very well done to you and your team, I think. Two questions from me, if I may, please. Firstly, on CapEx. Despite the slight reduction in full-year CapEx, it looks like there's a reasonable step up in CapEx in 4Q versus the rest of the year. And I'm interested in, is that a precursor to 2022 running at slightly higher levels of CapEx than you indicated at your CMD back at the beginning of this year? Secondly, on tax. David, could you help me understand, on slide 22, how much of that first half 2022 tax payment is actually related to catch up payments for 2021? What I'm trying to do is understand what the sort of normalized level of tax payments ought to be. So, therefore, actually get your underlying free cash flow number and better calculate it, please.

David Tønne: When it comes to CapEx, you're correct, we are expecting an increase in the fourth quarter, partly driven by the fact that NOAKA will now be categorized as CapEx going forward. In addition, we are also expecting long lead items to some of the projects that we have PDO-ed during the last couple of months, including the Kobra East & Gekko project. When it comes to CapEx guidance for next year, I don't want to be too precise on that because I want to save something for our Capital Markets Update in February. But we are still expecting CapEx to go down year-on-year compared to our 2021 updated guidance. When it comes to tax and the guidance on tax per quarters, I think the easiest way to look at it is that if we knew the outcome at the start when we set the installments, you will have equal payments in each of the quarters. So, that gives you an indication of how much of the increase in Q1 and Q2, which then should have been paid already in Q3 and Q4 of this year. Some of my tax specialists would probably have thrown out the numbers similar to maybe $300 million, but I think it's best for you to calculate that yourself.

Chris Wheaton: I'll see how close to $300 million I can get myself.

Operator: Our next question comes from James Carmichael at Berenberg.

James Carmichael: Just a couple of quick ones. Just on the strong overlift position in Q3. I'm just wondering how quickly – or whether we should expect that to sort of unwind during Q4. Again, just on tax, I guess if we add up all those quarters, we can come to an annual cash tax number for 2021. If oil prices stay at $75 through 2022, is there any reason that the 2022 numbers should be materially different from 2021?

David Tønne: On overlift, in general, I think we shouldn't expect to either overlift or underlift over time. So, I do expect that to perhaps level out over time. And then, when it comes to cash taxes for the fiscal year 2022, that's something that we will provide an update on at the Capital Markets Update together with an update on, of course, production and investment level and so forth. So, we provide now the guidance based on the payments for the fiscal year 2021.

Operator: Our next question comes from Al Stanton at RBC.

Al Stanton: Can I ask two questions, please. First of all, starting with exploration. The budget for this year is $400 to $500 million. Can you take out the NOAKA spend from that and tell us what the figure is? And then, is that the starting point for next year's budget? Or do you think the results of this year's exploration campaign justify lower spend going forward?

David Tønne: Give me a second on the NOAKA spend. If my memory serves me correct, I think we're talking well costs in terms of expenditure of roughly $300 million. But maybe I'll have to revert back on a more precise number on that. And then when it comes to exploration spend for next year, I think, again, we will guide on spend for that at our Capital Markets Update in February. But I think the best estimate would be to use what we've provided in terms of guidance at the capital markets in February.

Karl Johnny Hersvik: On the 2021 program, a lot of the wells that are now being drilled in 2021 program is remaining commitment wells, amongst other wells in the Barents Sea, which of course has not necessarily led to 2021 being a normalized exploration year. We'll release the 2022 program at the Capital Markets Day. As a little bit of a pre-warning, it looks a lot better.

Al Stanton: Are there many outstanding commitment wise?

Karl Johnny Hersvik: At the moment, I think we have two. But both of those two commitment wells are wells that I used to say that we actually want to drill. So you may not consider them commitment wells.

Al Stanton: My second question was about NOAKA. You did the interest for the three areas. I was wondering if you can give the distribution of the resources across the three areas. Or better still, just tell us what your stake is?

Karl Johnny Hersvik: I think we'll revert to that a bit later, Al. We are still in the process of doing the DG2 at the which I think Equinor as an operator will issue in a few weeks, and subsequent to that, which will probably lead us back to the CMU. We can give you a more detailed breakdown of the distribution of results.

Al Stanton: Just to follow-up on your question, I just checked my numbers. I want to be precise. I think field evaluation expenditure in total in plan is roughly under the $50 million to $200 million out of the total exploration spend. I think you can use roughly $150 million on NOAKA.

Operator: Our next question comes from Michael Alsford of Citi.

Michael Alsford: I've got a couple. Just a follow-up on NOAKA actually. Clearly, a fantastic project. Could you just confirm whether there are any plans going forward to farm down your equity interest before project sanction, would be my first question. Secondly, a broader industry question. I guess you saw that Vår Energi is looking to initiate a strategic review process. I just wondered whether you could maybe elaborate on whether you have the appetite to seek broader industrial combinations on the NCS, so whether it be more smaller deals within your portfolio?

Karl Johnny Hersvik: When it comes to farm down, we're, of course, not commenting on commercial processes. But I think I'll go as far as to say that we really like this project and we like our position in it. And we like the resources and we like the upside. So, I think you can from that love statement probably extract that there was no plans for farm down at the present time. When it comes to Vår Energi, we wish them all the best and hope they're successful in whatever avenue of commercialization that they may pursue. We're always looking for interesting combination that are value creative to Aker BP's shareholders. But apart from that, I'm not going to comment on business development processes.

Operator: Next question comes from Anders Holte of Kepler Cheuvreux.

Anders Holte: Just a quick follow-up for me to David on page 22 in your presentation slide deck. Just what natural gas price do you use behind those sensitivities?

David Tønne: That's also a good question. So when we've typically made these, they've been a fixed price, which has been linked to the oil price. But, of course, given the significant increase in gas prices, that assumption has not really been valid anymore. So, for the updated figures that you see here, we are between $15 and $20 per MMBtu, which of course is a bit too low when comparing against what you see in the market currently. So, if assuming that the current price that you can look outside the window continues for the rest of the fourth quarter, I think you need to take the average Brent a bit higher for the full year compared to what you would see if you're only looking at the Brent price. So, my best guesstimate would then be that you would probably end around the $75 mark, so you can increase it a bit based – on the gas price, it's a bit too low in the assumption here compared to the Brent price.

Operator: Our next question comes from Yoann Charenton of Société Générale.

Yoann Charenton: Apologies if these questions have already been raised. I'm just willing to understand if you can provide a bit more color on this NOAKA resource upgrade at this stage to say, basically, what are the drivers behind the resource upgrades and what are the subsections of the area that accounts for the highest share of these upgrades? Then I've got a second question, which is about the transition to the new tax regime. So, assuming the proposal that was made in September is approved by parliament, is it possible to understand if this could trigger a liquidity boost in 2022? And I'm already thinking about the transition, which is supposed to pay out the uplift and CapEx that has not been offset against a tax payment? And, of course, this is what comes outside of the temporary tax scheme. And maybe last question will be more generic. And just to understand if you have seen some change in terms of interest or asset swaps in this higher oil and gas price environment?

Karl Johnny Hersvik: On NOAKA, I think this is more the way the process works, right? So, when you go into feasibility, you usually have a little bit of a more coarse understanding of the reservoir. More generic, simplified models, et cetera. And then, as you're progressing towards Dhrupad, we mature the rest of our models, we rework the data foundation, new geological model, new seismic interpretations, et cetera, et cetera, to make sure they're all consistent. In addition to that, we also plan the drainage strategy for each of these reservoirs and optimize the connection between the reservoirs. And thirdly, we plan and engineer the wells and the well placement. And in doing so, we have increased the resource estimate from roughly 500 to roughly 600. And as I also said previously in this Q&A session, identified significant upside which has also led us to invest in roughly double the number of well slots that are needed to develop the original 600 reserves. And then, as we progress to project, and probably back in the Capital Markets Day, we'll provide a bit more, let's say, a breakdown of the technical details on this restaurant. There are some interesting traits. On, let's say, the change in – we can do the tax later. On the asset swaps, I would say that, in general, there is quite a lot of, let's say, BD type of activity ongoing at the moment, not only driven by the high oil and gas prices, but also driven by the structural changes in the energy transition and how that has changed the players' appetite for investing in oil and gas, whether that's directly linked to asset swaps or other. Also, other types of business development? Well, that's probably a question more of payment mechanism than anything else. But I haven't seen a singular activity in terms of asset swaps if we were thinking about swapping gas assets versus oil assets. But of course, there's some sort of optimization on drainage strategies in most of these reservoirs at the moment. And then, David, when it comes to tax, I'll leave that on to you even if I do think I know the answer.

David Tønne: Short answer is that we do not expect a liquidity boost in 2022, assuming that the proposal is approved as is. And the main reason for that is that the way that we understand the proposal is that it's tax losses carried forward that are being paid out and not the tax balances per se. But I'm happy to follow up with you separately on more details around this, if you would like.

Operator: Thank you very much. Students. Speakers, we have no further questions at this time. Please go ahead.

Karl Johnny Hersvik: Okay, that's good. I hope that everybody is happy with the answers that we have provided. And if they're not, the IR department is, of course, as always available for follow-up. So with that, I think we close the call and wish you all a great day.