Thank you very much. And good morning to everyone on the phone and to those of you who are joining us via webcast. I'm joined here by Markus Krebber for the presentation on the first half of fiscal year 2019. As we already announced the upgrade of our full year guidance two weeks ago, today, we present the details of the figures for the first half. As with our previous presentations, we will concentrate on RWE stand-alone. So let me hand over to Markus.

Yes. Thank you, Gunhild, and a warm welcome to everyone. It has been a very good first half of fiscal 2019 for RWE on the back of an outstanding trading performance. This enabled us to raise the outlook for this year, and I can also confirm our target to pay a dividend of €0.80 per share for 2019. At the end of June, we completed the conversion of our preferred shares into common shares. We now only have a single share class, which is in line with international capital market standards. Ladies and gents, the transaction with E.ON is on the home straight. We are just awaiting the EU merger clearance for E.ON's part of the transaction and are hopeful that the European commission will provide it in September. We have continued to prepare for the closing of the Innogy transaction and are now very much looking forward to the integration of the renewables businesses into RWE. With regard to our existing conventional generation portfolio, we decided to close our Aberthaw hard coal power station in the U.K. at the end of March 2020. We will transfer the existing capacity market agreements for the next 2 delivery years to third parties and to a small extent to units within our own generation portfolio. With the shutdown of the plant, RWE will end power generation from coal in the U.K. and as we continue with our plan of reducing carbon emissions. When it comes to the German coal phase-out, in early July, the Minister of Economics, Mr. Altmaier, announced his plans for the implementation of the commission's recommendation. It is envisaged that a draft law for the phase out of hard coal generation will be introduced into the parliamentary process by autumn. After the conclusion of the discussions on the lignite phase-out with the operators, the results should be incorporated into the parliamentary process and the draft law. On this basis, there could be a coal phase-out law by the end of 2019. Let's turn to the development of our adjusted EBITDA. For RWE, stand-alone amounted to nearly €1.4 billion on the back of an outstanding trading performance and a strong gas and LNG business. Despite lower generation volumes, earnings at Lignite & Nuclear on a level with the previous year due to higher realized generation margins. Earnings of the European Power division suffered from lower production volumes and weak commercial asset optimization. Another reason is the suspension of the U.K. capacity market. Adjusted EBITDA includes the Innogy dividend of €700 million, which we have contractually agreed with E.ON. Slide 5 provides performance details of the Lignite & Nuclear division. Year-on-year, the production volumes came down, driven by the restrictions at the Hambach mine and outages, among other things. However, slightly higher generation margins have been realized and led to a solid earnings contribution. The H1 result was, therefore, as expected, on par to the previous year's level. The increase in depreciation is mainly influenced by the discount adjustments for nuclear provisions, which led to higher asset values for the operating plants, as well as changes from the application of IFRS 16. For the full year, we confirm the outlook for adjusted EBITDA of between €300 million and €400 million. The European Power division realized an adjusted EBITDA of €99 million. The weak earnings from commercial asset optimization, which we experienced in the first quarter also impacted the H1 performance of the segment. In addition, we continue to see lower production volumes and also lack €33 million of U.K. capacity payments compared to the first half of last year. We confirm the outlook for the full year, but expect, as already mentioned in Q1, to end at the bottom of the provided range. Now on to our current hedge position on Slide 7. The hedge price for outright generation in 2019 stayed flat as we are almost fully hedged. For the years 2020 and '21, we took advantage of improved fuel spreads and converted implicit fuel hedges into fully hedged positions. For '22, we continued our implicit fuel hedging and increased the position to more than 60%. Hedge power prices have improved for all three years. With hedge carbon prices increasing to a lesser extent, we see a positive effect on generation margins of €1 per megawatt hour for the years 2020 to 2022. On Page 8, you can see the development of fuel spreads until the end of H1 2019, which are relevant for our hedge prices you saw on the previous slide. The upward trend for the delivery years 2021 and '22 is clearly visible. Moving on to the earnings development of the Supply & Trading division on Slide 9. The segment had an excellent first half and contributed an exceptionally good EBITDA of €434 million. We saw an outstanding trading performance over all desks and a strong gas and LNG business. We have, therefore, adjusted our guidance for this division and expect earnings significantly above €300 million in fiscal 2019. Slide 10 provides the earnings drivers down to adjusted net income. Our adjusted net income amounted to €914 million in H1 2019. Besides the typical adjustment of the non-operating result and the corresponding tax position, we've many corrections in the financial results stemming from changes in discount rates for long-term provisions and the application of IFRS 9. In addition to deferred taxes, we had adjustment of provisions for tax and tax refunds for previous periods. Now on to our distributable cash flow on Slide 11. The distributable cash flow is also on a high level of €910 million, which is dominated by the following drivers. Firstly, the high adjusted EBITDA; and secondly, the positive effect in working capital due to its typical seasonal pattern. Although we typically see a negative change in working capital in the second half of the year, we still expect to end the year with a positive effect from the change in working capital. The line item changes in provisions is dominated by the transfer of CO2 certificates to the national clearing authorities in Q2, by which the utilization of the CO2 provisions is completed this year, whereas the additions and provisions run throughout the year. For the full year 2019, we confirm our expectation from March to reach a level of approximately minus €500 million in change in provisions and other non-cash items. For our British pound hybrid, we paid the full year coupon of some €60 million in Q1, which has been the last payment for this hybrid bond, as we called it in March. Moving on to the details on the development of net debt on Slide 12. At the end of June, net debt stood at nearly €4.7 billion, which is an increase of approximately €2.4 billion compared to the reported net debt at year-end 2018. Essentially, the increase is driven by an outflow of variation margins due to the realization of the underlying transactions for which we had received variation margins in previous years, especially last year. In addition, the call of the British pound hybrid increased our net debt, as we did not refinance it with another hybrid and consequently lost the equity credit. Furthermore, net debt was driven by our dividend payment in May and an increase in provisions following the further decrease in discount rates. Finally, this brings me to our RWE stand-alone outlook for 2019 on Slide 13. As already mentioned at the beginning of my presentation, we have raised the outlook for fiscal 2019. We expect adjusted EBITDA to end between €1.4 billion to €1.7 billion and adjusted net income to reach between €500 million and €800 million. When it comes to the dividend, let me -- let me remind you that we have always said, we would smooth any short-term volatility of the trading business. We, therefore, confirm our target to pay a dividend of €0.80 for fiscal 2019. With this, I conclude my remarks, and I'm now happy to take all your questions.

Operator, could we have the first question, please?

Certainly. The first question comes from the line of Ahmed Farman from Jefferies.

Markus, I just wanted to start with the net debt. I think in the past, you talked us through, very helpfully through the sort of the various moving parts of the sort of the variation margin sort of what is linked to the settlement of contracts and commodity prices. I'm just wondering if we could have an update on that given sort of the movement we have seen in the second quarter? And also, given sort of the commodity price movements so far in the third quarter, could you talk a little bit about if you see any further inflows relating to the variation margin?

Yes, Ahmed, thanks for the question. I mean what we have seen until the end of Q2 is especially the reversal of variation models where we have seen the settlement of the transactions. And there was a negative market price effect in Q1 and a positive one in Q2. So the debt is leveled out now. So if commodity prices stay more or less on end of Q2's level, we would expect the net debt to end around the level we currently see, the 4.7 billion, maybe a bit lower. In Q3, so far, price movements are more or less flat. So we have not seen significant effect until yesterday on the variation margin side, but that is, as you know, very volatile, so that remains to be seen how that evolves over time. Does that answer your question?

Yes. Just one very quick clarification. I think, in the first half -- sorry, in the first quarter, I think the commodity price element was -- I think it was around 1.9 billion. So has that largely reversed? Is that sort of the movement sort of that basically explains the second quarter inflow in this item?

Yes. I mean if you take the delta between Q1 and Q2 footnotes on this slide, you see a significant inflow of variation margins in Q2. Yes. So that the net effect which remains is more or less realization of the commodity position for the first half of the year, which is equal to what we expect for the full year.

The next question comes from the line of Alberto Gandolfi from Goldman Sachs International.

Two questions on my side. The first one is, a little bit come back, Markus, on the comments you made on the phase-out, you talked about the draft law in autumn and even potentially a law by year-end. Now are we of the view now that the law has to be coupled with a compensation agreement in principle also with the operators? Or are we still of the idea that the two processes are separate? The law will talk about the phase-out schedule and then the discussion on compensation will conclude after that. So I was just trying to see, and if you had any change of heart in your initial estimates that you had put out there? I thought it was €1.4 billion, €1.5 billion per gigawatt or whatever is closed quite early on. And the second question is a little bit more on offshore. I mean we are seeing that E.ON started to talk about reporting under the new perimeter for Q4, that's getting exciting. We're getting there. And as you said, the home straight. And I was trying to understand a little bit more your offshore strategy. You were just awarded Dunkirk in a consortium. You are now the second largest offshore developer. Of the 2- to 3-gigawatt gross additions that you are targeting, how much do you think it could be offshore because we are starting to go from annual auctions of 5 gigawatts to 10 gigawatts, and we are heading towards 15, 20 per year. So I was wondering if there is a market share idea in your mind of how much you can obtain.

Alberto, thanks for the questions. The first one on coal exit. First of all, nothing has changed from what we have said previously. So from the discussions we are in, we have not any news we can share. So everything we have said so far is still valid. And how does it now work with the potential contractors, operators or agreement on compensation and the law? What Mr. Altmaier, the Minister of Economics, said is, they want to introduce after the summer break, first, legislation for the hard coal exit because there no agreement is needed because they want to run option processes. And in parallel, they want to find agreement with the operators of lignite. I mean we are actually only talking about two relevant operators here. And then when that agreement has been achieved, to introduce that also or to phase it into the legislatory process, which is already ongoing for hard coal, that by the end of the year both is done. But what we don't expect that we first see legislation on lignite phase-out and then contractual negotiation, that wouldn't work. On the nuclear side, it was also the opposite. First, agreement with the operators and a draft version, then legislation, then signing of the contract. And our view is the process, which is currently underway looks the same for lignite. Coming to the question on compensation, you repeated the numbers we have put out. I mean that is -- was our starting position as a negotiation, and we now have to distinguish also that potentially the effects for the layoffs for the staff side will be dealt by the government directly; that, that money will not be channeled through the companies, but they deal with compensation payment for the workers directly. Of course, that needs to be deducted what goes to us, but to reconfirm, what we expect in terms of compensation and what we think is adequate, our position, our view has not changed over the last month. Your second question on offshore. I mean please understand that full details of what we -- what kind of countries, what kind of market share, how much investments over the next three to five years we actually want to do in offshore will be presented at the Capital Market Days after we have seen the open books of both portfolios, also the development pipeline. But in general, I can confirm that offshore plays a very relevant role in our renewable strategy. So you know that there are ongoing options or options ahead of us, where the portfolios can participate. And to the extent legally allowed, we also know that both companies are very active in development activities, but you have to wait before we can finally confirm and talk about numbers, countries, market shares until the Capital Markets Day in March.

Markus, it's very clear. So allow me to understand. You think compensation discussion even with the operators will proceed legislation and you're saying that what's your degree of certainty on the fact that the workers' compensation will be just effectively dealt with by the states because this is quite big, it's one of your biggest costs?

Yes, it's right. Yes. We probably are -- I mean we are confident that because that is the recommendation of the commission and that is also how, let's say, the structure of the discussions and who talks about what is set up that we expect that the workers side is dealt by the government directly, so not channeling the money through the companies.

The next question comes from the line of Peter Bisztyga from Bank of America Merrill Lynch.

A couple of questions from me. Just staying on the subject of coal exits and discussions, I think Altmaier was on the tape a few weeks ago saying that the discussions were far advanced and constructive. So I was just wondering if you could sort of confirm that sentiment from your perspective? And in addition, can you just sort of remind me whether these discussions includes conversations around the Hambach mine and do your expectations of €1.6 million, €1.5 million per megawatt includes Hambach? So that's all sort of rolled into one question on coal exit for me. And then the second one was just around second close. Can you just remind us what the status is, vis-à-vis E.ON transferring Innogy's renewable assets to you because I seem to remember that, that is somewhat contingent on E.ON getting a domination agreement in place. And I was just wondering what the status of that was and whether there's any risk of delays on that front?

Yes, Peter, thank you for your question. I mean first of all, I would never publicly oppose a statement which was made by one of our ministers. So I cannot, of course, confirm what Mr. Altmaier said about the discussions we are in. The other element of your question, I mean, of course, the discussions also include -- they include all recommendations of the commission, so also the entire topic around Hambach. And the number we have put out is not 1.2 million to 1.4 million absolute, but 1.2 million to 1.5 million -- 1.2 million to 1.5 million per, to be close, gigawatt, and that includes everything, so also the consequences for the mine and the workers. The second question to the closing. I mean currently, the plan is that we get merger clearance in September. We are very confident as E.ON is -- that, that can be -- that we get that. And then we see closing within a couple of days and maybe 1, 2 weeks later that the E.ON renewables business is legally transferred to RWE, and we are currently working together with E.ON that we get also the second step. So the assets which have to be moved from Innogy to RWE, so the renewables business, Kelag and the gas storages until the end of the year. So we stick to our old timetable. And we are currently working on how we can actually manage the business when it is legally organized in two companies because there are no merger clearance restrictions. So there's more we can do together. Of course, minority shareholder rights at Innogy needs to be taken care of. And you can expect that we can give you more color on how we actually run it in a more coordinated fashion around closing.

And maybe just -- sorry, Peter. Just one word on the accounting from closing 1 onwards, you will see E.ON's renewables business in our accounts from that point onwards and Energy's assets, which come back to us, will remain in our accounts.

But there's -- just to be clear, there's no sort of risk of second part of the second close stalling or not happening because E.ON -- because of the E.ON strategy towards Innogy?

You mean a risk that E.ON decides differently and doesn't want to move the Innogy assets to us. Let me -- I mean we are very confident that we have taken care of the clear incentive scheme for E.ON contractually to move the assets over to us.

The next question comes from the line of Sam Arie from UBS. Please go ahead.

I think at this point, we've covered a lot of the topics that we would have questions on, but one we haven't covered is carbon and your hedging. And so I wonder if we could just get a bit more color from you on how you're seeing the impact of the current carbon price on operations. So obviously, what will happen in another sort of 10 years or so from the start of the year? And then on the other hand, you're showing spreads at a pretty good level now. So where we are in the process, and if that looks good, but obviously, then you said you're closing Aberthaw and the rest of Europe we hear is very hard for thermal coal to -- hard coal to run at the moment. So can you just kind of help us understand exactly what impact the carbon price at the current level is having? What you're seeing and how we should think about that going forward?

Yes, that has a couple of elements. Let's start with our hedging strategy on the carbon side, that has not changed. So the view that we should be commercially protected against higher carbon prices because of to-be-expected tightening carbon markets when market stability reserve is fully introduced is still valid. So we keep our carbon position. And as we have said earlier, we are under the current production assumptions, pre-implementation of the coal commission's recommendations, we are hedged until '25. So if you take that into consideration, we are either over hedged or we are even longer hedged, but we can only give clarity after we have agreement with the government what exactly we close at which point in time. But this position is still there, and you can already see that in action when you look at the hedged spread of '21 and '22 because since we have our long-term carbon hedge in place, we were able to benefit from rising power prices and margins even in a period of rising carbon prices. And that is then also valid for the years after '22. What effect does it have on operations? I mean the situation in the U.K. is a bit different because you add another couple of pounds to the carbon price. And of course, there is a clear goal of the U.K. government to phase out coal by '25. And now with the suspended capacity market payment and the plant not making a lot of money anyhow, it was a clear de-risking exercise to now take the decision to close it much earlier. I would not see a direct connection to carbon price developments in the last quarters. And then the last aspect, I mean, of course, you can hedge your margin, but operations are always run at current market prices here. Of course, we have seen significant fuel switching in the summer this year. If you look at current forward prices for the winter, we should expect lower fuel switching. But that in the end will depend on spot prices when we actually operate in winter. And of course, we cannot rule out that we see higher carbon prices to achieve the full fuel switching in winter again. But commercially, we are protected against it.

That's fine, Sam?

Yes, very helpful, very helpful. And one thing, Gunhild, I wonder if you'd allow me to add. It's not a question as such. But since we have you and we're at the end of results season, I just wanted to make one comment, which is I feel that the format you guys have settled on for your slides and updates is now very, very clear and helpful. I think it's one of the best of all the companies formats of all the companies we use, and I know that you'll be updating that next year with the new shape of the business. And I just encourage you to, as far as possible, keep with a very clear and helpful update format that you have developed recently through the...

Sam, now I have to be a bit cautious about the outlook of the year because Investor Relations team now will expect a higher bonus.

No. I actually wanted to say, Markus will now ask me if I paid you to say that. But thank you, Sam. That's very much appreciated. And we will try to keep it up.

The next question comes from the line of John Musk from RBC.

I just wanted to come back on the net debt and the variation margin, just to understand how that's going to move going forward. So, I believe you're saying that it's the balance, which is around €2.5 billion should be broadly the same for the rest of the year, there shouldn't be any change to that. But how quickly will that variation margin outflow in a constant quality environment into 2020? And then secondly, on the dividend, if we think about the benefit that you got from the better result in Supply & Trading and the increased guidance, seems that the net debt potentially is trending better as well. And then whilst you say you want to keep things smooth, we do see a consensus earnings for next year under the new structure well above €2. So could we see some positive movement in that dividend number when we get to year-end?

John, first, on the net debt side, your question how the €2.5 billion variation balance will phase out, I would say, roughly with stable commodity prices, around half of it will be phased out in the liquid period from the hedges we have for the next three years. And the other half is more related to the longer positions we have. So if prices stay stable, that will flow out over, let's say, the next seven years, something. On the dividend side, I mean you should not expect that we, if things evolve how we have predicted it now with updated guidance that you're going to see a movement on the €0.80 dividend. I mean that is something we should not expect. On the other side, what we do with the dividend under the new setup also depends on how confident we are with our investment plans in the renewables business. And there, we will give you the full picture and not only part of it, but the full picture in March.

The next question comes from the line of Elchin Mammadov from Bloomberg Intelligence.

I have two questions, please. The first one on the offshore wind. I mean some of your peers like EDPR and Engie formed the joint venture. Is it something that you've considered at all? And the second one is more on subsidy-free renewables, I mean we've seen some record low prices in Portugal, albeit in solar. Is it something that you are expecting to be more prevalent in the future? And if so, are you comfortable with building subsidy-free renewables or you will only get -- go for auction?

Yes, thanks for the question. The first one on offshore, I just have to say the same I already said before. Of course, I wouldn't rule out anything strategically, but further update at the Capital Markets Day. I'm not talking about it before in-depth discussion with the future management team and also a view of the development pipeline and their strategic thinking so far, which cannot be shared currently with us since we don't have merger clearance yet for the full transaction. On the subsidy-free renewables, I think we need to dig a bit deeper, what we mean by, what I mean. What is subsidy-free renewables? I think most renewables are already today competitive in the market. So it's not so much the question of subsidies. It's a question of what is the remuneration framework, and there you can have, of course, feed-in tariffs, which gives you a very high certainty. You can also do other things like PPAs or hedging. PPAs, of course, come with higher credit risk, which has to be taken care of. So I will never talk about subsidy, subsidy free, it's more the question of the remuneration scheme. And there depends market-by-market. I think in a world where we can expect that renewables will more or less produce most, and someday all of the energy, we need to think about market dynamics. And of course, since marginal costs are €0, when you take a financial investment decision on a renewable project, you want to ensure that you get your money back. So some kind of remuneration framework needs to be in place if you have a very high certainty to get it back and doing that only on market prices so to keep the position, how we would call it in today's market, merchant, totally open without PPA or feed-in tariffs. I see that as very difficult. But that doesn't mean that you need subsidies. Was that clear?

Yes, it was. I was more talking about PPAs. Yes. So yes. So yes, it looks like you're comfortable in some cases, but not fully merchant, maybe.

That's fully merchant. But I mean you can also have a project with good PPAs, which is then without any government -- direct government payment. But it depends whether you get the PPA and what is the incentive of people signing PPA because in wholesale market -- in very liquid wholesale market, the only reason to sign a PPA other than showing that you source green energy is you expect higher prices, but that can only be there for an interim period. So we need to see how markets evolve. And I actually expect over the next decade, one of the most interesting discussions is about future market framework for renewables and firm capacity in the market because I think that will change over time.

The next question comes from the line of Vincent Ayral from JPMorgan. Please go ahead.

So as Sam said, a number of my subjects has been touched upon. Just want to clarify, so net debt, you say end of the year were at 4.7 million and on the variation margin reversal you still expect in H2. I just want to be sure I got that right. I would have a question then on the CO2. We see that your hedging for 2022, I think, moved to 16, if I recall. I wanted to understand what is your cash cost and economic cost on the lignite fleet, as we don't have an EBITDA or an EBIT on such a level of granularity, that would be very useful, especially as negotiations are ongoing into and fall over months to come.

Thanks for the question. If commodity prices stay stable, we would expect a net debt at year-end which is a bit lower than the current level of 4.7 million. So more or less, where also market consensus is, which I think is currently around 4.3 million, we feel comfortable with that view. On the other question, CO2 and lignite profitability, so what we have -- the information we have given, I think, two years ago is still valid that the full cash cost of lignite at €22 per megawatt hour excluding carbon so -- and full cash cost means operations of the mine, the power plant and also -- not only OpEx but also CapEx. These are the full cash costs. So when you say €22 plus extra spot carbon prices, you'll see what we need to achieve as a hedged margin to be cash neutral on our lignite fleet.

And for the economic one?

What is that?

That's for the cash cost and the economy costs basically accounting for D&A and return of capital.

I'm not sure whether I get it. I mean, of course, accounting costs then depend on how you depreciate your CapEx. I mean in terms of economic assessment, the cash view is irrelevant. I mean I would say -- I mean given -- knowing the depreciation profile and the future CapEx profile, I would say the economic costs are a bit higher because we depreciate more than we invest. But actually, it's not that relevant.

The next question comes from the line of Deepa Venkateswaran from Bernstein.

I had 2 questions. One is on the lignite negotiations. Would you be able to talk about what is the time line after the draft law? I suppose there's still stated clearance needed from the European Commission. So perhaps, when is it that you would have the final law, the final contract signed if this time line proceeds? And do you sort of see any risk in case there's early elections in Germany early next year? And the second question is on the net debt, but more the future-looking net debt position for RWE. Would you be able to comment on where you see sort of the lockbox position land by the end of '19? I think my early assessment is it's around €800 million there. And there's debt of around €3.1 billion moving also from E.ON Innogy to you and then the €1.5 billion. So net-net, maybe around €5.4 billion. So any comments you can have on my numbers would be great.

Yes. Thanks, Deepa. So on the time line, I mean even if everything goes as the minister envisage to do it, I would think that we have final agreement next year. So it will definitely take until Q1, maybe Q2 next year, until everything is done and dusted. But in terms of the relevant economic consequences for the company, we can be optimistic that we probably know that by the end of the year already. And in terms of election, I mean it's a process issue. It's more a process issue than a content issue. I mean regardless how the German government will look like, I mean all relevant players have confirmed when it comes to coal exit, they're going to stick to the recommendations of the commission. But of course, you have a delay because the new government needs to be formed and so on. But currently, it doesn't look like that. So we are optimistic to conclude the discussions with the current government. On the net debt side, if you disregard potential movements from variation margins. So if we take a stable commodity price environment, we would expect at the end of this year that net debt after the transaction is executed is a bit lower than €10 billion, something €9 billion to €9.5 billion, so a bit lower than your number. Because if I add up your number to the current €4.3 billion, €4.7 billion, it is closer to €10 billion. I would expect something around €9 billion, €9.5 billion, of course, depending on interest rate movements and variation models. If we keep that stable, it's around €9.5 billion.

The next question comes from the line of Sofia Savvantidou from Exane.

Two from me as well. One just on the coal exit. Since it looks now that hard coal will be discussed a bit earlier, at least finalized a bit earlier for the auctions, I was wondering if you have any views on Datteln and sort of your contractual relationships there with Uniper? Uniper were saying at their own call that they haven't received any indications that they should stop the construction of the plant. So -- any views from your side on the outcome there? And the second thing is on your -- on your forward hedging, just with regards to your implicit fuel hedging, as I have understood it, you are making certain assumptions about the pass-through rate of coal, gas and CO2, which are, obviously, constantly shrinking given movements in the merit order. Given what has happened with CO2 and what you told us earlier about sort of fuel switching in the summer and in the winter, I was just wondering how you have sort of changed, if at all, your views on how you do your implicit fuel hedge? And therefore, with regards to the chart that you usually show us, the one on Page 8, whether sort of this assumes a steady percentage for gas setting the price and coal setting the price or whether sort of you have changed that in terms of how you look at it?

Yes. Thanks, Sofia, for the questions. First one on Datteln, it's an easy answer. We are not involved in any discussions around Datteln. So it's currently, if at all, we have no inside discussion between the government and Uniper. So we are not part of that. So we don't have any information. On -- and -- but you are right, as it currently looks like the government wants to deal with the hard coal exit earlier than finding agreement on lignite closures. On the hedging side, how it works. So the implicit -- the determination of our -- in the money position and also what we do on the implicit fuel hedge side, so how much is coal, how much is gas, how much is outright position is adjusted daily. So it is always recalculated on a daily basis and position changes daily and also assumptions here. And I mean that is purely based on the forward commodity price curve. How we actually run the implicit fuel hedge in terms of decision making? It has two phases. The first one is, do we actually want to enter into implicit fuel hedge, which means that we more or less take out the outright risk. So going short coal and gas, and of course, buying CO2. And that has an element of risk appetite, but also what is our view on the overall commodity price environment and how healthy are the locked-in outright spreads. The second question is then -- and then we have secured more or less the -- we have transformed the outright risk into a spread position. The second decision-making point is then when do we transfer the spread position into a full hedge. And as you can see, we have done that to a significant extent in '20 and '21, and that is an indication where we're sensing that the spread levels are healthy. For '22, we enter into implicit fuel hedging, so keep the spread level open.

We have a further question from the line of Peter Bisztyga from Bank of America Merrill Lynch.

I just had a couple of follow-ups, please. One, just on the net debt and the €9 billion to €9.5 billion range you sort of said for pro forma end of this year. Can you just sort of clarify what the assumption about locked box is in that? I don't think you answered that aspect of that? And then the second one, actually, just on the performance of your trading division in the first half, I was wondering if you could be a little bit more explicit about why it was so good and why you're so confident that it's not going to get messed up by somebody in Q4?

I like the last question. I mean I could, of course, tell you we have proper risk management in place, but we also had the experience of 2016, where we had a very good quarter and then a disastrous one in Q2, but we have learned our lesson there. And of course, we know how the -- how the performance is so far in Q3, which is more ordinary course of business. But we are confident that we keep the current level until year-end with some little volatility. I think the traders want to keep the current level and don't lose on their bonus payments by messing up the last quarter that is typically also an element of -- a dynamic element where typically the behavior at the end of the year is different than the beginning of the year. On the first question, net debt, yes, I was not explicit on the assumption on the lockbox because that also clearly depends on at what point in time do we actually execute and calculate the lockbox. Currently there, especially on the energy side, are significant investments going on in Triton Knoll. And I think it doesn't make so much sense to calculate what is actually -- at that point in time, do we get the money or do we have to pay more -- do we have to pay more for the investments through the lockbox or then later ourself that doesn't actually make a huge difference, whether it's coming through the lockbox or not. So the current assumption is there that it's plus or minus zero. So if we pay the 1.5 billion to E.ON, we take over around 2.8 billion in debt for provisions and so on. And then we have an effect from the renewables business of 0.5 billion of IFRS 16. That is what I would add to our current net debt level of 4 point -- around 4.5 billion.

And that 2.8 billion on the provisions hasn't changed in your view despite the sort of movements in discount rates that we've seen?

It has. I mean most of it is decommissioning liabilities for wind. And that usually doesn't move so much. It might have moved a bit.

We have a further question from the line of Ahmed Farman from Jefferies. Please go ahead.

Just one question, Markus. The sort of the 9 billion to 9.5 billion indication that you sort of mentioned, presumably, that doesn't include any impact on the lignite mining provisions from with any reach that you'd reach with the government. I just wanted to, a, confirm that; and b, is it something you could sort of help us think through as to what could be the impact given sort of the proposals and the discussions you're having with the government?

Yes. Thanks for clarifying that. That is right. I mean the net debt is without any potential impact from the coal exit in Germany. We have said previously that following the recommendation of the commission, we expect to be compensated for additional costs, be it on the restructuring side or for additional recultivation on the mining side. So that should be a net zero. Of course, if for whatever reason we see accounting effects because we have to apply lower discount rates since duration goes down, cash outcome earlier and we have less discounting effect, this pure accounting effect could add up to maybe €0.5 billion to €1 billion, where we should not expect compensation.

We have another further question from the line of Deepa Venkateswaran.

Sorry to come back on the net debt and the lockbox. So I think, in answer to Peter's question, you mentioned that you assume lockboxes more or less 0. I come to the same conclusion for '18 that it's more or less 0, but for '19, given the significant spend both at E.ON and Innogy and Knoll, particular farm down, I would see that it is actually a negative. And of course, I'm assuming that the lockbox will settle at the end of '19. Just to work backwards from the stand-alone debt of both Innogy and E.ON, just to make sure that so I was just wondering whether there's anything else that I'm missing? Because clearly, the Innogy, I think, when I spoke to IR recently are indicating that renewable CapEx might even be a bit higher than what we had assumed at the beginning of the year. So I was just wondering whether I'm missing anything on why for '19, generally, the renewables divisions would not be a net negative for Innogy and E.ON, and therefore, payment from you to them?

Deepa, I don't know what your assumption I mean we have seen the Triton Knoll farm now, which is part of the lockbox as well. So this is a big compensation for part of the CapEx. And the other one is on the nuclear side. We have agreed to calculate the money we get for the produced volumes on a spot basis. So unhedged. And of course, market price movements are very favorable. And I mean in the end, it is a question of timing. But if we close a lockbox for, let's say, the E.ON renewables business by the end of September this year and the Innogy one by the end of this year, I would overall not expect negative lockbox payment.

you talk about the nuclear? I think you went through that quite quickly. I didn't quite follow exactly what you said on the nuclear.

I mean we also get part of the lockbox. It's not only the results from the renewables business, but also the money from the nuclear minorities we take back from E.ON, so the respective production volumes. And that is also, I think, a low 3 million digit number. And that is much more favorable than when we signed the transaction because the agreement was to calculate that based on daily spot prices, and given the significant rise in carbon prices, the carbon-free outright position of nuclear made a lot of more money than initially anticipated.

Thank you, Deepa. If there are -- are there any more questions?

There are currently no further questions in the queue. [Operator Instructions]. Okay. The next question comes from the line of Ingo Becker from Kepler Cheuvreux. Please go ahead.

Two questions on lignite. First, given the very high carbon price, if you would remove your hedge position for a second. Am I right that the fleet currently is cash loss making? And could you indicate at the current carbon price, what broadly levels that would be? And on your hedge position, if we assume an early closure of part of your fleet, do I understand you right that part of this variation margin inflow, the net inflow that you still have on the books, you in that case could keep part of that, and that would actually transform into a gain rather than in the end, up and unwinding of the transaction, a rather neutral position?

Yes. Thanks for the question, Ingo. I'm not sure whether I got the second one. I'd give it a try. The first one is, I mean calculating lignite on daily spot prices is, I think, not worth doing because the position is typically hedged. So in order to assess the profitability of the lignite fleet, also under the current high CO2 environment, I would look at the forward curve because that is how we can hedge it. And knowing that our full cash costs are €22, and the carbon prices currently are around €27, you know that we need prices of €49 to be profitable. And when I look at the forward curve, it's still above €49. So I don't see the point that it is loss making. Of course, you can pick an individual week in summer, where it is different, but that economically doesn't matter because it's hedged and it's level out through the year, it's also different scenarios in winter. And the second question, I actually didn't get because I mean when we take -- when we -- the hedge position will never be affected by any agreement with the government. And on the cash side, the money is already -- I mean from rising CO2 price is already in the account. And on the P&L side, it depends where we allocate the hedges. So of course, you can always take the view that you say, I don't allocate them, I take them out of hedge accounting, that it's freeze, that it's frozen, and you need to wait until -- or you can reallocate them to maybe later years because you want to change your hedge profile. So -- but that is economically also not so much relevant, right? I mean relevant is what was the position, what is the mark-to-market the money is in the account.

The reversal is not actually that we lose the money, it's just we have booked it earlier in our cash flow. And in the P&L, it comes later. So we don't double count the money coming in twice.

Can I just inquire the €22 breakeven? I think at the time you said this, this was valued at an €80 a tonne carbon price, but you think in this environment, this is still the number to work with?

To clarify what we said, we said the full cash cost, excluding carbon at €22. So that is totally unrelated to the carbon price. You need to add the -- the extra carbon price to the €22. And then you see what power price level we need to be cash neutral.

Are there more questions?

There are currently no further questions in the queue [Operator instructions]. The next question comes from the line of Tanja Markloff from Commerzbank.

I have one question, completely different. It's on the nuclear spare volumes that you have that are available for you to sell. Could you give us an idea when you will probably be able to let us know how much additional profit you could make with selling these volumes?

Yes, Tanja, it depends on whether we find agreement with other market participants to sell the volumes or whether we have to wait until we hand them finally in for compensation by the government, which will happen after 2022 -- sorry, in '23. If we cannot sell them to any competitor, we expect the money to come '23, and we always said, it's a medium 3-digit million number. And of course, if we can sell them to competitors earlier, we will book the profits earlier. But that depends on also the dynamics between E.ON and Vattenfall, which you can also follow through recent statements from both companies.

There are no questions in the queue currently [Operator Instructions].

I think we will keep it that way. And if there are any further follow-up questions, then everybody knows where we are reachable. And we are, of course, at your disposal to answer them. So therefore, I would close the call. Thank you, everybody, for joining, and enjoy the rest of your summer, and we will be on the road from September onwards again.