[Abrupt Start] show you the results and highlights presentation. Then, we'll open up for a Q&A over the phone and we'll expect to finish the call inside the hour, as I know this is a busy day for everybody. Also, on the call we have Svein Skeie, Head of Performance Management; and Ørjan Kvelvane, Head of Accounting. And with that, I pass over to Lars Christian to get us underway.

Thank you, Peter. Good morning, everybody, and thank you for joining us. In the second quarter of 2019, Equinor delivered good overall operational performance in a quarter characterized by a record high project activity and many planned turnarounds. In addition, our financial results remain impacted by lower realized oil and gas prices and our production mix in the quarter. We have said that we expect price volatility and therefore, it is important to sustain and build up on the structural improvements achieved during the past years. I'm pleased to see that we continue to demonstrate strong cost focus and capital discipline. Equinor is a stronger company than we were just a few years ago. We have a stronger balance sheet and more competitive projects and we are more resilient to lower prices as well as carbon impact. With our net debt ratio below 20%, Equinor continues to be in a strong financial position and the Board has decided on a dividend of $0.26 per share for the second quarter, up 13% compared to last year. Based on our strong capital discipline, continuous improvements and project execution, we are today lowering our CapEx guidance for 2019 from $11 billion to between $10 billion and $11 billion. Strong project execution is also why we are lowering the CapEx estimate for Johan Sverdrup Phase 1 by a further NOK 3 billion from $86 billion to $83 billion. Since the PDO for Johan Sverdrup Phase 1 was approved back in 2015, recoverable resources have been increased from a range of 1.7 billion to 3.0 billion to a range of 2.2 billion to 3.2 billion barrels. In addition, we have reduced operating cost by around 30% and CapEx by NOK 40 billion. These are unprecedented deliveries from a dedicated project team together with our partners and suppliers. During the first half of 2019, the successful top side lifts at Johan Sverdrup reduced P schedule risk, and we are on track to start production in November as planned. And we expect to reach Phase 1 production plateau of 440,000 barrels per day during the summer of 2020, which is earlier than previously communicated. Just before the summer, Norwegian Parliament approved the Phase 2p development, which will bring the plateaued capacity to 660,000 barrels per day, with a unit production cost of around $2 per barrel, a breakeven oil price below $20 per barrel and a CO2 emission well below one kilo per barrel. Johan Sverdrup is, in my view, the best development project in the world today. As announced earlier this month, we have agreed to sell 16% of our Lundin shares and increase our direct equity position in Johan Sverdrup from 40% to 42.6%. Our Lundin investment has been very profitable. Since 2016, we have more than doubled the value of our investment. We expect to receive around $1.5 billion in cash during third quarter, retain a 4.9% stake and book a gain of around $1 billion. We expect to finalize the acquisition of the 2.6% equity in Johan Sverdrup following government approvals in fourth quarter of this year. Let me also remind you of a few other key developments achieved by Equinor so far this year. We have made commercial discoveries on the NCS and secured new prospective acreage, including offshore Argentina. We have agreed with OMV that Equinor will take over as operator of the Wisting field in the development phase. We doubled our equity investment in the Caesar Tonga field deposit Gulf of Mexico to 46%. And lastly, we started production from the Chesterfield in the Norwegian continental shelf. And finally, we were awarded the right to develop the largest off-shoring project to date for Equinor. The Empire Wind project, offshore New York, is a breakthrough achievement for the development of our global renewables business. The project is twice the size of our developed offshore wind projects to date. We expect to start the Empire Wind development in 2021 with 60 to 80 bottom fixed turbines, and output will generate sufficient power to serve more than 0.5 million Europe households with renewable energy. The safety of our people and integrity of operations are top priorities for Equinor. We work very hard to maintain a strong safety culture and to deliver good safety results. Over the last 12 months, our Serious Incident Frequency continued to be stable at 0.5 incidents per million hours worked. This is the best safety performance level achieved in Equinor's history. Our strong safety focus and drive to further improve continuous undiminished strengths. Management visibility and setting clear expectations are top priorities to deliver on our always safe ambition. Now to the financial results. We delivered net operating income of $3.5 billion in the quarter. Adjusted earnings before tax in the quarter were $3.2 billion, down from $4.3 billion in the same period last year. We delivered overall good operational performance and maintained a high production level. This quarter, we delivered a production mix on the NCS with 60% gas and lower liquid share than usual. Lower oil production was mainly due to unplanned production losses on [indiscernible] and reduced production from partner-operated fields. Higher gas production is mainly due to the start of Aasta Hansteen contributing with around 60,000 barrels per day. As I mentioned, our financial results were negatively impacted by lower commodity prices. Other realized liquid prices in the quarter was down 10% to $59.3 per barrel. Within liquids, we have a relatively high NGL share of 24%, impacting realized prices. We expect the liquid share to increase as a result of higher production, especially with the start of Johan Sverdrup. Also, our invoiced gas prices were down 16% in Europe and 4% in U.S. The demand for gas in the EU increased by 15% from the same quarter last year. The new and increased LNG capacity, combined with lower demand in Asia, has resulted in temporarily lower gas prices. Still, the fall in our realized prices was less than half of the reduction in NBP prices. Market volatility shows importance of our continued strong focus on costs. In accordance with our expectations and previously communicated, our costs were somewhat up compared to last year due to new fields onstream and preparation for start-ups. As in the first quarter, increased reserves on several fields reduced our overall depreciation costs. The group tax rate on adjusted earnings was 64% in the quarter. IFRS net operating income after tax in the second quarter was $1.5 billion, up from $1.2 billion in the same period last year. And our quarterly adjusted earnings after tax of $1.1 billion was down from $1.7 billion. Now some comment on each of the segments. E&P Norway delivered adjusted earnings before tax of $2.4 billion in the quarter, down from $3.1 billion in the same period last year. This is mainly due to lower realized prices. In addition, we had 2% lower production with a mix more skewed to gas than usual. As normal in the second quarter, we had several turnarounds which reduced production. These turnarounds mostly impacted our liquid volumes. In addition, we experienced some specific production challenges on Snoda Gravel and Aasta Hansteen. Good cost control was maintained on the NCS in the quarter. Underlying OpEx and SGA costs were lower this quarter than in the same period last year. E&P International delivered adjusted earnings before tax of $649 million, down from around $1 billion in the same period last year. Adjusted earnings after tax were $442 million, down from $752 million. The after-tax cash flow per barrel for E&P International in the quarter was strong at around $25. Including turnaround effects, we delivered a production rate of 820,000 barrels per day, the highest second quarter production ever achieved internationally. A strong cost focus in our international operations delivered stable cost quarter-on-quarter. Let me also mention, in Nigeria, due to lifting schedules, we saw less volumes that produced in the quarter income around $70 million will thus be booked in later quarters. Our MMP segment delivered adjusted earnings of $210 million compared to $300 million in the same period last year. Weak refining results affected MMP negatively this quarter. In addition, we also had a negative timing effect related to the valuation of gas in storage. According to accounting principles, we had a write-down of the gas inventories due to the drop in gas prices in the quarter. However, the gas inventory is sold forward at higher prices and expect to deliver is during winter. Without these timing effects, MMP would have delivered adjusted earnings within the guided range. We maintained a high production rate. Equinor's production in the second quarter was 2,012,000 barrels per day, on par with the same period last year. Expected natural decline on fuels and production was offset by new fields and new wells brought onstream, especially on the NCS and in U.S. onshore. During the first six months of 2019, we report a solid cash flow from operations and a net free cash flow were $1 billion. We maintained a net debt ratio below 20% and our organic CapEx for the year-to-date is $4.8 billion. In addition, we have closed several value-generating transactions and we paid $1.6 billion in dividend and $4.2 billion in tax. Let me conclude with our updated guidance. Last year, we had a record high production and we expect to be around the same level this year. From 2019 to 2025, we expect 3% average annual production growth. Excellent project execution and cost control make it possible for us to lower our organic apex guidance from $11 billion to $10 billion to $11 billion, and we maintain our 2019 exploration activity guidance of around $1.7 billion. And with that, I'm pleased to open up for questions and hand it back to you, Peter. Thank you.

Thank you, Lars Christian. And then, I'll pass back straight to the operator who can remind people of the process for polling questions and then we'll start to take the first one. Thank you.

[Operator Instructions]. And the first question is from Oswald Clint from Bernstein.

I wanted to ask about the gas and I guess, I wanted to ask why your gas production was up so much in Norway in the second quarter? But you mentioned demand was up 15%. So could you perhaps break down that demand and tell us where it's coming from in terms of power/residential/industry, please? But primarily on the topic, I wanted to know that -- you talked about 2020 moving to spot gas prices primarily. But if prices were to remain weak, could you delay that intention and continue to be selling forward in terms of natural gas sales? That's the first question. And then secondly, I was just curious about sustaining Norwegian volumes longer term, and I know you had that planned for extending 20-odd platforms through time and I see that here you've had eight of those approved by the government. Is that number in line with the plans so far? And when would you expect the other ones to get approval?

Thank you for a very good set of questions. On the latter, we feel that the eight approvals so far is in line with our plan and the others are progressing nicely. So we don't expect any sort of surprises when it comes to that. It's just a lot of work that needs to be done and documents that needs to be provided. On the gas production in Norway. Yes, it is up compared to previous year's quarter, mainly due to starting up Aasta Hansteen and bringing some 60,000 barrels of oil equivalents per day to Equinor. Then, we have had some temporarily operational restrictions on Oseberg during the quarter related to any gas reinjection. So that means that we have exported more gas from Oseberg than would have been normal during the second quarter given the seasonal variances in the prices. Troll gas production were down, in line with what we usually do for a second quarter. Then, also the turnarounds for this quarter, the majority of them are hitting the oil production, the liquid production, whereas third quarter this year, the turnarounds that are coming up will to, a larger degree, affect our -- or impact our gas production compared to what was the case for second quarter. So the last piece of your question related to sort of the 15% increase in European gas demand. It's partly weather, colder April and May, the residential demand was up some 5.5% this year. And then there is sort of quite an extensive switch from coal to gas of around 4 bcm adding to it, so that explains those trends to put it like that. The good thing about, in many ways, the production mix is that this is temporary, and we expect the liquid share of the production mix to come up again over the next couple of quarters and even more so when Johan Sverdrup comes onstream during November.

That's really helpful. Sorry, there's just a tiny bit at the end about 2020 onwards in terms of moving your natural gas to spot prices. Is that something that could be pushed back in time?

Well, the shift that we're doing is that we want to expose more to the spot market, and we see that we benefit from having entered into contract more on a season ahead than a year ahead, and both for this quarter and we expect the same to happen for third quarter and then gradually that will fade out. And if their forward prices for gas are to stay low, then we will not sort of be able to achieve the same effect running the businesses, the old way of doing it. But the shifts to more to the spot market does not limit us. On the contrary, we would like to take a more active role in placing sort of our gas volumes in the market. So if you see that the gas prices medium and long term comes up, we will go more for a season ahead than a year ahead, of course, if we believe that, that is favorable.

Next question is from Biraj Borkhataria from Royal Bank of Canada.

A couple, please. The first one on production. You mentioned a couple of things on unplanned downtime. Can you just talk about whether those issues are now behind you, and also how much contingency is built into the flat production target for 2019 at the group level? And the second question is on CapEx and the reduction. I remember asking this question at the CMU whether the target was challenging enough. And I'm wondering, on the one hand, are you setting the bar challenging enough for your businesses because you have a wave of improvement processes and digitization, all these things coming through. On the other hand, when you look at volume numbers, particularly from the NCS, which are declining year-on-year, and your spending levels are coming down, I guess investors might get a bit nervous about replenishment, particularly in Norway. Sorry, it's a bit general, but could you just talk about the balance of those two factors? Just interesting to get your thoughts.

First, on the operational issues. Oseberg reinjection is up and running again, so that is behind us, and we expect Snoda Gravel to come on stream during second half. That issue with the flexible risers to be sold. On CapEx guidance, we started out the year with a CapEx guiding of around $11 billion and now we are saying between $10 billion and $11 billion. And this is due to capital discipline and very good project executions, in addition to improvements in the business and very happy to see that improvement because this is definitely a positive result, which brings us a lot of learning definitely. And we have seen over the last couple of years, and you have seen too, in our numbers, how we've been able to bring down the development cost and now having a portfolio that is extremely profitable and resilient in a sort of global perspective. So what we're doing moving forward with revenue project is that all our learnings, we're trying to factor into the new developments. So this is the way of running the project is in many ways setting a new standard for ourselves and somewhat even argue for the industry and for others to judge, but this is then for us to draw the maximum learnings going forward. Then, there were some other questions that I really sort of -- yes, there were a lot of them. Svein?

No. Maybe then on the NCS, a reminder of the IOR that we're doing. We said that we're going to drill around 100 production wells per year with a breakeven below 20, a short-term payback period and we will continue to do that. And we are on our plans also with that one, which is also something that will benefit the production going forward.

Next question is from Thomas Adolff from Credit Suisse.

The Johan Sverdrup went up. Previously, you've guided to within 12 months, now you're say plateau will be reached during the summer. What's driving that confidence with the faster ramp-up? And then secondly, if you look at M&A and compare that to buybacks, where do you see more value today?

First of all, on Johan Sverdrup, sort of the faster or early ramp-up targeting plateau coming summer whereas we said that 12 months ago -- or within 12 months or so months ago, and the reason is the progress of the drilling of the wells. There is a lot of work still remaining offshore. I worked offshore for seven years, I mean, starting up several platforms and this is the first time we're going to start up beyond Sverdrup. a lot of nitty-gritty details and pieces and valves and documents and start-up procedures and all that kind of stuff that needs to be in place and verified and people go through it and train and all that, so it's a lot of work still remaining which makes us keep the startup to say during November. I see others are saying they might be starting up earlier. I hope we can start up earlier. I'm a positive guy. I've always been. But I'm also realistic, and I know how much work and hard work still remains for us to deliver on that start-up during November. But I'm also very happy to see that we can guide on the cost of ramp-up. Then we have never really produced this asset. And I get questions from time to time about where can we increase the reserves and all that kind of stuff. And I feel the respect that those are valid questions and important questions, and we will ask them too, internally. But now it's more about getting the job done, prepare for startup, getting it to start up and deliver on the plateau and then we will start getting production experience and see how this reservoir is developing and responding to the different levers that we have to pull that we have in our toolbox when it comes to reaching and delivering on a high recovery factor. In many ways, you can say that I'm giving you a bigger sort of longer reply than your question merits, but I think it is important. I understand fully the big intention related to these assets, and it deserves so. But that's how the timing of different aspects related to the development is -- will pan out. On the M&A side, we see that there are some pockets around the world. The products that are...

If you were to use -- just around the capital framework -- sorry to stop you there. If you had to compare M&A with buyback, where do you see [indiscernible] given you [indiscernible]

That's where I'm coming to. M&A versus buybacks. We have said that we would like to strengthen our balance sheet. I think the last quarters too, very -- volatility in commodity prices merits to keep a very strong balance sheet. We have said that cash dividend is a preferred means of returning cash to our shareholders. And then, at this point of time, going forward, we will look at the world and the outlook and that good opportunity set. And if we can make good business deals like the Lundin recent transaction announced and the doubling or [indiscernible] at Caesar Tonga, then that is for us very, very important to do. And then don't forget that we have an extremely profitable sanctioned portfolio of projects, but also a very attractive unsanctioned portfolio projects that we will like to pursue which we believe overall will represent the best value proposition for our shareholders and then pay back -- or sorry, buyback is still part of the toolbox.

Next question is from Lydia Rainforth from Barclays.

Two questions from me. Just coming back to that performance issue question from Biraj. What can you actually do in terms of -- because a lot of that seems to be from non-operated assets, so just in terms of what you can do about addressing that performance issues that you had within the NCS? And then the second one, just in terms of cash flow, clearly, we still have weaker gas prices I think than were in the plan. If that -- if we go through the second half year, how much -- or how confident are you that puts at risk, the cash flow forecast to the group?

Well on the performance issues related to our nonoperated assets on the NCS, as in every partnership where we are not the operator, we are supporting the operator and pushing the operator and that is what we're doing in this case, too, to see if we can help out to the best of our ability for having good results also delivered from non-operated assets. On the cash flow for the quarter, as you say yourself, it's highly impacted by the commodity prices and gas being one of them, but it is also impacted by the fact that we have two tax installments on the NCS for this quarter compared to just one the previous quarter. I think we [indiscernible] guided you something about $1.5 in reduction in gas prices would represent sort of $1.1 billion in lower sort of cash flow or NOI per year, so that is kind of the range that we're talking about. And you can do the calculations as good as I can about the different scenarios going forward. But we believe that will be cash flow positive at 50 for the full year 2019. And when it comes to sort of CapEx guiding for the period of time going forward, then the first opportunity for us to revert you on that will be in the Capital Markets Day coming up early next year.

Next question is from Teo Nilsen from SB1 Markets.

Two questions, then. First one, a quick one on Sverdrup and then the ramp-up of [indiscernible] from first one until summer 2020 or it will be back-end loaded production growth? And my second question is related to walk on in Norwegian meta where we've seen a lot of discussions regarding walk on development solutions. So my question is, how does the recent Liatorna discovery change your view and then what walk on situation you preferred development solution?

When we start up the wells, every well, we ramp-up gradually and define what we call the sand-free rates. We don't want to produce sand. And for that to happen, you have to use a separator and some equipment to determine that flow rate, which is kind of the maximum flow rate for that well. So starting on a totally new field like this, you will need to do that well by well and just add it on and stack it on top of it. So it's neither nor of the two, it's more kind of like walking a staircase because you'd rather you ramp-up one and then you will have determined what that plateau should be like, flow rate-wise; and then you have the next one and then the next one. So you see already in our guidance for this year how we believe that, that ramp up will be reflected in our numbers where we're saying it's going to be around the same levels as we have last year, which was a record high. And then we will come back to how this is going to be factored into the 2020 production numbers in more detail because then we have at least a couple of months -- two months of production history hopefully, close to, when we get to that stage. And then Marca and the Liatorna discovery. Marca is a huge area on the Norwegian Continental Shelf and it stretches from a bit Oslo, the capital of Norway to beyond [indiscernible], which is a small town to the rest of -- far west of Oslo. For those interested, you can look it up in Google Maps, I guess. But we believe that this area will be best developed if you look at it as one area solution to the North where Equinor is the operator and one to the South Arca BP is the operator. This will bring best value to the companies involved, to the Norwegian government, which has an interest in how this is being developed and also from a resource and development point of view. So then to the discovery that Arca BP just did recently on Liatorna we believe that, that is just going to support the area solution to the South and bringing that into better economics. And then I think it is important to look at the improvements that we have done in our proposed solution to the north. We have worked it like we did with Johan Sverdrup, like we did with Johan Castberg, Bay du Nord and others, and really been able to bring down the development cost, and that is what makes this a very good proposition, same from our point of view. And we would expect that the same way of thinking with -- and the same way of economics and maximizing the revenue for all parties involved, if they did the same to the south.

Next question is from Christyan Malek from JPMorgan.

Two, if I may. First on the international strategy. Clearly, that's been source of underperformance for reasons sort of less conspicuous, but I want to understand more in terms of strategic perspective. What are you looking at internationally that you're effectively using your use of capital allocation towards, is it Brazil, is it shale? And if not, I'm struggling to understand why we're not seeing more cash return on the horizon particularly given your gearing rate is starting to sort of come -- continues to outperform and really your balance sheet in the right direction. And the second question is on Lundin. Why sell now? The logic behind it and including the sort of remaining stake of 4.9%, what are you planning to do with that? I mean ultimately, how do you think about that transaction in the context of the capital allocation and cash return?

We have developed over decades as a company. We have been competing on the NCS with some of the biggest international companies for decades and learned to survive and thrive and compete at very good returns and results. We have seen, when we moved internationally, that we have nothing to be shy of. We have an excellent organization; excellent track record and people want to work with us. People invite us into partnerships and governments are inviting us to bid for opportunities because they see a company that has a lot to show for and, not only sort of return-wise, it's our toolbox, it's our way of thinking when it comes to taking care of the environment, being a prudent operator, how we treat our employees, all that kind of stuff adds up to a basket of being an attractive employer but also attractive partner and operator to have in your neck on the woods, depending on where you look around the world. And we then, you see that we are taking on more and more opportunities and also as an operator because that's when you really can make a difference and have an impact on the development solutions being brought forward. And we strongly believe that a lot of the deals that we have done over the last couple of years, the Carcara, the Bay du Nord discovery, the MC33 Nepal, taking on that operatorship based on a stellar drilling performance, and all these makes sense for us because it's the best way of returning cash and value to our shareholders over time. We could choose to write-down the depreciation curve as accountant once said by spot investment and return the cash to you guys. But that is not a sustainable business for a company like ours. So that's why we need to and want to gradually build our company. So yes, I'm buying shares in Equinor every month and I recommend everybody else to do the same. On the gearing range, we have said that 15% to 30%, this is good for IFRS. You could add another 5%, 6% based on IFRS 16. In fact, 15% to 30% and we are comfortable being below in periods of time and comfortable by being above. And now we are at 19.9%. Everything else being equal as far as what we see now, of course, the cash that we're getting from the Lundin transaction in the third quarter, most likely will improve that net debt Tier 2 somewhat and then we're going to buy the 2.6% of equity in Johan Sverdrup in the fourth quarter, and then it's somewhat back up again. So I think that is the most granularity I can give you on the gearing. And why sell now? Well, this was the opportunity we got. When we entered into this, we wanted to be exposed to Johan Sverdrup production and now this opportunity came along where we could have an industrial solution, where we take direct equity into this asset and could also monetize on a very good investment where we doubled the value and then we are left with some shares in that company, and we are very happy to see that is part of the deal, too.

If I could just push you on that, your preference to build over cash return, if I'm clear on that response. I mean, would you consider wholesale M&A in the context of your build [indiscernible] for strategy or it's more going to be through strategic asset sort of sales transactions? So I just want to understand if there is a priority within that build strategy?

There's only one priority and that is to maximize the shareholders' value.

Next question is from Jon Rigby from UBS.

Just on the NCS operating cost. They appear to be -- unit costs are rising, again. They clearly came down very significantly post-2014. I just wondered whether you were able to run pick the various elements of that, so sort of mixed effect, I guess, there is sort of dollar-kroner effect in there although I think guidance was beginning to think about using kroner and also whether there is any underlying operational inflation starting to come back in to it? The second question is just on your gas trading business. Is it likely that even with the Danske acquisition that while prices in absolute terms remain as low as they are, which, I guess, could be for a couple of years, it just will be very difficult to generate margin from that business much higher than the lower end of the guided range until we see some sort of recovery and stabilization in gas markets?

When it comes to NCS and adjusted OpEx and SG&A per barrel, it is up 7% year-on-year in absolute costs. It's up 6% year-on-year. This is the total picture for the company and the group. So if you adjust then for Roncador coming in and also Aasta Hansteen and some changes related to divestment of Alba and gas lead removal costs, asset removal obligation adjustments, the absolute cost is flat year-on-year. So to your point on whether we see some cost inflation coming back into our business, I'm almost schizophrenic on this one because we're looking every day in and in every corner and in every part of the business to see if we can see any cost inflation. We see kind of a push for cost coming up, we're seeing more from external market side of it. Globally, there are still good capacity but there are some pockets rates in Norway, for example, even Norway is part of the global market, it takes time to bring in another rig if you want to do something about the capacity of the supply side. So we see some trends in some areas that might reflect or represent higher sort of supplier costs. But I mean, we have secured contracts, procurement contracts were $100 billion at the end -- I told you around the Capital Markets Day. So we are quite sort of comfortable in a short return picture on this one. Then, the medium term, longer term, beyond two, three years, it's related contracts to determine what the contract terms will be. But 80% of improvements is still by our design, in combination with the improvements that the supplier industry has delivered. So that is what we're focusing on primarily, to keep and churn it to become even more competitive going forward. To Danske Commodities, to Danske, we expected when we bought it and that is reflected in the numbers too, that you're saying during third and fourth quarter that they are making most money because that's when you really have the spikes and the volatility to thrive on and that we hope will be the case regardless of whether the gas prices are low, medium or high. Anything else to add to this, Jan or Svein?

Just to comment on the absolute level on the gas price. Remember that it's a flow-through of the price going into the DPN segment of that one and the MMP is more picking up the margin on it. So it's within the price level will be more reflected in the DPN and the in segment rather than in the MMP in itself. Then, we have the trading advantage that we can do on top of and that's what we're doing in the MMP.

Next question is from Michele Vigna from Goldman Sachs.

Congratulations on winning the offshore wind project in New York State. I was wondering if you could give us a bit more detail on the economics there in terms of what IRR you expect on an unlevered basis, and then what you expect on a levered basis? And then also if you plan some farm down of that large investment? And secondly, I was wondering on your gas realizations, is they're quite difficult to model as you can expect. I was wondering if you could guide us for the second half of the year on how much of the volume had effectively been pre-sold in the previous three to six months versus how much we should expect to be broadly linked to spot prices?

Empire Wind, we are very happy that we won that auction. This segment of the business, you see from our Capital Markets update that the current project that we're having in our portfolio, we're up and running, producing, having returns around 10% and that is on a project basis. It's not on an equity leverage basis. And then we have seen that there's a huge competition in this segment, pushing down sort of the returns and we have not been willing to compromise on returns. We have seen -- looked at a lot of opportunities and chose not to bid. We have looked at some opportunities and chose to bid and we lost because we didn't want to compromise on the returns. And then we see a few opportunities that we really would like to pursue because those projects can create good value, and we believe Empire Wind is one such project. And then it is too early in the stage of that development to say something about the returns and the terms and all that kind of stuff. We really need to move forward and start construction in '21 and start delivering power to the grid during 2024. So we have ample time to discuss this going forward. On the gas side, Svein?

Yes. We have sold and are benefiting then from the long-term gas sales as of this quarter. And second quarter, we had done it was gas spot of 5.49, we had 4.09 in the NBP price. We were also seeing benefits from the gas sales now in third quarter as Lars Christian said earlier. Based on what you see in the current prices, it will be somewhat on but still way above what we see in the current NBP market. And also, commercial reason of not disclosing exactly what kind of volumes we have on it, but it will be about more than BP prices.

Next question is from Christopher Kuplent from Bank of America.

And I just have two questions remaining. The first one, I suppose you tried to answer in reverse earlier on Johan Sverdrup and Lundin and the transaction. I wonder whether you, in fact, are signaling that you are very excited about Johan Sverdrup with the price you're willing to pay. And my question is, do you see more opportunities for increasing your exposure or equity exposure to Johan Sverdrup? Have you had other discussions with shareholders within Johan Sverdrup? And are you keen on doing so? And the second question is, again, on wind. Just wonder whether you can tell us within 2019, '20, whether there are contingencies in your CapEx plans because it looks like to me, there isn't much actually going to be spent on wind in the near term. Just wondering whether you can confirm how much, if any, has been budgeted?

On Johan Sverdrup, if you have met a single Equinor employee that is not very excited about the Johan Sverdrup, please give me his or her name because I would like to know who he or she is. I mean, this is definitely a project that everybody is very excited about. This opportunity arose to take more of an industrial solution and get direct equity into this asset and we are very happy that this turned out the way it turned out. And the way we read the comments in the market was that it looks like Lundin was making a good deal, and it looks like Equinor was making good deal. So in this case, I think we struck a prize or a package then looked like something of a win-win situation. Whether we have discussed -- discussions with others in Johan Sverdrup or discussions with others in other assets or not have had them or will going to have them or not, we are a company that do not give comments about that. You will read about it in the papers. On wind and capital spending going forward, currently around 5% of our CapEx is related to the wind or the renewables segment. We have guided on 15% to 20% of our CapEx in 2030, should be within an ambition to be within the renewables segment but back-end loaded then, not a linear curve. The Empire Wind is a very big building block in that to happen. And we have in our capital plans for '19 through '21, around $11 billion year-on-year that we have guided on average. We have also renewables projects as part of that and then we have oil and gas projects to partner with. We are running a business today like we did during the downturn with a contingency plan. And if the oil price were to drop or the commodity prices were to drop, really rock-bottom and stay for a long time and we need to free up some flexibility, we do have so the opportunity to do. But at the same time, we believe that this level is something that, given the pricing and the balance sheet strength, and so on, we would like to progress along these numbers and that gives room for both growth within oil and gas as well as renewables.

Next question is from Martijn Rats from Morgan Stanley.

Yes. I hand it back. My questions have been answered.

And next question is from Peter Lowe [ph] from Redburn.

Just a clarification on CapEx in 2020 onwards. Do you see that $11 billion number as being adequate to deliver the production growth targets you've outlined in 2025 or is the expectation that, that will be supplemented by further opportunistic resource acquisitions going forward?

I did sort of comment to the CapEx spending organic so far this year and we guide on $11 billion, that's based on an exchange rate of $8.25. So we -- if you use $8.25, you get $4.9 billion CapEx spending so far this year compared to what you see in the numbers of $4.8 billion. That's just a detail, but something to be aware of. When we announced the production sort of numbers and the CapEx guiding at the CMU, the $11 billion for, on average, for '19, '20 and '21, and the projects then being sanctioned is sufficient to bring us and give us the production growth that we told you about. And then, of course, beyond 2021, we'll also sanction new projects, but that is also turning in to be a very attractive portfolio.

Next question is from Yoann Charenton from Societe Generale.

First set of questions will be on Empire Wind. You referred to a $3 billion CapEx budget for developing that project. How much of this will show through organic CapEx, roughly speaking? And second question will be on the cash flow statement. You reported a very significant increase in financial investments in the first half of the year versus '18. Could you please describe some of the underlying factors leading to such an increase?

First of all, on Empire Wind, the $3 billion, we are working -- going to work this project and start up construction then in 2021 for that project to be onstream in 2024. And the majority -- this is the organic spending that we expect to have on this project in that ballpark. On the financial investments, Ørjan, you want to give some meat to the bone on this one? Ørjan Kvelvane: So it is important to look together with the cash elements, so this is part of our liquidity management, and it's about whether our instruments are above or shorter than 90 days. So this is only kind of classification and then hits the cash flow based on that.

Next question is from Anders Holte from Kepler Cheuvreux.

Just one follow-up on the wind project, if I may. I know you say it's early days, but I guess, to look at Ersatz materials, they say that they target an unlevered IRR of 7.5% to 8% on new wind farms. Is that a level that you would be happy with in recent wind projects? Or are you looking for inherently IRR on your offshore wind?

We are currently having a couple of assets up and running on a project based return, we're talking about around 10%. It's a huge sort of a mixed basket of numbers out there, some are leveraged on an equity basis and all that. But on this project, a lot of work needs to be done and some contracts that needs to be negotiated to find out what the terms will be for Empire Wind, and we will revert when we have more details on that one.

And that was our final question for today, so I'll hand the call back to the speakers. Please go ahead.

Okay. Well, thank you everybody, and please thanks -- we've covered everybody's questions, and we're absolutely bang on time for the hour. So thanks all for your participation, and thanks to the speakers here today. With that, good luck, and thanks very much indeed. Bye, bye.

Bye, bye.