Gunhild Grieve - Head of Investor Relations Markus Krebber - Chief Financial Officer and Member of Executive Board

Alberto Gandolfi - Goldman Sachs Vincent Gilles - Credit Suisse Deepa Venkateswaran - Sanford C. Bernstein Peter Bisztyga - Bank of America Merrill Lynch John Musk - RBC Capital Markets Ahmed Bilal Farman - Jefferies Group LLC Javier Garrido - JPMorgan Chase & Co. Sofia Savvantidou - Exane BNP Paribas SA Samuel Arie - UBS Investment Bank Lueder Schumacher - Société Générale José López - Millennium Management Nick Ashworth - Morgan Stanley Oscar Najar Rios - Santander

Dear ladies and gentlemen, welcome to the RWE Conference Call. Markus Krebber, CFO of RWE AG will inform you about the developments in the first half of fiscal 2018. I will now hand over to Gunhild Grieve. Please go ahead.

Thank you very much. Good morning to everyone on the phone and to those who are joining us via webcast. I am joined here by Markus for the presentation on the first half of fiscal year 2018. We continue to concentrate on RWE stand-alone figures, since they are relevant for our financial steering and are also not affected by any changes to the financial reporting until the agreed asset swap with E.ON closes. As always, in order to focus on your questions, we have kept it short. So let me hand over to Markus.

Yeah, thank you, Gunhild, and good morning, ladies and gentlemen. Our H1 figures show that we had a good first half of fiscal year 2018. Adjusted EBITDA came down by 21% as expected. Mainly due to lower realized generation margins and volumes. However, our trading activities showed a very strong performance in Q2. The operational performance in the first half year is in line with our expectations. Hence, we can confirm our full year outlook for RWE stand-alone. Following the planned asset swap with E.ON, the IFRS figures for the RWE group have to be adapted accordingly. Those activities, which will be transferred to E.ON in the long run are classified as discontinued operations. This primarily includes the grid and retail business of innogy. The outlook we gave in March has to be amended as well. The revised outlook only reflects the accounting driven adjustment and not any changes to our expectation for the operational performance. More at the end of my presentation. The execution of the transaction with E.ON is progressing well and as planned. In mid-July, we signed an agreement with innogy on a fair integration process and innogy's support for a swift implementation of the planned transaction. This includes in particular innogy's support in obtaining merger clearance and other regulatory approvals. Further, innogy will support the preparation of the transfer of innogy's renewables business to RWE. In this context, it will also be reviewed how the transfer of renewals businesses can be implemented as soon as possible after the transfer of RWE's stake in innogy to E.ON. All in all, the agreement is an important step and it should give additional impetus to the execution of the transaction. The planned transaction with E.ON was also the reason why the two rating agencies, Moody's and Fitch, had put us on credit watch, which is standard procedure for such a transaction. In the middle of May, Moody's concluded their analysis and confirmed our investment grade rating of Baa3 and restored the outlook to stable. Moody's based judgment on our conservative financial policy and expect that we will be in line with the relevant debt thresholds. We are optimistic of delivering on this expectation as we will improve our leverage factor with the transaction. The minority stake in E.ON provides us with additional financial flexibility. Let me remind you that Fitch rate us at BBB flat versus stable outlook. Here we are still on credit watch evolving. At the beginning of June, the German government nominated the members of commission, Growth, Structural Change and Employment. The commission is tasked to identify measures, which will close the gap to the 2020 climate goal as quickly as possible and ensure the achievement of the 2030 CO2 reduction targets. In addition to environmental targets the commission should also take into consideration security of supply affordability, as well as social aspects and the avoidance of structural disruptions. In addition, the commission shall develop a plan for the phase-out of coal-based power generation, detailing the necessary companion [ph] law, economic, social and structural measures. The commission held its first meeting on June 23 and is expected to present first proposals by the end of this year. We hope and expect that the commission will deal with the complex topics based on factual expertise and reach a consensus which will also provide planning certainty for the companies involved. The timeline however, the result are expected by the end of year, looks very ambitious. Let me now move into the result. Slide 4 shows the development of our adjusted EBITDA. For RWE stand-alone it amounted to €1.1 billion. The decline is mainly a result of lower realized margins and lower generation volumes. The adjusted EBITDA includes the innogy dividend of €683 million, which we received at the end of April. Slide 5 provides the performance details of Lignite & Nuclear. The earnings decline of roughly €200 million for adjusted EBITDA in the first 6 months is mainly driven by lower realized generation margins and volumes. Reduction in volumes is partly a result of the closure of our Gundremmingen B nuclear unit at the end of last year. Furthermore, we had more and longer planned outages compared to H1 2017. Looking at the outlook for the full year, we expect adjusted EBITDA to be between €350 million and €450 million. The European Power division realized an earnings decline of €26 million. Adjusted for non-recurring items, it nearly reached the level of H1 2017. The earnings decline from lower margins was offset by the income from the UK capacity market and operating cost improvements. For 2018 as a whole, we can confirm the outlook with an adjusted EBITDA contribution of €300 million to €400 million. This brings me to our current hedge position on Slide 7. Average hedge prices for our outright position in 2019 to 2021 stays flat compared to the level we reported in Q1. We have increased our hedge position slightly from 2020 and 2021 to 90% and 40% respectively by an increased implicit fuel hedge. Let me also remind you of our long-term carbon position, which we have financially hedged through to the end of 2022. In other words, the change in carbon prices should not affect our generation margins for the next five years. In anticipation of your questions, I can confirm that we have also already taken measures on our open carbon position for post-2022. But please understand that we will not provide any details on our position due to the sensitive nature of this information. On Page 8, you can see the development of fuel spreads until the end of June 2018, which are relevant for our hedge prices you saw in the previous slide. The graph looks slightly different to the previous one as we instead of average monthly figures, we now show end of month data to bring the graph in line with our hedged prices on the previous slide. Fuel spreads continued their Q1 decline in April and May before starting to recover strongly at the end of June. Let's move to the Supply & Trading division on Slide 9. We saw a good trading performance, which was driven by a very strong second quarter. While our gas and LNG business posted a good performance, it lagged beyond the very high result of last year. Besides that, we had a negative effect from value adjustment within our principal investment portfolio. For the full year, we confirm our earnings expectation for this division of between €100 million and €300 million. Ladies and gentlemen, Slide 10 provides the earnings drivers down to adjusted net income. Our adjusted net income amounted to €683 million in H1. Besides the typical adjustment for the non-operating result and the corresponding taxes, we have many corrections in the financial results driven by the mark-to-market valuation of securities and the new IFRS 9 rules. And now on to distributable cash flow on Slide 11. In the first six months of the year, distributable cash flow amounted to €829 million. This is disproportionately high and may not be extrapolated for the full year, mainly due to the inclusion of the full innogy dividend in H1 and the typical cyclical pattern of our operating working capital. With regard to the change in provisions and other non-cash items, I would like to point to the timing effect of CO2 provisions mentioned on the slide. It's a transfer of the CO2 certificate to the national clearing authorities in Q2. We have completed this year's utilization of provisions, whereas additions are only halfway through the year. For the year as a whole, we expect to be in line with our initial guidance of roughly €650 million. The change in working capital is partly driven by seasonally affected trade accounts payable and inventories, which are typically higher over the winter months. Typically, we see a negative working capital in H2. However, we expect to end this year with a positive balance. The details of the development of net debt are shown on Slide 12. At the end of June, net debt stood at €3.7 billion, approximately €0.8 billion lower than at the end of fiscal year 2017. This mainly results from a high inflow of variation margins in H1. They will revert once the derivatives are realized or commodity trends turn around. We expect this to mainly happen in 2019 and thereafter. Now on to our RWE stand-alone earnings outlook for 2018 on Slide 13. As already mentioned earlier, we can confirm our earnings outlook for the year as well as our target to pay a dividend of €0.70 for fiscal year 2018. This brings me to our outlook for the RWE Group after the change to the financial reporting. With innogy's grid and retail business classified as discontinued operations, and therefore, no longer accounted for in adjusted EBITDA, we have to adjust the outlook we provided in March 2018. We forecast adjusted EBITDA of continued operations to reach €1.5 billion to €1.8 billion, the comparable previous year's figure amount to €2.1 billion. Innogy's continuing activities, which are the renewables business, gas storage activities and KELAG, are expected to contribute an adjusted EBITDA of between €700 million and €800 million compared to €785 million in 2017. We see CapEx for the continuing operations of RWE to amount to €1.2 billion to €1.4 billion. We are stating loss CapEx here, so before proceeds from disposals of farm downs. Out of this approximately €0.8 billion to €1 billion is attributable to innogy's continuing activities and will be mainly spent on growth projects into renewables business. In conventional power beneration, we still expect CapEx of approximately €400 million, predominately for maintenance and modernization purposes. Furthermore, it includes small gross projects, for example, the conversion to biomass co-firing in the Netherlands. RWE Group net debt for continuing operations is expected to be moderately below the level as of June 30, 2018, of €5.4 billion. With this, I conclude my remarks, and we are now happy to take all your questions.

Thank you, Markus. Before we start the Q&A session, we just want to draw your attention to a slide pack we have put together on the pro forma combined renewables business. You can find it on our IR website, and we hope that this is going to answer the many questions we have received over the last few weeks. And with this, operator, could we please start the Q&A session?

Thank you. Ladies and gentlemen, we will now begin our question-and-answer session. [Operator Instructions] First question is from Alberto Gandolfi of Goldman Sachs. Your line is now open. Please go ahead.

Thank you and good morning, everyone. I'll stick to the two questions today. The first one is on renewables. Could you please comment on the Triton Knoll farm down? I know it's technically innogy. But considering you already own the economic interest, I was surprised not to see a price disclose. The Asian price is talking about £700 million, just for the right to participate in 40% of the projects. So I guess the question is, is this ballpark figure broadly okay, and should we think about it as a right to participate to the project? And how would you intend to redeploy capital in your pipeline? And the second question is about sensitivity to carbon. You were talking about being financially hedged until 2022 previously. Can perhaps I ask you a question in terms of where do you see the profitability of your combined cycle going in the next 2 to 3 years in terms of volumes and spread, if we go into a situation, whereby carbon goes to switching economics. So we're not even talking about the coal commission here. It's going to be coal shutting down, production and, perhaps, lignite being impacted too at least for your competitors out there in the market? Thank you.

Yeah, thanks, Alberto for the question. So first one on Triton Knoll, I'll probably have to disappoint you. I mean, I cannot give you more information than you have got from innogy yesterday. A general comment, I mean, we appreciate the farm down. I think it's a great project to do some diversification there, given also the size of the combined portfolio in UK. It's also favorable for the future combined business. But on the price, I cannot give you any additional information. Redeployment of capital is part of the strategic question. And, I mean, as we have said before, we will answer that after we had the intensive strategic discussion with the management teams. And that will probably not be disclosed to our future strategy in investment focused before closing one. On CO2, yes, you are right. I mean, we are financially hedged until 2022. So any movement of the carbon price should not affect the profitability of RWE. Of course, it does not mean that it changes profitability of the different technologies. And your question pointing regarding to CCGTs, so our expectation is that our continental CCGTs, I mean, in the UK the picture is already totally different. But our continental CCGTs should over the next year contribute more than it currently contributes, but that has many factors. One is probably the price constellation, so hard coal gas and coal, and spreads. But the other one is also tightening of the market with the ongoing nuclear exit, and also additional coal capacity leaving the market. So in a tighter system should make flexible generation more favorable for ancillary services, but also maybe load factor. So we expect an increased contribution from CCGT.

Thank you.

Thank you, Alberto. Next question, please.

The next question is from Vincent Gilles of Credit Suisse. Your line is open. Please go ahead.

Yeah, yes, thank you. Good morning, everyone [indiscernible]. Two questions, the first one is on Slide 7, on the hedging 2021, before there is no real surprise. And I do realize these numbers to the end of June. Therefore, the little uptick in power prices spread and change in assumptions have not taken place yet. But I would be interested to understand why you increased by 10%, not a very large number, but still not a small number. You're hedging and what we should be expecting - I guess, what I'm trying to get read to is, how long will it take before we see the impact of the current strength in power prices on this part of your business? Sorry, it's a long question. Second question, which is simpler, variation margins, the impact on the debt you flagged that we should not get too excited and it will be offset partly for the second half of the year - yes, second half of the year. Could you maybe develop a bit more what exactly is in these variation margins? And will it be a full offset? Will it be just a partial offset? Thank you very much.

Thanks for your question. On Page 7 we have increased the implicit fuel hedge also in 2021. I mean, this gives us till exposure to the upside of increasing spreads. And we have hedged against falling coal and gas prices. So what we actually did is at current hard coal and gas prices, we have sold fuels and we have bought CO2. Any upside in power prices stemming from tightening markets or anything like that would still benefit this implicit fuel hedge. And this is part of the risk management where we say, I mean, the exposure to fuel prices, absolute fuel price levels, we're going to hedge and take out over time, because we have no directional clear view on hard coal prices over the next 3 to 4 years. Now to your question, when do we see an uptick here in hedge prices, so where we currently still show the 29, which is unchanged to a quarter ago. We have two underlying effects here. I mean, as you can see that, the average blended price setting spread, which is shown on Page 8, was lower at the end of June than it has been on the end of March. So this was a negative factor on the hedge prices. But the position, which is still open, so the light blue one, not the shaded one but the light blue one, which will close over time, is now closed at the existing prices of 40 something. So even if spreads don't move, you should over time when we switch into the hedge position, see an increase in the 29. So maybe I just extend my answer, so whatever happen to spread 2021, we expect the hedge price will go up, because the blue one, which is not yet hedged will be hedged at much higher prices. And in 2022, we are convinced that the spreads are currently too low. And we're going to see a continuing recovery until at least - until delivery. As we keep our spread positions here open, we also expect their prices to increase. Your second question, variation margins. Let me put it this way, we don't want you to be overly excited. Of course, it is a positive development that net debt comes down, which also shows that the position we have on, which are now fully mark-to-market, were the right hedge decision, because otherwise we would see a negative mark-to-market. But you should not double count the effect, because we have now hedged our generation margin the outer years by implicit fuel hedging and also doing something more on the CO2 side. And that will, of course, materialize in EBITDA, but that is now already upfront in the bank cash-wise. You cannot double count, so it was a wise decision on hedging. But you cannot double count when it realizes in the EBITDA in the future years. But please, I mean, this is also sensitive information. I will give you not the exact split, which hedges and which commodities drove the inflow of variation margins.

Thank you.

Thank you. Next question, please.

The next question is from Deepa Venkateswaran of Bernstein. Your line is now open. Please go ahead.

Thank you. So two questions from my side, first one on - now, you've had some time to think about the new structure post the integration of renewables. So I was wondering if you could elaborate a little bit more on your thoughts on the capital structure and dividend policy for the new RWE? And second question is on nuclear compensation. I think in the interim report you mentioned that it's a medium-triple-digit amount. What form will this take? Is it you selling these volumes to, say, E.ON or is it getting the money from the government? Just some idea on when we should expect this, and - yeah.

Yeah, Deepa, thanks for that. Let me start with the easier one, where I don't have to disappoint you again, which is the second question, I mean, nuclear compensation. We are obliged by the law that we enter into serious discussions with our peers, which probably needs some additional production rights. We have done that. We are in the process of negotiating with them. If we can conclude a deal here, we probably see the result earlier. If we cannot find agreement, we have fulfilled our obligation and then we have to wait for the compensation from the government, which will but only happen in 2023, after the last plant has been shut down. But in either case, we expect a similar amount, which is now determined by the details of the law. And this is the stated mid-three-digit million amount, which is expected. On the new structure and dividend policy, I mean, of course, we have time. We are still discussing it. But given that we cannot share all the detailed plans with innogy and E.ON's renewals business already, because this is sensitive information, it is still an outside in-view of RWE on the details of their business. And please accept that we will only come out with all details when we had this discussion, and that cannot happen before closing one. But you can then shortly, after closing one expect us to present the full picture, including dividend policy investments and so on. Also the intention on the E.ON's take-rate [ph] is a relevant building block, when it comes to dividend policy and investment amount. On the debt side, I mean, we think that we feel confident with the net-debt-to-EBITDA ratio of between 2.5 and 3. It will still take some time with the rating agencies to sort out how this new RWE, with this - which is a new animal combining conventional generation and renewables, what the business risk profile exactly. And then, we're going to see whether we need to achieve the lower or the upper end or somewhere in the mid. But that is not the relevant question for us, because given the financial flexibility we have, we can manage it according to what is needed. But that's where we're going to position the company debt wise. We want a strong investment-grade rating, so we are fine with the BBB that we have from Fitch, and over time, we want to achieve the same with Moody's.

Thanks.

Thank you, Deepa. Next question, please.

The next question is from Peter Bisztyga, Bank of America Merrill Lynch. Your line is now open. Please go ahead.

Yeah, hi there. Two questions from me, please. Firstly, your guidance for Lignite & Nuclear for full year implies that the second half is going to have to be an awful lot better than the first half. So I was wondering if you can just explain the drivers behind that relative improvements. And then the second one, just going back to the renewables business, maybe you could just give us a flavor of how the cooperation agreement that you signed with innogy will allow you to sort of start steering the Renewables business today? For example, I think, you've already said there's going to be some provision [ph] fee to assist in financing new projects. So anything you can tell us there, just to help us understand how you're going to move renewables forward? Thank you.

Yes. Yeah, thanks, Peter, you are right. This is probably artificially, when it comes to cyclicality, but we actually expect a higher result in the second half of the year than in the first half for the Lignite & Nuclear segment. And the reason why this is now different than in previous years is the overhaul cycle, because we have seen significant planned outages in the first half of the year, and we have only very little ones in the second half of the year. And in the last year, it was the other way around on the lignite side. So we feel very comfortable with our guidance of €350 million to €450 million, which also implies that we need a better H2 than we have seen in the first half of the year. On renewables, I mean, to be very clear, we cannot interfere with steering the business. We talk about the independent companies until merger clearance. There is no coordination when it comes to business decision. These will be taken by innogy and E.ON on a stand-alone basis, but what we have agreed with innogy and also E.ON a couple of things. The first one is that we will now set up joint project organization to preplan the integration process, which also implies that innogy will start project carving out the renewables. And we will also look into our potential measures to transfer the renewables business as fast as possible after closing one. So what this means net-net is that probably the time between closing one and closing two, which we presented when we announced the transaction, can be shortened. It's not yet determined, but we are together working on a solution to that. And on the financing side, we said probably if innogy for their financing needs some additional money and intend to farm down projects we probably want to keep, they will now approach us and discuss whether we are interested in providing a bridge equity finance, so that they don't need to farm down projects we want to keep. So there is kind of a process about the future business scope and that is also, I think, very helpful. These are the areas where we have seen improvements over the last two, three months where have now agreement how to progress jointly.

Great. Thank you very much.

Thank you, Peter. Next question, please.

The next question is from John Musk of RBC. Your line is now open. Please go ahead.

Yeah. Good morning, everyone. Two questions as well. Firstly, just looking at the distributable cash flow, which I know was higher due to some of the working capital, et cetera, but even so it's at nearly 2 times the level required to pay out the €0.70 dividend for the full year. So how much of it should we expect to reverse in the second half? And is there potentially some upward pressure to that dividend guidance? And then secondly, on your hedging slide, I note it's only a small reduction, but in the outer years you reduced your volume expected from the outright production from 85 to 80 down to just 80. And is that due to any assumptions you're already making around the coal commission? Or is that just general market trends?

Yeah. Thanks, John, for the questions. Let me start with the latter one. Yeah, we have already given the guidance and now we think it's definitely more at the lower end of the guidance, so around the 80 terawatt hours and not in the mid-range. We decided to make that assumption also transparent to you. There is no specific driver behind it. So it's not that prices are different and the money production has significantly changed. We also don't have new assumptions on potential outcome of the coal commission in the earlier years. It's more that we are now more confident that we're going to see more at the lower end of the given guidance and that we decided to put only 80 here. Profitability wise, it will not have any significant impact. On the distributable cash flow, yeah, I mean, I agree. We are happy that we see a very strong contributable cash flow. If you go to the different line items, I mean, you know the EBITDA guidance we have given, I made in my speech clear that we expect change in provisions and other noncash items, a full year figure of around €650 million. CapEx guidance is around €400 million and change in operating working capital - I mean, over a longer period of time that should be fluctuating around 0, since we have seen significant negative effect last year, driven by two elements. One was phasing out of working capital element and another one was a very mild winter and higher than usual gas storage inventories. And this should definitely revert this year. So we expect a €3 million digit lower positive effect in the working capital for the full year. And the other one, I mean, cash interest is not relevant in hybrids are already the full year effect here in the slide. So as we definitely expect a very strong distributable cash flow. What that means for dividend? We're going to decide at the end of the year when we also have clarity about how that going to look like next year and then we guide the dividend for the following years. But yes, it's a positive development.

Okay. Thank you.

Thank you, John. Next question, please.

The next question is from Ahmed Farman of Jefferies. Your line is now open. Please go ahead.

Yeah, good morning, everyone. So first question on Slide 6. I think that you earlier suggested like for like, you have a flat EBIT. But if I look at cash contribution, it's quite a significant step down. I mean, could you, perhaps, talk about what is driving the jump in CapEx and even free CapEx the reduction cash contribution? And then the second question I have is on your output and load factors and output in coal and gas. If I look through your first half results, I see quite a significant decline in coal output 25% year-on-year. Gas is also down 13%. Is that largely due to underlying trends or are there any phasing effects? And if it is really down to underlying trends, how does this fit with your view of higher contribution from spread generation and recovery in spreads? Thank you.

Yes. Thanks for the question. First one on European Power at Slide 6. I mean, the CapEx is still a very low - it's a very moderate figure. We have seen a very low CapEx last year, given also the overall cycle. So the €67 million is more in line with our guidance for the full year, but we expect CapEx to be around €200 million, it was artificially low last year. Other than that, there are no specifics. I mean, cash contribution is adjusted EBITDA and CapEx. What we have seen last year is one-off effect from the sale of property in the UK, which amounted to €20 million, €25 million. And - yeah, maybe one thing to highlight on this segment, especially development in the UK from the to-be-expected capacity payments, we have seen one-third in the first half of the year whereby two-third will be paid in the second half of the year. But that is also reflected already in the full year guidance of €300 million to €400 million. On the load factors and the production, I mean, on coal what is important to keep in mind that coal production, if you look into the detailed regional split, has especially come down in the UK, and that was because we transferred Aberthaw into kind of a reserve, it is not actively producing this year. That was significant one, and another one was in Germany where we closed the hard coal plant further together with Stayak [ph], so it's an already announced closure. The general load factors on the hard coal plants, which are still running, have not changed. On gas, it is different. In gas, we have seen last year, especially the fact where we had two, three weeks of no wind, no sun and our existing conventional generation was producing significantly more. That has not been repeated this winter. But we don't see any structural change in trends or anything. So it's business as usual for those plants, which are active.

Is that fine, Ahmed?

Yeah. Thank you.

Thank you. Next question, please.

The next question is from Javier Garrido of JPMorgan. Your line is now open. Please go ahead.

Hi, good afternoon. I think there's just one question left for me, coming back on your hedging. You have increased significantly the volumes hedged in the spread capacity from 50% to 80% in the second quarter. And as you mentioned in the call, spreads have increased in June, but they still remain low versus what they're having in the rest of the month. I was wondering, you could elaborate on why such a significant increase in the volumes hedged and the spread capacity whether it's risk management related or whether you found the absolute level of spreads very adaptive during the quarter? That would be very helpful.

Yes. Most of our - in the money spread positions are in the UK and in the Netherlands. And of course, the spread prices we give you on eight is Germany. So the increase in hedged spread positions in 2019 was, especially, the U.K. and the Netherlands.

Is that fine, Javier?

Yeah. That's fine. Thank you very much.

Thank you. Next question, please.

The next question is from of Sofia Savvantidou of Exane. Your line is now open. Please go ahead.

Yeah, hello. Thank you for taking my questions. I'll stick to two as well. One is a follow-up on what you said earlier on the Lignite & Nuclear EBITDA. Obviously, you are quite hedged for the fixed prices for 2018. And at the start of the year, you felt you needed to give about €100 million EBITDA range for the full year number, but now we've already seen the first half. So we still have €100 million EBITDA range, but on just the second half, which is effectively half the number. So I would be interested to hear your thoughts on with the price pretty much locked in, what is the variability that we could see and what would make you be at the top end, midpoint or lower end of that guidance range? And then the second question is on the coal exit committee. There was a press article today talking about some suggestions that the lignite provision should be reviewed in the same manner that we had for nuclear provisions. So I was wondering, what would be your view on that whether we see that as an opportunity to remove this lignite provisions from your balance sheet? Or how would you think about it and what would you want to see the committee do with that? Thank you.

Yeah. Thanks, Sofia. First on Lignite & Nuclear or also the other generation segment, I think we are very happy with the given guidance. So we feel comfortable, but it's - I mean, still a bit too early to hint in a clear direction whether it's the upper end, the lower end or the midrange. And I mean, given that we feel comfortable and maybe also hint where we currently see it evolving. So let's wait for another quarter to give a more directional view on where we end up in the guidance. On the coal exit and the discussion about the provisions, yeah, I think that was not a decision by the commission to deal with the topic. It was more from some politicians to suggest they should also look into that. I mean, there is no an expert topic. Let me maybe briefly explain how we think about it. The comparison to the nuclear liabilities is totally wrong, because on the nuclear side, as the decision was to review those provisions where the government takes over the responsibility and the financing, and part of the deal with the government to bring exactly that in line. Those who can determine the cost level, which are the - which is the government when it comes to final storage of the rate, should also be responsible for the financing. We still have kept the other part of the provisions, which is by the way to 2.5 times bigger than the lignite mining provision to decommission our plants and do the packaging and then no review has happened, because everybody feels comfortable with IFRS rules and our auditors and all the transparency we have to create is fine. And that is exactly the comparison to lignite. We are responsible for the re-cultivation. We are constantly doing it, it's not something, which is going to happen after the decommissioning. I think we have already re-cultivated bigger areas of land than we still will use in the future. So we don't see any comparison to the nuclear, which would - by the end, if that is really - if that would be done would be the opposite, which have been done on the nuclear side, which would then bring financing responsibility in two hands and not keep it combined in one hand. We currently - and that is the last part of your question, we currently see no initiative by the government or anybody to discuss whether the government should become responsible for this task and should take also the money. They see it as a compared to the nuclear topic, a minor topic also in terms of size of the liabilities, and they all want to keep the responsibility with the company and then also the financing should be with the company.

Okay. Thank you.

Thank you, Sofia. Next question, please.

The next question is Sam Arie of UBS. Your line is now open. Please go ahead.

Thank you. Good morning, everybody. I would like to ask two questions, please, on your future renewables business. And Gunhild, as you mentioned, you published a very helpful document on this, so I just wanted to thank you for that. My questions, the first one is quite simple. I just wanted to ask what level of return you think will be achievable on future renewable projects, but if you haven't secured yet in terms of project returns versus WAC [ph]? It's a question I've been asking everybody this results season, so I'm interested in your perspective on that. And then secondly, just stepping back a minute, when I look at the level of ambition from some of the countries you operate in? For example, I see the German regulators planning for an increase of 90 to 100 gigawatts of wind and solar capacity by 2030, so that's what 7 or 8 gigawatts of new renewables every year in just one country. Well, then I wonder why the industry continues in the mode of auctioning developments one by one, with one gigawatt, 2 gigawatts of capacity up for grabs each time. Do you think that over time we might see the auction model offering significantly higher volumes to secure even greater cost reductions? So for example, could you imagine a model where a given country would auction off packages of 5, 10, maybe one day 20 gigawatts of new capacity in one go? It would be delivered for a longer timeframe, obviously. But I feel like something is changing here and I'm interested in your perspective. So those are my questions. Thank you.

Yeah. Thanks, Sam, for the question. I mean, the last one is a political question of the regulatory framework. I mean, we also sit here puzzled and see how things evolving in Germany, if they are serious on reaching their targets of 65% renewals by 2030, something needs to happen on both ends, additional renewable volumes to be auctioned, but also the necessary investments in the grid and both is delayed. And - but if you ask me whether we see some indication, especially in Germany, that they want to change anything, we don't see anything. So maybe as you - we sit here and being a bit puzzled how they really want to achieve that. But so far, nothing is discussed in terms of different approaches to auctioning or also the entire regulatory framework around renewables and security of supply. So what in terms of expected returns, that is a more difficult question. It has two elements. The first one, what is the right WAC for a given project and the risk profile. And the other question is, what do you expect to earn on top of WAC. I mean, depending on the different regions and what we have seen in the auctioning, and also where innogy and E.ON are now successfully delivering projects, we think that you can earn a decent margin on top of WAC, depending on which technology and market. And it should be at least 1.5%, maybe up to 2%, 3% above on WAC.

Okay. That is very helpful and very clear. Thank you for your answer.

Thank you, Sam. Next question, please.

The next question is from Lueder Schumacher from Societe Generale. Your line is now open. Please go ahead.

Yeah, good morning. The first one is on Clean Dark spreads. Markus, you mentioned the quite strong recovery in Clean Dark spreads from June. What was the driving force behind it? Is it just power prices catching up with few commodities, which have been running up quite strongly? Or did the market actually get tighter this summer, perhaps, coal plants struggling with supplies, it'd be interested in your view on that? And then also on the carbon topic, where do you currently see the early fuel switch? And how much carbon abatement can actually take place at that level, in your view? There's also, while strictly speaking not a third question for me, because it's been asked already. So I just wanted to clarify. On the volume, on the outright output 2020, 2021, you said there's no specific reason behind it, but you're now more confident that will come out at the lower end. And I just wonder, what is this based on this greater confidence that you're going to be at the lower end? Is it sort of the marginal lignite plant that was hardly earning any money being taken out of the planning process? Or - just would be interesting to hear your reasoning behind that, what made you more confident.

Let me start with your first one, Lueder, the Clean Dark spreads. I mean, that's now pure speculation. I mean, technically, of course, power prices have increased more than hard coal and CO2 and that widens in the Clean Dark spread. What the drivers, why the market reacted like that, because it's a financial market, I don't know, right. I mean - you would typically see some - from time to time, you will see that power is lagging the fuel complex. So that coal and CO2 move faster and then power moves a bit later, especially in the outer years, where the liquidity is a bit more constrained on the power side than it is typically on the fuel complex, where you have much more liquidity in the market. But I'm not aware of any specific argument why is it's now widened at the end of June. The second question is a very interesting one. What can really happen? I mean, of course, at current CO2 prices and the fuel complex price constellation, you already see first fuel switching, because they're very inefficient, hard coal plants, the old ones which are still in the system are currently not economically. So it takes place, but to have a significant amount of CO2 abatement from fuel switching, you probably need higher prices. But it's now gradually starting. The interesting question, how much can really be base or reduced by fuel switching. And that amount is definitely not 100 million tonnes. It's in the two-digit million area. So if you see the shortage of CO2 supply in the coming years, which is maybe a couple of 100 million tons, this can never be solved by fuel switching, whatever the CO2 price level is. But I think, this is the too short-term sighted view on the CO2 market, because the most relevant question is what's going to happen with this surplus, and what happens with forward hedging, because of certainly different price constellation CO2 prices will probably change hedging behavior of industrials and especially utility. And that would then bring demand for CO2 certificates down. But this is a market which is very difficult to analyze fundamentally. It's more, I would say, game theory of what people will do at what kind of price level. But as we have said before, we expected an increase and I would not rule out that CO2 prices will go even higher. And the last one on volumes, on the 80%, so to be very clear, there is no new decommissioning plan or whatever that we take out an additional lignite block and so on. So we have always given the range, because we also gave for the other years range. Now, we have moved on in time, so we feel a bit more clearer that we should give you the transparency that we are more at the lower end of 80 to 85.

We were always at the lower end, Lueder, so it's just kind of narrowing the guidance if you want.

Okay. Thank you. Just one follow-up question, when you mentioned the - definitely the 100 million tons possible abatement from fuel switching, but double-digit. That was referred to Europe or just the German market?

No, that's the European market.

Excellent, thank you.

Thank you, Lueder. Next question, please.

The next question is from José López of Millennium. Your line is now open. Please go ahead. José López: Hello, good morning. Thank you for taking my question. I have two questions, mostly related with the UK and possible extrapolations to other markets. So the first question was about the increased participation of batteries and demand side response in the UK. And yesterday, we saw an [aggregate took them into] [ph]. So how do you see that impacting your expectations for ancillary service revenues? Are you seeing any pricing pressure in the UK on the ancillary service market? And do you foresee this trend occurring also in the continent? And also, one question, and the second question is your UK CCGT fleet is relatively more efficient than some of your peers. We have the beast from the east, so that coal snap in H1. And yet - and coal output is down across the system. And yet, your CCGT generated a little bit less than in H1 in last year. Can you take me through what's behind that? Did you have some statutory outage or maintenance that needs to be considered, that needs to be adjusted for that, you would have actually done a little bit better? Thanks very much.

José, thanks for the questions and very well spotted on the CCGT in the UK. We could not fully benefit from the beast from the east, because we had some minor unplanned outages in our CCGTs also weather related, but, unfortunately, especially in the period where prices were very favorable. Of course, we could partly offset that by selling the gas, which we didn't need, because also gas prices were very high. But in the end, this unplanned outages resulted in the situation where we made exactly the money we had hedged upfront. But we could not realize the additional upside. And that is also reflected in the produced volumes, so very well spotted. On the batteries in the UK, yes, our expectation is that we will see a continuous expansion of batteries in the market. It will also bring down some of the ancillary services prices, especially the very short-term response. But on the other hand, and the additional renewable new-builds will also make the demand for balancing the system, will bring the demand up. So currently on a net-net basis, we expect that we're going to keep the profitability level we currently see for our fleet in the UK. José López: Thank you.

Thank you, José. Next question, please.

The next question is from Nick Ashworth of Morgan Stanley. Your line is now open. Please go ahead.

Hi, morning, everybody. Two for me. I guess, it's a sort of a follow-up to that question. Thinking about portfolio optimization in the near-term, it's obviously that's all focused on the big deal into next year. But are there small disposals that you are wanting to make, are you happy with the portfolio where it is today. Is there stuff that you want to add? Are you spending more money in new technologies? What's going on with the current business? And then, how should we think about that over the next couple of years? And then, secondly, just a clarification on net debt. The €4.5 billion to €3.7 billion midyear, I think earlier on in the year you were saying that the full year should be closer to where it was last year. But I feel like it should now be closer to where it is at the moment by full year. And I want to just get some sort of clarity around when that will be by the end of the year. Thank you.

Yes, Nick. Thanks for the question. First one on the portfolio, I mean, we do some, let's say, minor growth investments into the portfolio. To name two of them, one is we invest in the biomass conversion of the Dutch coal plant. We will bring Amer online to almost 90% biomass firing until the end of this year, and also in Eemshaven up to 15% biomass coal firing. There is one smaller investment. And of course, we will now also bid into the auction process in Germany, where the grid operators will auction with stability which are smaller gas-fired power station in the area of 100 to 200 megawatt. And if we get that secured we are also investing there. But we talk about little investment there. On the inorganic Moerdijk [ph] site, we - if we can get hold of, let's say, gas and hydro for the right prices, we would add that to our portfolio in the market. But, I mean, we are investigating that now with potential sellers for the last years. And, of course, it always needs to two to agree on the price and we definitely want it for the right price or we keep our existing portfolio as it stands.

On net debt?

Sorry, and on net debt, yes, I mean, if you take the €3.7 billion and compare to last year, and here figure is definitely significantly low. But since variation margins are volatile, let's give it another quarter, until we update our guidance here.

Okay, understood. Thank you.

Thanks, Nick. Next question, please.

The next question is from Oscar Najar of Santander. Your line is now open. Please go ahead.

Hi, good afternoon. Oscar Najar from Santander. Yes, one question regarding the hedging in Page 7. Previously, you said that, now that power prices are higher, if you had the light blue area, your average price will be higher. However, we have seen that in the last quarter, in the second Q, the volume has gone from 30% up to 40%. And the price achieved has been more or less the same or 29. Obviously, this has to do with next page, that is the spreads of the - red line that is call for 2021 decreasing, but why don't you have been fully hedged in the position with a dark blue instead of continuing the fuel hedge and why don't you do that in the following month, because the power prices are much higher and you have hedged 3, 4, 5 units per megawatt hour higher? That's the question. Thank you.

Yes, Oscar. I mean, there are two reasons for that. The first one is by converting the outright position into the implicit fuel position we implicitly hedged the power price level, because we take out the risk of falling commodity prices, especially hard coal and gas. And the other aspect is that especially in the outer years, so 2020, 2021, we are liquidity constrained, if we just use the power products. By using the fuels to also grow, short them and implicitly hedge the position, we have access to more liquidity to risk management provision. Otherwise, it would take much longer to reduce the risk of the outright position. And I mean, to be clear, on 2020, you will not see at current price levels that we increase the dark blue area, because we think that the market is undervaluing the situation or underestimating the situation. And the financial markets are not reflecting the physical fundamental that we have seen that before. And at that price constellation, we are not going to hedge.

Thank you.

Thank you, Oscar. Are there any more questions?

There are currently no further questions. [Operator Instructions] We haven't received any further questions. I hand back to the speakers.

Thank you very much. Then, I'd just like to say, thank you for attending the call today. We at the IR department are available for further questions. And, yeah, enjoy the rest of your day. Bye.

Ladies and gentlemen, thank you for your attendance. This call has been concluded. You may disconnect.