Orrön Energy AB (publ) (ORRON) Earnings Call Transcript & Summary

Hello, and welcome to the Lundin Energy AB Q2 Report 2021 Call. [Operator Instructions] Today, I am pleased to present Edward Westropp, Vice President, Investor Relations. Please go ahead with your meeting.

Thanks very much, Keith. Welcome, everyone. Thank you for joining the call. So this is the 2Q results call for Lundin Energy. Thanks for joining. We're going to follow the normal course of events. Nick Walker, the CEO, will take you through the operations and highlights, and then Teitur Poulsen will take you through the financials. We'll then have a Q&A at the end, first of all from the conference call line, and then we'll be taking questions from the web afterwards. So, I'll hand over to Nick who will kick the meeting off.

Good. Well thanks, Ed, and good afternoon or good morning if you're joining us from North America, and welcome to our second quarter 2021 results discussion. I'll cover off the operations update and then Teitur will talk us through the Q2 financials. And as usual, as Ed says, we'll open up for questions. First of all, the key highlights. We delivered record production and financial results in the second quarter as backed by strong operating performance and further strengthening of oil prices. You can see Q2 production was 190,000 BOEs per day. And as we've previously announced, we increased our guidance in the second quarter for the year. You can see that Phase 2 of Johan Sverdrup is on schedule, and we've just completed some key installations on schedule offshore. And you'll see later that the project is bang on schedule. We also announced an increase in June to the full field capacity, when the Phase 2 comes online, up to 750,000 barrels of oil per day gross. And on top of that, all of our key projects are on track, providing growth to over 200,000 BOEs per day by 2023. Our resilient cash generative business delivered record financial results. You can see operating costs for the quarter were $2.8 per BOE, which is better than guidance. We delivered also record free cash flow of $949 million for the first 6 months. That's almost 2x our annual dividends, but in only half the year, resulting in deleveraging of the business with net debt reduced to below $3.2 billion at the end of the period. And if we look forward and assume a $70 per barrel oil price for the rest of the year, we estimate that annual free cash flow is set to be around $1.5 billion, and at year end, our net debt will reduce to below $3 billion. I think as many of you know, we also completed a very successful $2 billion inaugural investment-grade bond issuance during the quarter, raising long-term money on very attractive rates, with the proceeds used to pay down existing corporate credit facilities. And we continued to make good progress on decarbonizing our operations with everything in place to achieve carbon neutrality from 2025. Already, around 60% of our production is independently certified as carbon neutrally produced. We've already made several certified carbon neutrally produced crude sales, which I believe will become a key differentiator for the company. And we're also on track with our renewable projects. So in summary, we delivered record results in the first half of the year, and all of our key business priorities are on track. I will now step through the details supporting this. Firstly, looking at production, our world-class assets continue to outperform, delivering production in Q2 of 190,000 BOEs per day, which is above the top of the guidance range. That's now 24 quarters running that we've met or exceeded guidance. And this performance is driven by I think 3 things. First of all, excellent production efficiency across all of our assets. Second, an earlier ramp-up of Johan Sverdrup Phase 1 to the new increased plateau levels. And third, additional facilities capacity at Edvard Grieg due to declines at Eva Olson. And looking forward, we expect production around the current levels for the rest of the year. And this strong performance caused us in June to increase the full year production guidance range to between 180,000 to 195,000 BOEs per day, as you can see from the original guidance range of 170,000 to 190,000 barrels of oil equivalent per day. This delivery is backed by continued top tier operating performance, which you can see shown here, with excellent production efficiency metrics of 95% to 98% across all assets. Operating costs were $2.82 per barrel, which was better than guidance, and these are industry-leading levels. And also really good performance on carbon emissions. 2.9 kilograms of CO2 per BOE. And putting this in context, that's about 1/6th of the world average. And on top of that, we delivered safe operations in the quarter. Turning now to our decarbonization plan. We're making good progress on our plans with everything in place to achieve carbon neutrality from 2025, which is a first for the upstream industry. To recap, the plan is supported by real action around 3 key pillars. Firstly, reducing emissions with electrification of our assets or with power from shore. Secondly, replacing and offsetting our power usage with investments in renewables. And thirdly, what we can't reduce, commitment to nature-based carbon capture to neutralize the balance, which means that from 2025, every barrel delivered by Lundin Energy will be carbon neutrally produced. As a result of the performance of the Johan Sverdrup electrification in reducing emissions, we've reduced further the emissions intensity target for the company. So from 2023 onwards, it's going to be around 1 kilogram of CO2 per BOE. And now that's 1/20th of world average, which means we've less emissions to neutralize with our natural carbon capture projects. On the back of announcing the world's first certified carbon neutrally produced crude oil sale from Edvard Grieg in April, we've now had the Johan Sverdrup field emissions certified as low carbon and have committed to neutralize all future residual emissions from the field with high quality, certified natural carbon capture projects. What this means is that all future Johan Sverdrup barrels are being sold as certified carbon and neutrally produced, which represents about 60% of the barrels that we sell today. We've seen lots of interest and have already made several certified carbon neutrally produced crude sales. And I think, as I've mentioned earlier, this will become a key value differentiator for the company. Another key aspect of our decarbonization plan is powering our business with renewables. We're on track with the power from shore projects at Johan Sverdrup and at Edvard Grieg. And our target is to meet all of our own power usage with our own generated renewable energy. The Leikanger hydropower investment in Norway, which is fully operational, covers about, as you can see here, 60% of our net power usage this year. The MLK wind farm will become operational from the end of the year, and Karskruv will become operational in 2023, by which time we will have a net generation capacity of around 600 gigawatt hours per annum, which is more than our usage. That means that by the end of 2023, over 95% of our production will be fully powered with our own generated renewable energy. So now moving on to our world-class producing assets which drive our business. Johan Sverdrup keeps on delivering above expectations. You can see the stellar operating metrics here. And they've continued with operating costs well below $2.00 per barrel and exceptionally low carbon emissions, more than 100x better than the world average. We continue to see excellent reservoir performance ahead of expectations, and which I've mentioned previously, I think in time we believe will lead to a reserves growth. And we continued to see the facilities capacity increases. Phase 1 capacity ramped up ahead of schedule to the new level of 535,000 barrels of oil per day gross, which takes the capacity additions to around 100,000 barrels of oil per day above the original design level. And this has come for almost no cost. And we recently announced that the full field gross processing capacity has increased from 720,000 barrels of oil per day to 755,000 barrels of oil per day when Phase 2 comes online at the end of next year. This comes as the result of optimization and debottlenecking the facilities. And I think there's potential for more, but we'll have to wait and see how the facilities perform when they come online at the end of next year. As a result of the continuous improvements in this asset, the full cycle breakeven oil price has been reduced further to below $15 per BOE from the previous figure of less than $20 per BOE. I think this demonstrates that this asset truly is world class. Looking now at Phase 2 of Johan Sverdrup. The project remains firmly on track for first oil in Q4 2022 with costs unchanged from the PDO. As you can see here, the key parts of the project are coming together on schedule. In the middle, you can see the jacket for Phase 2 platform was installed offshore in June. And at the top, the parts of the Phase 2 process topsides have been assembled on a barge in Norway for final completion and commissioning, and that topside will be installed offshore on the jacket in the spring of next year. And at the bottom, you can see a riser platform module that was installed successfully in July. And on top of that, we have subsea equipment installations ongoing at the moment. They will be completed this year to allow development drilling to commence early in 2022. So in summary, Johan Sverdrup continues to deliver above expectations, and everything is on track for Phase 2 to start up at the end of next year. And now moving to the Greater Edvard Grieg Area. Our focus here continues to be on delivering the multiple projects that will keep the facilities full in the long term. At Edvard Grieg, we've had excellent results so far for the infill well program, and I'll talk about that in a moment. We continue to see the benefit of facilities capacity upside, with Eva Olson clearly in the decline phase. And on top of that, we're on track with our power from shore project for completion at the end of 2022. The tie-back project, which we'll talk about in a moment, are on track for first oil in the coming weeks, and we're working to bring forward a number of new opportunities. With the de-risking of Solveig Phase 2 and Rolvsnes, those 2 potential new developments that we can move forward. We're currently drilling an appraisal well at Lille Prinsen, and that will be followed by an exploration well on Merckx. So there's lots of positive -- hopefully positive news to come this year. Moving on to the Edvard Grieg infill well program. We've seen good results so far from the program. We've drilled 2 of the 3 planned wells. The first well, A-17, we reported on in Q1, and you can see that located on the map. We've now brought it online. That well targeted lower quality conglomerate reservoirs. And we installed the new Fishbone completion technology in the well with the aim of increasing productivity and reserves. With the well now online, we see excellent initial results. The well productivity is 10x the expected level with the Fishbones clearly contributing to the performance. So really excellent results from that well and a technology that you'll see used in the next well and has application elsewhere across our portfolio. The second well is the A-16 well, and you can see that illustrated on the chart here. That's also being drilled and is now in the completion phase. This is the first drilled branch where we've drilled the Edvard Grieg, and it's the most complex well on the field so far with a total of over 5.5 kilometers of horizontal section completed in the reservoir. We again deployed Fishbones in the first branch, which involved drilling over 180 small bore holes out of the main bore. Again, this is to improve rates from the lower quality reservoirs we see in the Jorvik Basin area. And the second branch was really an exploration branch, which was to test the Jorvik High area, which has been successful and which I think will lead to a small reserve increase in the field. We'll get this well online in Q4. It's going to be brought online at the same time as the third well is completed due to constraints on the platform. And the third one we're going to drill here is targeting the southwest area of the field where we see upside, and it's going to be exciting also to see that well drilled. You can see this is a great project. I think we've talked about this in the past with stellar economics. And you can see the breakeven oil prices for this is below $20 a barrel. So a great project to do and good results so far. And we're already beginning to think about a further phase of infill drilling here. We're also making great progress on the Solveig Phase I and Rolvsnes extended well test tie-back projects, as you can see here. Everything is on track for first oil in the coming weeks, and we're also below budget on both projects. The topsides modifications that we've made at Edvard Grieg and the facilities -- subsea facilities have all been finished. At Rolvsnes, the horizontal well has also been completed, and we've started the commissioning phase for the project. So first oil is going to come very shortly there. And at Solveig, the first horizontal production well has been drilled in the high quality multi-dose reservoirs we have there on that section of the field. And that well is being finished and completed, and we see excellent results here that are better than expected. So, positive news there. And first oil from Solveig will come this quarter with commissioning starting as soon as Rolvsnes is online. Of course, the early production results here are important to us. It's going to be key to de-risking a second phase of development at Solveig and a full field development at Rolvsnes. And those are opportunities, with success, we aim to bring forward to PDO during next year to take advantage of the tax incentives. So the results from these -- the early production results for both projects is going to be important. And of course, all of these projects around the Edvard Grieg area are key to sustaining the long-term plateaus through the Edvard Grieg facilities, and I see that we have more upside opportunities to progress. And pulling all this together, this recaps the long-term production outlook for the Greater Edvard Grieg area. You can see that we've extended plateau to the end of 2023, and that's an extension of 5 years from the original PDO. And with Eva Olson on decline, that will allow production through the Edvard Grieg facilities to be expanded. It's already increased the contractual level that we have from 95,000 BOEs per day up to around 105,000 BOEs per day gross today, and with the potential to increase up to 135,000 BOEs per day as Eva Olson declines further. And importantly, we will have the well capacity to utilize that potential. So I think there's lots more to come. The potential in -- and there's massive potential in the area to keep the facilities full in the longer term, and we're working super hard to realize that opportunity. Now turning to the Alvheim area. You can see that the area continues to add reserves and create value for us. We have 3 infill wells planned this year. The first came online in the first quarter and has performed as expected, and the other 2 wells will be drilled in the second half of the year. We've now 3 new projects in the pipeline: the Kobra East and Gekko project, the Frosk project, and the Trell and Trine project. And together, they add over 65 million barrels of gross 2P reserves and deliver gross peak production of up to 45,000 BOEs per day. So very incremental to the overall facility. We've just submitted the PDO for the Kobra East and Gekko project. That's a subsea tie-back into the FPSO with first oil planned in 2024. And given the time frame the project's being developed under the Norwegian temporary tax regime, it has strong economics with a breakeven oil price of less than $30 per BOE. So a good project and is moving forward. And the Frosk project's the next one to come. It will come forward to PDO in this quarter. And then Trell and Trine is slated for sanction during 2022. So we will have 3 projects moving forward here, all under the temporary tax regime. And you can see we continue to explore in the area. I think it's really encouraging that we continue to find opportunities to create value here. And I think still there's lots more to come. It's a very prolific area, and we keep finding new opportunities. And we're continuing to deliver on our growth strategy. All of our key projects that I've talked about are on track and will deliver production growth to over 200,000 BOEs per day by 2023. And I'm confident we can sustain at those levels with a pipeline of new projects. We've already sanctioned one of the projects. 3 more are heading to sanction. And we have now 3 potential projects that we're de-risking with the aim to benefit from the temporary tax incentives if we can sanction all of those by the end of next year. In terms of other activity, Eva appraisal results came in on the downside. So while there's still probably a project there, it's rather small, and so I think that drops away for us. And the studies we've been doing around the Alta discovery indicate that the favorite development scheme there is a tie-back to Johan Castberg, the timing of which means it's not going to be possible to benefit that from the temporary tax incentives. But this remains a good economic project for the future and something we're very much looking to move forward. It's just the constraints on capacity at Johan Castberg prevent us doing it now. And we aim to deliver future value with a material exploration program with 4 wells remaining to be drilled this year, targeting around 200 million barrels of net unrisked resources. And so I remain excited about the growth opportunities and prospects ahead, and I'm confident we can continue to sustain the business long term. With that, I'll now hand over to Teitur to review the Q2 financials.

Okay. Thanks so much, Nick, and good afternoon or good morning, everybody. So starting here with the first highlight slide for Q2 financials. I think the quarter can, again, be characterized as a very solid operational performance and obviously also helped by our improving macro environment. And also a key feature in Q2 for us was obviously the diversification of our balance sheet and with us issuing our inaugural bonds. Also of the key numbers you see here, Nick has been through the production. As he said, this is a record quarterly production of 190,000 BOE per day. But our financials are driven off sales, not production. And as we have pre-announced, we were under lifted in the quarter by 10,000 barrels. So our financials are driven off 180,000 BOE per day for the quarter. Very good oil price and gas price realization. $68 a barrel for the cargoes we sold of oil during the quarter, and just over $52 per BOE equivalent in gas and NGLs. OpEx continues to be below our guidance of $3.00 for the full year. So we the $2.8 in the quarter. And the investment levels, just below $270 million in the quarter for oil and gas, CapEx and E&A, and just below $50 million in renewable in the quarter. And if we look at the first half, we have slightly underinvested in the first half relative to full year guidance, so you should expect somewhat higher CapEx levels in the second half of the year. So some of the financials. EBITDA, SEK 1.6 billion, which is a record quarterly performance in terms of EBITDA generation. We already set a new record in Q1, and this is then besting to Q1 numbers, which makes for a very solid first half performance. CFFO, just below $740 million. And as Nick said, free cash flow at $423 million for the quarter. The 2 bonds we issued, one was a 5-year bond and one was a 10-year bond, $1 billion each. And the fixed coupons on these bonds sitting at 2.0% for the 5-year bond and 3.1% for the 10-year bond. Very solid uptake with our first issuance. Very strong demand, particularly out of the U.S. market. And we're very pleased with the commercial terms we achieved on these bonds. So that's leaving us with a net debt just below $3.2 billion at quarter end. And that means on a 12-month trailing number, we are now at 1.0x net debt EBITDA as of end of June. If we then go to the next slide and look at some of the key financial metrics, which we sort of measure ourselves up against, you see with the EBITDA on the left, volumes are -- due to the under lift, you had volumes are down 11% compared to Q1 this year, whilst the realized hydrocarbon prices are up 11%. So that gives us an all-in 4% improvement on EBITDA generation on Q1 with somewhat lower OpEx in Q2 compared to Q1. And for the first 6 months, then, that means we have generated close to $2.1 billion of EBITDA. CFFO, $738 million in the quarter. We had cash tax payments in Q2 ramping up from the Q1 level, so we paid $246 million of cash taxes in Q2. And we also had a working capital build during the second quarter of $42 million. We already had quite a big working capital build in Q1 of $135 million, so for the first half, we've built up close to $180 million of working capital. And that's simply a function of an increase in production level with increasing oil prices. And that has, therefore, built up receivables as we have moved through this period. So combined for the first 6 months, just below $1.5 billion, including the working capital movement. And if you add back working capital, it would be closer to a $1.7 billion of CFFO generation for the first 6 months. Free cash flow, as I said, down 20% compared to Q1 at $423 million. And for the first 6 months, $950 million of cash generation compared to a full year dividend payout of just over $500 million. So we have already at half year covered the cash dividends twice over during these 6 months. And then we have adjusted net results of $160 million in Q2. On the face of the balance of the P&L, we reported $166 million net profit after tax. And then we adjust for a non-cash FX gain of $45 million. And also for certain interest rate swaps, which are now deemed to be ineffective hedges due to the issuance of bonds, which led to a $38 million mark-to-market movement on these interest rate swaps, again, non-cash. So when we adjust for those 2 items, we end up with $159 million of adjusted net results. Then moving on to price realization. From our own production, we generated revenue of $1.1 billion in the quarter. And you can see the price realization on the left here. The dated Brent, which is the index we price off, averaged $69 a barrel. And then on timing effect, we actually lifted more volume in June than we did in April and May. And because of that timing effect, it effectively means that our realized price is up $1 because of that. And then we had physical discounts on the cargoes we lifted of just over $2.00 a barrel, which therefore gets us back to a $68 per barrel of oil realized. And on the right here, you see when we blend in the gas, which is a small component of our production mix, but you can see that we have sort of realized 67 -- roughly $67 a barrel per BOE of production. And a very busy quarter. This just signifies the scale of the business these days, the 21 oil cargoes lifted, including co-lifting 4 VLCCs during this quarter. So, very material volumes going through our market, crude oil market and trading department these days. Then looking at the cost picture on the next slide. On the right-hand side here, you see our absolute costs. And this is driven off the production volumes we have as opposed to the sales volumes we have. And you can see the red horizontal line shows the metrics per barrel, $2.80, and it's been hovering around $2.80 for the last few quarters. We've also seen a strengthening knock over these 5 quarters, which is obviously pushing up our dollar OpEx costs since most of our OpEx is not denominated in Norway. But nevertheless, a very stable picture, very good cost control by our operating teams in Norway. And as I said, we remain full year guidance at $3.00 a barrel as we look forward. And on the left-hand side here, we also see the EBITDA margin we are generating was actually a record in Q2, 96% EBITDA margin. It just goes to show that not all barrels are created equal. What counts at the end of the day is the cash generation per barrel we produce. And with the low OpEx we have, these are extremely cash-generative barrels coming out of the portfolio. Then on tax, the tax rate on the face of the P&L was as we expected in the quarter, around about 77% tax rate. And even when we adjust for certain non-taxable items, such as the FX gain of $45 million and the interest rate swaps, which we had to charge to the P&L in the quarter, the ineffective portion, $38 million. Adjusting for those items, we have a tax rate of 78% on the P&L, which is essentially what you would expect, give or take, given that the tax rate in Norway is 78%. And then on the bottom chart here, you see the phasing of the cash tax installments we have made and will be making in the second half of the year. As I said, we paid $246 million in Q2 with $120 million paid in Q1. So first half, we paid just over $360 million of cash tax. And now when we look at Q3 and Q4, when we are starting to reflect the tax installments based on the 2021 performance, we've locked in the taxes almost already for Q2 and Q4. So just below $320 million is the estimated tax installment in Q3. These are actually not denominated tax installments, so it'll depend on the exchange rate in the end. And then just over $720 million in Q4 of tax installments, which means that during the full second half of the year, we will have paid over $1 billion in cash taxes. And then we also give a projection for likely tax installments in Q1 and Q2 going into next year. These numbers will obviously depend on what oil price realization we will have during the second half of this year. But you see somewhere between $330 million and $500 million in Q1, and $660 million and $1 billion of tax payments in Q2 next year. Then looking at the cash flow generation during the second quarter. As we said, CFFO of $738 million. If you add back working capital, we would have been up at $780 million. With the $42 million of working capital build, the reported number is $738 million. And then we had investment activities amounting to $315 million. And for the first 6 months, we have invested $540 million for the 6 months, which is slightly less than 50% of the full year guidance that we have given. We paid out the first quarterly dividends in April this year, $128 million. And we paid our second quarterly dividend in early July, so that will be reported in our Q3 numbers of another $128 million. And here you see the impact also from our inaugural bond issuance, $2 billion of bonds. And these were issued at 99.8% to par. So we backed proceeds of $4 million short of $2 billion. And as Nick said, those proceeds were used to pay down and cancel certain term loans with our corporate facility of $2 billion, and we also paid down the revolving credit facility by $124 million. So that facility is now undrawn as of end of Q2. And then we had other items of $16 million. The majority of that relates to fees on the bond issuance, which then resulted in a cash build during the quarter of $151 million. So in terms of the debt position for the company and the liquidity as we look forward, we now have gross debt at the end of Q2 of $2.5 billion. So that consists of $2 billion in bonds and $1.5 billion in term loans, which have a maturity, as you can see at the bottom here, of $0.5 billion maturing at the end of 2023 and another $0.5 billion end of 2024 and also at the end of 2025. And then our revolving credit facility, which is amounting to $1.5 billion, is undrawn at the moment, but that also matures at the end of 2025. But the key -- one of the key aspects for the bond issuance was, of course, to term out the maturity of our debt profile. And you can see here the 5-year bond matures at the end of -- or mid-2026, and the 10-year one right out to 2031. So that means that the average maturity of all our credit lines at the moment is 5.5 years. So in a very strong position. And of course, ahead of issuing our bonds, we received 2 further public credit rating from Moody's and Fitch. And all 3 of these ratings are now at investment-grade level and all with a stable outlook, where we sit today. And the liquidity for the company is still very strong. As I said, the revolving credit facility is undrawn, $1.5 billion. And when you couple that with the net cash we have at disposal, $300 million, that gives us now a liquidity hedge of $1.8 billion. And then moving on to guidance, the latest guidance we have. As Nick said, we updated the production guidance to 180,000 to 195,000. In mid-June -- or the rest of our guidance has essentially remained unchanged to the previous guidance. So you see all the numbers here, and you also see what the first half actuals have been and how those relate to the full year guidance. And then my last slide is just to recap on our dividend schedule when we go ex-dividend and when we are likely to pay out the proceeds. As I said, the second quarter dividend was dispersed already in early July, as you can see here. And then we have another $128 million being paid out in early October and the last $128 million in early January. So with that, that wraps up the financials, and I'll hand back to Nick for some concluding remarks. Thank you.

Yes. Thanks, Teitur. Just one final slide to summarize. I want to leave you with the message that we delivered record results during the quarter, and all of our main business priorities are on track. I think there's 4 key points that summarize our business. First, our world-class assets continue to outperform, yielding record production and operating costs ahead of guidance. Second, we have a resilient cash-generative business, which delivered record free cash flow in the first half of the year, covering material dividends, funding growth and deleveraging the business. So we've been able to do all of those things. Third, all of our key projects are on track, providing production growth to over 200,000 BOEs per day by 2023, and we have a pipeline of opportunities that will sustain those levels of production. And fourth, we're delivering on our decarbonization plans and will be carbon neutral from 2025, with already 60% of our production being carbon neutrally produced. So those are our second quarter results, and thank you for your time. And we'd now like to open up for questions, which I think the operator and Ed will manage for us. So thank you very much.

[Operator Instructions] Our first question comes from the line of Teodor Nilsen from Sparebank 1 Markets.

A couple of questions from me. First, on your carbon neutral certified barrels, have you actually seen any better realized price as a direct consequence of the certification? Or is that something we should observe in the future? And second question, exciting news on Jorvik and the well you just drilled, and you also talked about the reserve increase. Could you indicate how many barrels we're talking about at Jorvik? And that's all for me.

Yes. Thanks, Teodor, and good afternoon. I'll get both of those. In terms of carbon neutral barrels sold, I think we're getting a lot of interest. I think it's a bit early to see, but we're already selling those barrels to people that we haven't made sales to before. So I think that's an indication. In terms of Johan Sverdrup, given the fact that the emissions are so low, the cost of us of being able to do this looking forward, incremental cost is extremely low. It's less than $0.01 a barrel. So we think it's going to take a bit of time to build the market, but we're having lots of conversations with lots of people, and I'm really encouraged. And I think there's a real potential here to, at current carbon prices, to generate around $2.00 a barrel. And I think as carbon prices increase around the world, that creates even more opportunity to create value here. So I'm absolutely convinced we're going to do it. I think you're already seeing it in terms of the more marketability of our barrels. But being able to put a finger on a real value creation's not clear just yet, but it's going to come. And in terms of Jorvik, this is on the eastern side of the field. We drilled a branch into it. It's shown on the figure. It's not an area that's been drilled in the field before. It's going to -- as I mentioned in my -- when I talked, it'll result in a small reserve increase. I think it's too early for us to give an indication, but -- and we would really want to see the production there from it. But no doubt, we found oil volumes that weren't in our book to reserves. So let's wait and see, and we'll be able to report on that probably at the end of the year. Does that help?

Well, no, it didn't help, but definitely looking forward to the report. But just a follow-up on the first question on the carbon neutrality on the subsequent barrels. Interesting if you actually get some incrementals and new kind of players. Could you sense of like what kind of buyers or new type of buyers you're selling to now compared to before the certification?

Well, we made our first sale to Korea to Caltex there. So we haven't made a sale there before. When we sold our Edvard Grieg barrels, we sold it into Saras in Italy. Again, a sale we'd never done deal with before. And so I think that in itself indicates that we're making our barrels more marketable on a global scale and competing more strongly with other barrels. So we think that there's some value coming from that. So let's see. We're working hard to realize value here. And I think when you see what's happening in the market, others are starting to do a lot more gas sales, LNG sales on the same basis, and it's coming to the oil market, too.

Our next question comes from the line of Michael Alsford of Citigroup.

I've got a couple, if I could. So, good operational performance so far this year. Upgrade to guidance on production, but there's still quite a wide range. So I was just wondering whether you could explain the sort of the lows and the highs to the range and how we should think that will evolve through the rest of the year. Secondly, just on the Barents Sea. Rather underwhelming successes by the industry in the Barents Sea so far this year. I'm just wondering whether you could maybe talk a little bit more about how you see the Barents Sea in terms of your exploration strategy and maybe how that's perhaps changed on the back of the well results for you and the industry. And then just finally, on Kobra East and Gekko, it was a pretty high CapEx number associated with the development of those barrels. I'm just wondering whether you could explain what's driving that such a high CapEx number. I think it was about $1 billion gross.

Yes, Michael, and good afternoon. Good to speak to you again. In terms of production guidance, we -- coming into the year, there were some maintenance activity in the second quarter and early third quarter and also to do with installations offshore that -- but that's all behind us. And as we look forward, we reported 190,000 BOEs per day in the second quarter. As we look forward, we see production around those levels. I think the biggest variable for us is the rate of decline of Eva Olson. So it's clearly on the decline, and we have well capacity to step in and fill it. So that's really what drives the range as we look forward for the rest of this year. And as you know, we like to -- as a company, it's now 24 quarters that we've met or exceeded guidance. And we've tried to maintain a relatively cautious view of how we guide and aim to do better. And that's why we still sort of maintain a range. But you can see the midpoint of that range I think points towards the upper end of the original guidance range, which the top end of which is 190,000. So that feels about where we'd probably land out, but let's see. And in terms of the Barents, it's a good question, and it's one we've had many times. First of all, it's only one core area for us. Exploration, we have 7 core areas through the whole of the Norwegian continental shelf. We remain interested in the Barents. It's a big area. I think when you look at what's being found there, there's really sort of 4 or 5 big discoveries. And given the scale of the area, I can't believe that that's the only thing to find there. So we remain interested in the area. As I say, 1.7 billion barrels of commercial resource discovered there in a few big fields. There's possibly more to find. We have some good prospects, and we will continue to drill and explore up there. But of course, the recent results have been disappointing. But I will say we're in the Wisting field, which is great. It's 500 million barrels. It's heading towards sanction next year, and it's a great project. And of course, there's some other things going on out there. So we remain interested, and let's see what it yields. But as I say, it's only one area out of 7 for us. And then you asked about the K project. I think here is a -- it's a great project. It's a tie-back, but it's got relatively low reserve. So its capital cost per reserve is relatively high. And it's got some quite complex wells involved in it, given that it's a thin oil leg and quite a number of complex long horizontal wells. So I think that's why you see the sort of relatively high development capital per barrel associated with that. But as I say, it's got great economics. It's got basically no OpEx associated with it. So that's the benefit you get here because it's tied into an FPSO that's owned. And the economics are very strong below $30 breakeven. So hopefully that covers those for you, Michael.

No, that's very clear.

Our next question comes from the line of Anders Rosenlund of SEB.

I just have a quick question on the electricity sales from your renewable generation capacity. Is it so that you don't sell certificates of origination from that production in order to qualify for green electricity on your oil production?

Well, our aim is to -- we will have more electricity sales than we need. But that's -- we will -- to become carbon usual, we have to offset with and retire those certificates. But the value on those is very low at the moment, so it doesn't really impact on valuations.

But I'm correct understanding that you don't sell those certificates of origination. You retain those, right?

Well, we have been selling them, yes, at the moment. But that's a consideration for us looking forward. It's something that we need to think about further. But it's not a typical component of our valuations.

No, I'm not thinking about valuation. I was just thinking about the greenness of that production. But okay. Great.

Our next question comes from the line of Karl Fredrik Schjott-Pedersen of ABG.

Two questions from me. First, on your balance sheet. And of course, congratulations on the inaugural bonds. In terms of balance sheet going forward and given the current oil market outlook, you're set to generate a very substantial free cash flow over the coming years. How do you plan to balance cash versus debt on the somewhat longer term? That's the first question. And the second question relates to Alta. Could you provide some more color on what has resulted in this being pushed to beyond the temporary tax regime?

Yes. I can take the first one, Karl Fredrik. It is true. If you look at the cash balance we have at the end of Q2, it's been higher than we have ever had before, because previously we had a reserve based lending facility, which we could pay down and redraw as we saw fit. Whereas with these fixed-term loans and bonds, obviously your gross debt is fixed, and therefore, you're building up cash balances. So that's something we need to review going forward. At the moment, we have $1.8 billion of liquidity headroom. Is that an appropriate level or is it too much or too little as we move forward. I think that will depend on a number of factors, including dividend levels and the new developments that we're going to undertake and also our appetite for M&A. So all that will play into the mix. But the cost of carrying a little bit excess cash is extremely low for us, and so we don't really see that as prohibitive. And on balance today, to have a bit more liquidity headroom we see as being beneficial and gives us a lot of firepower if we want to accelerate some of our activities. And I should say, the cash generation is going to be pretty phenomenal. When we look forward, we should be comfortably below $3 billion of net debt at the end of this year. So those term loans we have outstanding with the banks might come under review as to whether we cancel some of that later on this year or early part of next year.

And then -- thanks, Teitur. Getting on to the second part of your question, which is around Alta. We've long term had a view that this can be developed as a tie-back to Johan Castberg. But with the temporary tax incentives, we [ certainly ] -- whether we could utilize those to accelerate this opportunity, and we've looked to reuse FPSOs and also tie back to Goliat. And we've concluded that those projects don't really work for us, and hence, the fallback is that this will be developed as a tie-back to Castberg in due course. The challenge, though, is that Johan Castberg doesn't have capacity for some years. So we can't now bring this project forward in a time frame that we can utilize the tax incentive. But I think it remains a good project, and it's on the books for the future. So it's a shame we couldn't move forward quicker, but that's the reality.

Okay. And there's no kind of regional difficulties that could have kind of really cost to the Wisting developments.

No, it's completely unrelated. Wisting is so far away. It's completely different. Wisting's a stand -- the thing about Alta is it's -- to put a new facility there, it's just a bit too small. And so we need more resources. There is potential in the area, but we -- it just doesn't feel feasible to derisk. It needs multiple wells to do that. And so I think the best way to move this forward in the future is as a tie-back to Johan Castberg so we can step into the upside opportunities. Whereas Wisting is a 500 million barrel field, which is standalone, and that is very clearly moving forward to development sanction next year.

Our next question comes from the line of Al Stanton of RBC Capital Markets.

Yes. A couple of questions, if I may. Just for clarity, in the Greater Edvard Grieg area, are you going to have to rein in Edvard Grieg to make room for Rolvsnes and Solveig, please?

Yes, Al. That's a good question. So we have a capacity level, the contractual levels of 100 -- as 95,000 BOEs per day. And as I mentioned when I spoke is that we today have capacity to produce 105,000 because Eva Olson is not using part of its share. And as Eva Olson declines further, we can lift further production through. What we're going to do when we bring Solveig and Rolvsnes on is we're going to cut back Edvard Grieg further, and we're going to produce the 3 fields. And the aim is to optimize the production and the offtake from those 3 fields together to maximize recovery within the constraints of the facilities we have. But bringing on new wells at Edvard Grieg, Solveig and Rolvsnes wells, we have a lot of excess well capacity. And that's what drives the plateau extension out for us. So hopefully that helps.

Yes. No, that was clear. It probably explains why production in the fourth quarter doesn't get 200,000 barrels a day either.

That's correct. And Solveig is designed around 30,000 barrels a day, and Rolvsnes will produce a relatively low rate until we understand how the field's performing. And so you get a sense of how much we're going to cut back Edvard Grieg from the 100,000 barrels now down to probably 65,000, 70,000 when we have the other 2 fields on.

And then finally, if I may, with respect to Wisting, you've got a foothold in that with 10%, but you picked up some acreage nearby with a slightly larger stake. Is that a sign of what we should expect? Is there something to happen on Wisting?

We've made no secret we'd like more of it. 10% is a great project, and the only thing is that we'd like a bit more of it. And let's see in time, we may get there. But we compete for acreage with everyone else. And because the consortium look for acreage around Wisting and to add onto it, we joined that, and that's what we were able to pick up. But our general aim is to be in for 30% or 40%, if we can, into new exploration blocks. And our working interest there sort of fits with our sort of desire to be having a more material interest. So nothing to read into it, really, but of course we'd like more.

Our final audio question comes from the line of Yoann Charenton of Societe Generale.

I have 2 quick questions, please. One is basically on your pipeline of projects that you aim to sanction before year-end 2022. I'm just trying to understand how many barrels, as we speak, are still on track for FID by year-end 2022. That would be great if you could provide a sort of growth ballpark number. And then the second question would be on the marketing front. I realize that third party crude sales rebounded quite materially this quarter in Q2. Can you explain what it brings to Lundin to have that many -- that much third party crude to market?

Teitur, why don't you get the second question first.

I can do that. Good afternoon. Yes. So what we are doing here is essentially optimizing the lifting windows of our cargo. So when we sell to our customers, they normally prefer a fairly specific delivery date of that particular cargo, and they're willing to pay a specific price for that specific delivery date. And if that delivery date doesn't synchronize with the lifting slots we have been given at the terminal, then what we sometimes do is to swap effectively cargoes with some of the other operators so that we can engineer a lifting window which fits into the delivery date for the customer. And when we do these swaps, the way we account for it is that we essentially buy a third party cargo from somebody else, and then we sell our own cargo to that same party. And the way we have accounted for it is to show this as gross revenue and gross costs for buying and selling that. But ultimately what it does, it allows us to deliver to a customer which was the best paying customer for us. So that's the rationale.

And I think, to get back to your other question, when we started out, we said sort of 8 or 9 projects that we had, potential new projects targeting 100 -- the 200 million barrels of net resources. And some of those projects are more certain than others, and we're in the de-risking phase. And as I said, 4 of those projects are now certain to move forward to sanction. We have -- one's already sanctioned, 3 sort of heading in that direction, and 3 more are sort of also being derisked. So hopefully, we can get those across the line. In terms of the impacts with Eva going out and with Alta delay, we're down to about 120 million barrels in total for that group of projects. But the reduction in Alta is not a loss of resources. It's just a deferral. And so the projects in total account to about 180 million barrels that we have available if you add Alta in. Hopefully that…

Yes, that's very clear.

We currently have no further audio questions. I will hand back to the speakers for any web questions or final remarks.

Thanks very much, Keith. Yes, we do have a couple of questions from the web. So I'll close on this. There's a couple here from Matt Smith at Bank of America. Could you give some color on Edvard Grieg current performance and expectations towards year end versus May record NPD production data? And what is the likelihood of seeing M&A activity in the next 12 months? Capacity is enhanced each quarter by the cash flows. Do you see opportunity sets out there? And what Brent price is assumed in the fixed tax installments for 2021, Teitur? So Nick, that's probably 2 for you and then the last one for Teitur on taxes to oil price.

Yes. I'll capture the Edvard Grieg question. I think, Matt, what you're seeing is a period of time where Eva Olson had some downtime. And every time we see downtime at Eva Olson, we have the capacity to expand production. I think Eva Olson suffered some upsets there and was also cut back due to gas processing at the onshore gas terminal, which was restricting them. So every time we see cutbacks there, we have the ability to utilize our excess well capacity at Edvard Grieg and produce and do so. So that's what you're seeing is that period. And that's going to continue for us. With bringing on Solveig, bringing on Rolvsnes, bringing on 3 new wells at Edvard Grieg, we're going to have significant excess well capacity for quite some time. But as I say, we're limited by other constraints. So if we make our -- that's why we have a wide range of outcomes for the full year, even though we're at midyear. So hopefully that covers off that question. And Ed, could you just remind me on the…

It was on M&A. We've got -- clearly, each quarter that goes by, there's a lot of cash flow generation. And what is our sort of M&A appetite over the next 12 months like?

Yes. It's a good question. And our principal focus of growth is through organic growth, but we also do look at M&A opportunities. A good example is a piece of Wisting that we bought last year. But there's a couple of provisions. First of all, they have to fit with our strategy. So we're not interested in mature assets. It has to be early life or undeveloped opportunities -- Wisting fitted into that -- and it has to be high quality. And secondly, we have to be able to get it to the price where we can create value, too, and those things aren't always the case. But if we can find those opportunities, we have the financial firepower to do lots of things. So we keep looking, and if we find something that's really value accretive for us and fits the strategy, then we will do it.

And then there was a question on oil price assumption from the tax installments.

Yes. For the second half of 2021 second.

Yes. So when we set these tax installments, we put a projection into the oil taxation office in early June. Normally based off on a specific oil price, and in this case it was sort of in the low 60s that we projected forward for the second half of the year. Of course, there are other items coming into that as well; production volume and OpEx and capital investments for the rest of the year. So there are a few moving parts. And obviously, since we submitted our projection, we have upgraded our production outlook for the full year. So this new guidance we're giving today on Q1 and Q2 next year reflects our very latest outlook on all of those items.

Okay. Thanks. Thanks, Teitur. The last question from the web, it was a rather shy person because they haven't given us their name. But one of the questions has been about acquisition, and I think we've sort of covered that. But one area he or she was wanting to ask about was reserves concentration into Edvard Grieg and JS, and is that a concern of ours going forward that over 90% of our reserves are contained within 2 fields? And is that something that we're concerned about? Is there a strategy around that?

No, Ed. We're not particularly concerned about it. What is positive about it was we have reserve concentration into extremely high quality world-class fields, and that's what we would like to see, actually. So actually, I think it's a positive for the business that we have such high quality fields with low operating costs and cash generative. And that's really how we look at it.

Super. Okay. Well thank you, Nick and Teitur. And thank you, everyone else, for joining us today. If you have any other follow-up questions or want more detail, please don't hesitate to contact me. And have a good summer. Thanks very much.

Thank you.

Thank you.