Welcome to the RWE conference call. Markus Krebber, CFO of RWE AG, will inform you about the developments in the first half of fiscal 2020. I will now hand over to Thomas Denny.

Thank you, Anika. Good afternoon, ladies and gentlemen, and thank you for joining us today to discuss RWE's result for the first 6 months of the year. I'm joined by our CFO, Markus Krebber, who will run through the presentation before we move on to Q&A later in the call. As in Q1 this year, in order to compare like-for-like, our presentation focuses on the pro forma figures in comparison to 2019, meaning that assets taken over from E.ON in the third quarter last year are included for adjusted EBITDA and EBIT for the full year 2019. And with this, let me hand over to Markus for the update on H1 2020.

Yes. Thank you, Thomas, and a warm welcome to everyone on the phone. It's good to speak to you, and I really hope you are safe and sound wherever you are dialing in from today. The operational and financial performance in the first half of 2020 has been good overall, and so far, we have only seen a small impact on the business from the COVID-19 pandemic. On a pro forma basis, year-on-year adjusted EBITDA of our core business increased 9% to €1.5 billion. The RWE Group's adjusted EBITDA stands at €1.8 billion. We confirm our full year guidance and now expect adjusted EBITDA to be at the upper end of the guidance. We also confirm our target to increase the dividend payment to €0.85 per share for this year. Our net debt now stands at €7.8 billion. This is a decrease by roughly €900 million compared to Q1. Our clear target is to meet a leverage factor of around 3x adjusted core EBITDA to net debt at year-end. And we are delighted that the asset swap with E.ON is finally fully closed. The legal integration and the HR integration have already been completed. The teams are now operating in the target management structure across the entire business. Let me remind you that the energy activities, which we transferred back to RWE, have been recorded in our group figures already as they were commercially assigned to us. We do not see any relevant effect from the final closing in our financials. What else? We are excited about our latest announcement on the deal to acquire Nordex 2.7-gigawatt development pipeline in onshore wind and solar. This gives us great option for future growth and a broad entry into the French market. I will come to back -- I will come back to that in a minute. Regarding our Coal/Nuclear business, we are pleased that the Coal Phaseout Act, which found broad consensus, was brought into German law. Lignite phaseout is supplemented by a public law contract drawn up by the federal government and the operators, which will pass the German Parliament after the summer break. The law and contract are subject to approval under EU state aid law. We expect this process to happen in autumn this year. With this, we now have a clear path on how to exit from our remaining coal operations. Ladies and gentlemen, let me briefly come back to the transaction with Nordex on Page 4. This transaction is a strategic pipeline enhancement and our broad market entry into France. It strengthens our existing pipeline of 22 gigawatts, and the projects to be built will come on top of the targets announced at the Capital Market Day. We expect CODs as early as next year and additional capacity of approximately 500 megawatts in operations by 2025. We are also pleased that this creates a great opportunity to enter the French market. 1.9 gigawatts of the development projects are in France, of which roughly 300 megawatts are close to FID or in late development stage. France is a very attractive onshore market with huge build-out targets and a solid remuneration framework. France was the only large market in Europe where we were missing a pipeline and a strong development team. Together with the pipeline, an experienced team of 70 professionals mostly based in France will join us to drive our growth ambitions in France further. In markets where we already operate assets, the pipeline gives additional options: Spain, approximately 400 megawatts; Sweden, approximately 400 megawatts; and Poland, a small position of more than 10 megawatts. What are the next steps? We have agreed an exclusive put option with Nordex on a purchase price of €402.5 million. Nordex kicks off the consultation process with the French Works Council, which needs to be finalized before the put option can be exercised. The completion of the transaction is also subject to foreign investment clearance in France and the completion of common carve-out processes. It is assumed that the transaction could be completed in the fourth quarter of this year. Now back to the financials for H1 2020 on Page 5. In our core business, adjusted EBITDA increased by 9% to €1.5 billion as a result of a good performance in all segments. Broadly speaking, the good H1 result for Offshore Wind and Onshore Wind/Solar was due to the very good weather conditions in the first quarter and onshore capacity additions. The Hydro/Biomass/Gas division mainly benefited from the resumption of GB capacity market. And the Supply & Trading division outperformed after a successful start into the year, which continued in the second quarter. Ladies and gentlemen, our wind and solar business is progressing well. Installed capacity remains unchanged at 8.9 gigawatts, but there is more to come in the second half of the year. And we made good progress towards our growth targets for 2022. Amongst others, we have taken the FID for the Hickory Park solar farm in the U.S. with a capacity of 196 megawatts and a co-located 40-megawatt battery, which is due to be commissioned in '21. The project is under the investment tax credit, ITC, regime and has secured a 30-year PPA with Georgia Power. Regarding the period after 2022, the Awel y Môr Offshore Wind Farm has secured an agreement for lease with The Crown Estate. The project is an extension of our operating 20 more wind farms. The additional pro rata capacity is 300 megawatts. What are the next steps? The development of the project will continue with a view to participating in CfD auction rounds in 3 to 5 years' time. Furthermore, we welcome the announcement from the Irish government that the Dublin Array offshore project has been designated as 1 of 7 relevant projects, meaning it will be fast-tracked to the new marine planning regime. The project will add 300-megawatt pro rata capacity and is currently in the development phase. Subject to an updated content application and investment decision, construction could begin in '24 with COD in '26. And lastly, we are now participating in the third floating demonstration project. Together with The University of Maine as well as Mitsubishi Corporation, we will develop a demonstration project off the coast of Maine. We continue to drive floating offshore wind because we see great potential for floating wind farms worldwide, in particular, in countries like the U.S. with deeper coastal waters. Let's move on to an update of our construction program. It is progressing well, apart from some COVID-19-related delays, mainly at U.S. construction sites so that we had to shift COD of approximately 500 megawatts from '20 to '21. Due to the adjusted commissioning plan, we expect the overall financial impact for this year to be a small to medium double-digit million euro amount. Please note that the PTC income level of the U.S. project is secured in any cases at all sites. Now we'll take a look at the status of the individual projects we presented to you at Q1, starting with the Offshore division. Our Triton Knoll project offshore construction work started earlier this year, and everything is progressing as planned. At the Kaskasi project, contract with main suppliers are signed, so preparation work is continuing and going according to plan. The construction work will start in Q3 2021. The Clocaenog Forest onshore wind farm is already generating and receiving revenues from the contract for defense. As soon as wind farm testing is completed and COD is reached, we'll report it as installed capacity. Grid availability at the Cranell onshore site has been achieved and the commissioning of the individual wind turbine is ramping up. The actual commissioning date is scheduled for this month. We have updated our milestones at our Big Raymond onshore wind project. One part of the project, namely Raymond West, with 240 megawatts, will slip into Q1 '21, whereas the commissioning of Raymond East with 200 megawatts is expected in the second half of Q4 2020. COD of Scioto Ridge has moved within the fourth quarter to the end of December this year. On the basis of the adjusted time line, construction work is on track. Commissioning ramp-up will start soon. And at the Limondale solar farm, the grid registration process took more time than expected due to the current circumstances. COD has, therefore, slipped into Q1 '21. In total, we will bring 1.3 gigawatts online in the second half of the year, mainly back-end loaded. With that, we can move to the details of the individual segments. The Offshore Wind division realized an adjusted EBITDA of €585 million. Year-on-year, this is an increase of 19%, thanks to higher wind speeds in the first quarter. Gross cash investments in H1 amounted to €316 million, mainly driven by Triton Knoll construction work. The sale of the Seabreeze installation vessel is the main driver for gross cash divestments. We confirm the outlook for the offshore division. Our Onshore Wind/Solar division increased 12% year-on-year, and adjusted EBITDA amounted to €273 million at H1. Revenue drivers are an increase in capacity of approximately 380 megawatts year-on-year as well as higher earnings in Europe from above-average weather conditions in the first quarter this year. Most of the gross cash investments are for the U.S. onshore projects, Big Raymond, Scioto Ridge and Cassadaga as well as Boiling Springs. Despite the small to medium double-digit million euro negative impact from tighter commissioning phases and the delay at Big Raymond and Limondale, we confirm the outlook for the full year. The Hydro/Biomass/Gas division delivered a good performance over the first 6 months, higher earnings results mainly from the British capacity market. In contrast to the strong first quarter at H1, earnings from the commercial optimization of our power plant dispatch have normalized. In June, we signed a contract to sell our Georgia biomass business to Enviva Partners for a purchase price of USD 175 million. The transaction was closed at the end of July after successful merger clearance. The disposal is already reflected in the guidance we gave you in March. The EBITDA contribution for pro forma 2019 was a good €30 million. In 2020, it is approximately half this amount. As we have already reported to the market, the fire at the Eemshaven power plant has caused an interruption to the biomass co-firing, which we expect to last until November 2020. This will impact the outlook by a small to medium double-digit million euro amount. Despite this, we also confirm the guidance for this division. Moving on to another quarter of favorable earnings development from the Supply & Trading division. At H1, adjusted EBITDA amounted to €322 million on the back of a strong trading performance and good results from the gas and LNG business. We didn't expect the division to replicate the exceptional performance of the first 6 months of last year. The division's outlook is €150 million to €350 million. Given the strong H1, we expect to end at the upper end or even above. Ladies and gentlemen, having now reported on the core business, let's move to the Coal/Nuclear division. Adjusted EBITDA has doubled year-on-year and amounted to €310 million. As we already mentioned at Q1, earnings improved due to higher realized wholesale prices and an updated production plan in the lignite system. Nevertheless, we need to consider implications from the implementation of the accelerated exit plan. For the full year, we confirm the division's outlook. Moving on to the earnings drivers down to adjusted net income. Adjusted net income amounted to €795 million due to the high adjusted EBITDA of RWE Group. The negative effects in the financial result of minus €150 million from Q1 were partly compensated by the E.ON dividend of €182 million we received in the second quarter. Adjustments in tax are applied with a general tax rate of 15%, in line with the expected midterm tax level for the group. The tax rate of 15% has been derived from all income streams. It is based on blended local tax rates, the use of loss carry forward and the low taxation of dividends, including the E.ON and Amprion dividends. And now on to the adjusted operating cash flow. The adjusted operating cash flow shows the impact on net debt from operating activities. It is adjusted for special items and timing effects that balance out over time. The utilization of nuclear provisions is not included. As you will remember, we consider this as a financial cash flow. Hence, when the nuclear provisions are utilized, they can be refinanced via financial debt. In H1, the adjusted operating cash flow topped €2 billion and is built up on the high adjusted EBITDA as well as a positive effect in working capital. The change in working -- operating working capital of €437 million is mainly driven by the payment from the British capacity market from 2018 and '19, which we received in Q1 as well as a reduction of gas inventories. For the full year 2020, we expect this line item to remain positive for the same reasons. Turning to the details on the development of net debt. At the end of June, net debt increased to roughly €7.8 billion. First and foremost, this was due to timing effects from hedging activities of roughly €1 billion, mainly related to CO2. Another driver of net debt is the company's net cash investments, clearly linked to our strategy to expand in renewable energy. The dividend payment for fiscal year 2019 is already reflected in the net debt figure at H1. We see a leverage factor of around 3x net debt to core adjusted EBITDA at year-end, which considers the investment of approximately €400 million for the acquisition of the 2.7-gigawatt Nordex development pipeline. Volatility and commodity prices and interest rates could temporarily drive it slightly above 3x. But if this is the case, we are confident that we would return to our target level in the medium term without an impact on our planned CapEx program. Finally, moving on to the outlook for fiscal 2020. As I already said, we confirm our outlook for this year. Adjusted EBITDA of the core business will come out between €2.15 billion and €2.45 billion. Adjusted EBITDA for the group will range between €2.7 billion to €3 billion and adjusted EBIT between €1.2 billion to €1.5 billion. For both adjusted EBITDA and adjusted EBIT, we expect to see results at the upper end of the guidance. Our guidance for adjusted net income is €850 million to €1.15 billion, and we expect it to be in the middle of the range due to the negative one-off in the financial result, which we experienced in Q1. The dividend target is unchanged, €0.85 per share for fiscal year 2020. And with this, I conclude my remarks, and I'm now happy to take all your questions.

Thank you, Markus. And as always, in view of time, please stick to two questions only. Operator, please start the Q&A session.

[Operator Instructions]. Our first question is coming from the line of Wanda Serwinowska from Crédit Suisse.

Wanda Serwinowska, Crédit Suisse. Two questions for me. The first one is on the negative power price. In the U.K., there is a clause in the most of the CfDs to say that if the power price goes negative for more than 6 hours, then basically CfDs will still apply for that time. Does the rule apply for all your assets in the U.K.? And is -- and that's the same or similar to exist in other markets than other we operate in? And the second question is on the renewables target growth. When can we expect RWE to raise the annual renewables target growth? I mean we've seen recently Engie increasing the annual target from 3 to 4 gigawatts per annum.

Yes. Thanks for your question. I mean, yes, the negative price rule applies to the U.K. and we have a similar one. But the technical details are slightly different also in Germany. I mean I have to admit, I don't know the exact details. And so far, I think, I mean, you can usually plan it because you know your power price forecast on a quarterly hour basis for the full year. And I mean it has not had a significant negative effect, which was not planned for us even this year. So for us, it's a minor technicality. And if you want the details, I think please call the team also to understand where the German measures deviate from the U.K. one. On the targets, I mean, we already gave you an indication with the Nordex pipeline that comes on top of our target. But I mean our targets have been communicated a couple of months ago, so don't expect us that we give you new targets every month. So when we deem it appropriate that we need to update the market about new plans or revised plans, we will do it. But we will not do it on a quarterly basis.

I would appreciate if you could get back to me on the details, on the technical details on the negative power price. I know that it's not the issue for this year or next year, but we've seen more and more of a negative power price on the market.

Yes, we will come back. But I mean just a remark, I mean, the moment it becomes viable, you usually -- I mean -- but as the team comes back -- but I think -- I mean, for us, I think it's an overrated issue also going forward because what we see is we get more and more flexibility in the system in many markets, so the periods of very negative power prices should naturally come to an end. I mean not for the specific plant. You cannot do anything for a CfD plant. But the market overall because incentivizes investments in flexibilities like batteries and that -- and these -- if you get more of that, it will definitely take at first the negative power prices away. So we don't see it as a big issue going forward, but the team will come back on the technicalities.

Your next question is coming from the line of Vincent Ayral from JPMorgan.

Yes. Quick one. Could you provide us a bit more color on the Nordex pipeline but at an asset level so we understand? We see the geographies, so mainly it's the footprint in the French onshore market. So we understand the strategy behind. It would be great if we could get a bit more color on the project level. What are the big projects which are in there? And basically, what is the expected time for contribution there? So that will be the question one. And bouncing back on this, what is your view regarding acquisition of renewable assets given current prices? Buying a pipeline is one thing. Buying an existing operating asset is another one. Do you see that like value accretive? And would you, in such a situation, consider potentially even finding larger acquisitions by reconsidering your stake in E.ON?

Yes. Thanks for your question. Let me start with the latter one. I think for us, I mean, having a deep pipeline where we can invest our money, it would not be, let's put it, value optimal to actually acquire existing assets because we want to build them. We want to operate them. And us becoming a financial investor, I mean, I see it difficult that, that is really value accretive. It's a different thing if you can maybe swap assets here and there to change the portfolio mix and get some synergies here and there, but I don't see it as very relevant for the near future. So I mean we are interested in strengthening our pipeline, especially as we have done with the Nordex. I'll come to that in a minute. But acquiring existing assets, asset by asset, is not part of our investment plan. I mean on the Nordex pipeline, I mean, let me start first with why this was strategically important, as I said in my speech, because France is a very attractive onshore market. With -- I mean the double-sided CfD for 20 years, inflation linked, we have seen prices in the last auctions between €62 and €67. So you can see that, that is very attractive. And it was on the European landscape, the one target market where we really missed the presence, so it was really a good opportunity for us. We looked into the pipeline in detail, as you can imagine, in the due diligence. And I mean we have very good locations, good wind conditions, clusters in geographic proximity that will provide efficiencies. And I mean I can -- I will not talk about specific locations now because the transaction is not closed, and we are bound to confidentiality. So I can give you a view of how the portfolio will look like. I will give you more color in a minute, but I cannot talk about specific sites. I mean we can give you more color after the closing of the transaction. What we have already said is 15% of the pipeline is close to FID or very late development stage, and we expect the first CODs by '21. On average, we would at least expect 100 megawatts from the pipeline per annum so that we have, by '25, another 500 megawatts under operations. Including the purchase price of €402.5 million, we expect that the IRRs of the projects will be within our given range. At the Capital Market Day, we said for mature onshore PV markets we expect 4.5% to 8%. But please, I mean, this is a very mature market, and we had to buy it. So don't expect it at the upper end of the 4.5% to 8%, but clearly in the range. We saw the price as attractive. I mean it's always very difficult to judge or assess the price from the outside in, but we have also seen other pipelines. We participated in many due diligence in France, so we know also how other pipelines look like. And just looking at it from the outside in, you have seen acquisitions in that market, which were priced at €150 million to €250 million per megawatt, and we are at the lower end of that. But I mean that is very difficult, comparing prices on that level, pipeline by pipeline. The split of the maturity of the pipeline is more or less in line with the maturity of our overall pipeline. I mean around -- as I said, 15% is close to FID and late stage. We have around 30% mid-stage, and the remaining part is in early stage development.

The next question is coming from the line of Peter Bisztyga from Bank of America Merrill Lynch Securities.

Yes. So just another one on the Nordex portfolio. Could you sort of tell us how the €400 million acquisition price and the, I guess, additional CapEx that you're going to be spending over the next couple of years fits into your existing €5 billion CapEx budget? Does it displace something else out of that budget? Or is it in addition? And I guess if it's in addition, then where have you found the extra balance sheet capacity, please? And then my second question actually was just on carbon, which has obviously been very volatile over the last couple of quarters. I guess your Supply & Trading division might have profited from that. But I was just wondering, could you give us your views as to what's actually been driving the carbon price, particularly as it's reached for sort of mid- to high 20s?

Yes. Peter, thanks for the question. On the Nordex pipeline, yes, it will come on top of the €5 billion, as we have said with the announcement of the transaction.And now your question regarding funding, I mean, as I said in the speech, we expect to be within the leverage target of the 3x net debt to EBITDA, including the €400 million. And I mean we have a lot of moving parts. I mean if we assume, and I also hinted to that, that commodity prices, especially gas and CO2, and interest rates stay where they were at end of June, then we have a good view what are the moving cash items, operating cash flow, investments. We know our divestments are hinted to Georgia Biomass. We're going to pay back the hybrids. I mean that is all very stable, and we can foresee that we'll end the year at around 3.0. But of course, we cannot control commodity prices, and we cannot control interest rates. But these are only, I mean, timing effects. I mean it will normalize over time. That's why we are confident. If we move up, then it will come down without impacting the CapEx. Then later, the project investments after the -- I mean when we do CODs, that will be part of the capital allocation approach. But of course, as I hinted to, it will come on top of our existing targets. But I mean 100 megawatts here and there, that will not move the needle on the company of our size.

And carbon?

Sorry, carbon. Sorry. Exactly, carbon. Yes. I mean even within the team here, we have 2 different views, and I think that's a good reflection of how I see the market. Short term is more bearish because, I mean, with the COVID situation, with very low gas prices, significant fuel switching, muted industrial demand, I mean the demand for carbon certificates is definitely much lower than it has been expected. On the other hand, it's also clear that the more political mid- to long-term view is more bullish because, I mean, somehow, the European Commission needs to implement the more aggressive CO2 reduction target. And it doesn't matter whether they go to, I don't know, 50%, 55% or even 60% reduction by 2030. A significant part of that, maybe even more than half, needs to come from the EU ETS, and that will definitely mean that prices will go up. And maybe what is different this time than in the last financial crisis, in the last financial crisis, we have seen a lot of industrials who were sitting on excess certificates were in financial trouble, and they needed to sell just to get liquidity. This is with a huge program of the central banks and the fiscal support, now different. Maybe some industrials take more of the political long-term view and use the liquidity they still have to buy cheaper than they expect the prices to be. I think these are the 2 camps, short term, long term. And since this market is nothing you can fundamentally analyze that it's always a sentiment question, and I think the more dominant factor is definitely the midterm to long-term political view. I can simply not imagine that if prices go down to €15 again, that the politicians will simply do nothing.

The next question is coming from the line of Alberto Gandolfi from Goldman Sachs.

The first one is to go back to the E.ON stake. We heard in the past that, maybe badly counted, about half of that could be used against lignite liabilities and the rest could be used for growth. Could you please confirm that? And when it comes to growth, can you help us understand the logic? Would it be contingent to maybe big offshore wind or perhaps to identifying something external, like you just did with Nordex and be something even bigger? And secondly, it's just thinking about M&A from a different perspective, like RWE as a potential target. So we are seeing oil companies very quickly moving into the space, BP with a 50-gigawatt net target by 2030. A company like yourself would be like a plug and play, developing with existing capacity. So do you think there is a race to scale here? And what would be the best way for you to fend off a threat like this one?

Yes. Alberto, thanks for the question. I mean on the E.ON stake, I can just reconfirm that everything is still valid, which we have said in the past. I mean the E.ON stake is not tied to the lignite provisions. We just said we currently use it. We could also back the lignite provisions by other financial portfolios. And I mean when you look at the potential sourcing of financing, yes, I mean, we potentially need half of it to back the lignite provision, and the other half would be available to capital rotation. But I mean that has not changed. It's exactly what we said before. Usually, we have two questions. So you have three. Which one do you want me to answer now, the oil question or the other one? I'll start with the oil question, and then let's see whether we still have time.

Perfect.

Because I think that's the more interesting one. I do agree that it could -- that we couldn't end up in a situation that it's a race for scarcity because, I mean, it might be difficult to -- if you put together all the capital investment plan of everybody around in this field, it's almost impossible to employ that amount of money until, let's say, 2030 because there are simply not enough projects and you have more lead times to do it. So existing pipelines become much more valuable. I think the investors of big oil and others needs to ask themselves the question whether it's really green, a green investment, if you buy existing stuff from others because that is not a positive contribution. It's just, I mean, overbidding in prices. So I mean on the question whether we could become a target or not, I think your company is well positioned to have the oil companies figuring that out, and we sit and wait what happens.

Got it.

Well, I mean that's speculation. I mean that's not in our control. So what can we do? I mean I'm actually happy that also others see the field of renewables and the overall power sector as attractive because that's our -- that's the core of our strategy. And I think we have all the ingredients to be successful. We have a very experienced team. We have a deep pipeline, which actually needed to be developed over a decade. And of course, we have an investment discipline, and we'll ensure that we put the money where we get a decent return. And we will continue doing that, I mean, developing our pipeline, investing in good projects and also being on the technological forefront, be it battery speed, H2 or be it floating offshore. Where I actually don't see limiting factors is the long-term market growth because the long-term market growth of renewables and also power overall is, I mean, tremendous globally. The trend to electrification and to green is very supporting. And where I also don't see a limiting factor is funds because if you have good projects, I think investors are actually looking for investment opportunities. And now you need to ask yourself who actually brings what to the table. I mean the market growth is there itself. Funds is not the problem. So what you need is experience in the pipeline.

The next question is coming from the line of Rob Pulleyn from Morgan Stanley.

Yes. So first question, Markus, is can we talk about the EU recovery fund and how do you think internally that RWE will benefit from this? And there's a second part to that, not a second question. Can you help us understand practically how the money flows from a number on the presentation slide into actual projects? Because that still seems very unclear. And the second question, and hopefully a lot simpler, is you have secured some acreage in the U.K. Could you provide an update on the process you have for leases for some of the other extensions you flagged at the CMD, namely Greater Gabbard, Galloper and Rampion. Has that been successful? Is that underway? Or is that not this year's business?

Let me start with the easier one, Rob. I mean we are working on the lease extensions, and we -- it will be around 800 megawatts to 1.2 gigawatts. And we are optimistic that we can finalize it and by then, book it as the lease is secured by the end of the year. But it's going well. And on the European recovery fund, let me start with the second part of the question. Yes. I mean I think we will learn about it over the next, let's say, 2 quarters until the end of the year, how the flow of the money will really go because usually, the European Union works in a way that just -- they don't have -- they have only little funds like the Just Transition Fund and stuff like that, that's double-digit million, where they put money directly into specific projects. Usually, the European Union's budget is a huge kind of, I mean, shifting mechanism. So people are paying net in and getting money net out. So what now, as a next step, needs to happen is that the individual countries needs to come up with programs and plans where to invest the money. And if that ticks all boxes, they will get their proportional share of the money. So we need to wait for national actions, where they're going to put and where they want to invest and how they support certain things is also unclear. I mean you can do it with direct subsidy. You can do it with the remuneration framework. It's simpler financing. I mean it's still totally unclear. And the only thing what we can do, and that's the first part of your question, I mean we are also now actively looking especially in the evolving H2 sector. And of course, what is obvious is if more renewable power is needed and you get an indirect remuneration framework for renewable power via the support of demand for green hydrogen, we are definitely ready to build more renewables, but we are also willing to invest into the production of hydrogen. That depends on what agreement we find with the partners. Is it better our money or their? And how do you structure the contracts? The question is who puts money into transportation. Maybe more others. It remains to be seen whether that needs to be unbundled. Many open questions. So I think the important step now is to get the right partners together and think it through, what is feasible. And you should usually start with the demand, I mean, who actually needs the hydrogen. And then you do -- you backward read into it. And I mean I think these are the big fields. Our current business already saw especially renewables and storage technology. And the new one, which will come in addition, is hydrogen. But also, I want to kind of not spoil the party, but I mean, if we talk about profits from specialty hydrogen, probably we need to wait a couple of years before it is relevant in terms of investments but also in terms of profitability. And maybe the kickstart of the solar and wind business is a good proxy. It could easily take at least half a decade, maybe a decade before it becomes a relevant profit figure. We will update you whenever we have good news.

The next question is coming from the line of Sam Arie from UBS.

Great set of results today. I just wanted to ask two questions, one on returns and one on farm-down. So on returns, I think you had spoken at the CMD about 100 to 300 bps spread above WACC as being typical in the renewable business. These days, 100 to 300 bps doesn't actually sound that crazy as an estimate of the WACC actually as well. And I don't know, the lower the WACC, the lower the spread that you need to make the same kind of value creation ratio. So it just seems to me that a year or 2 ago, it was common to talk about high single-digit returns in renewables or mid- to high single-digit returns. I'm talking about unlevered project returns. But are we now more likely to be going into the low single-digit returns territory? And is that possibly a fair outlook for Offshore Wind as well, where returns historically have been a bit higher? Just love to know what your thoughts are about that, the kind of industry level. And then my farm-down question is just, look, I feel like we're going to see over time more and more pressure from auctions and tenders, and developers may be eventually forced to bring the farm-down partner with them to the tender. So if you like, the competitive pressure of auctions will mean that there's kind of extra value arbitrage that you currently get in the farm-down might eventually get captured by the consumer or the public body that's doing the tender. So I'm just wondering, do you think that's a reasonable expectation? And have you thought about whether in the future you will sort of, as standard, go to auctions or tenders with a finance partner alongside? And have you talked to any specific funds or partners about that kind of long-term approach? So returns and farm-downs.

Thanks for the discussion. I mean on returns, I agree that we definitely see that the WACCs are coming down. I mean I also carefully read your report. And you also put now very low numbers to WACCs, which I think is the right thing. But I'm not there that I would say we see now low single-digit returns for offshore. That's not where we are. I mean definitely, if we have promised you the average IRR of an unlevered project of 650 basis points for the investment program we have outlined until 2022, potentially the absolute returns -- not the value creation but the absolute returns of the next CapEx program will be lower but also because the WACC is significantly lower. And when you talk about the absolute level, I'm not at low -- I mean low for me is three and three something. It will come down, but I mean what we see is not for the projects which we have after the '22 horizon already visibility of the profitability. I wouldn't call it that low. It's more medium. A farm-down, I'm not sure whether I got your question. I don't see -- I currently don't see that you have tenders where you need to bring your financing or will you have an advantage if you don't go into the auction alone and getting an advantage when you already bring a financing partner. I haven't seen things like that. What is more and more obvious is that also now the new tender design, to give you one example for Taiwan, that local -- I mean local production becomes a dominant theme that if you want to put money in some place, you need to prove that it's actually good for the regions where you get the lease. It's good for the people. You create jobs. You use local suppliers. That is becoming more and more important. But what I don't see is that its advantage that you already, with the auction, say that you're going to farm down or bring a financing partner.

Okay. Well, look...

Does it help? Or you want to have a clarification?

No, no, no. That's fine. I don't want to take up too much time, but I'm sure we'll talk about this again.

The next question is coming from the line of John Musk from RBC.

Yes. Firstly, on the hedging of the outright book, it looks as if you've accelerated the fully hedged portion, particularly in 2022. Obviously, it's quite a small chart, but from maybe roughly 30% to 50%, which is probably more than you would normally do in a quarter. So I just wanted to understand some thinking behind that. Is there a particular view on power prices or spreads at these levels? And then secondly, on the 3x leverage factor, just confirm, that's not including any potential asset rotation at the moment? Because there are some headlines in recent days around some of your offshore assets that you might be looking to sell down.

John, thanks for the question. I mean on hedging, you are right. We increased the outright hedge. So what we actually closed by that was the spread position. Is there -- I mean what you could read into it is if you think spreads are fair, it's part of derisking now to close it. And I think if you look at current market prices and spreads, I think everybody expects 100% recovery by '22. And if you want to lock that in, you better close the position now. And that's what we have done. That doesn't tell you what we -- I mean we don't know how the global economy will look like, but it's better to log it in now than to keep it open. On the leverage side, the 3x net debt to EBITDA includes our plans on capital rotation. So it is our net investment target. I mean we have outlined a net investment of around €1.5 billion to €2 billion per annum. So if we're going to invest, gross more given the profile, and it also includes divestment. I have already said that we divested, which is not yet in the financials, Georgia Biomass for close to $200 million, $175 million and some adjustments. And I mean on the other things, we are considering our options. So we will bring it to the net figure. But I now don't want to speculate on gross and net because we always said that the leading metrics is 13 gigawatts net. So whatever we do also on disposals, we will reach the 13 gigawatts net. And also the EBITDA guidance for 2022 is a net guidance. Yes? So -- and how we're going to achieve it with how much gross and how much disposals that we need to -- given the current uncertainties in some markets, we need to have some flexibility. And I mean if you now want to get a comment on the rumors on disposals, I mean, the comment is no comment because, I mean, we will update you when we have taken a decision. Not -- we will not update you whether we have on a certain asset the market share or not.

The next question is coming from the line of Deepa Venkateswaran from Bernstein.

So my two questions. So firstly, in the U.S. So if we do have a possible victory for Joe Biden and they bring in the 2 trillion plan, I was just wondering, how does that change? Would you accelerate your growth your -- the conversion of your pipeline in the U.S.? Or practically, how might it change anything for you? And my second question is on Germany itself. So obviously, Germany has pretty lofty targets for 2030, but we're seeing the auctions are continuing to go undersubscribed on onshore wind. Do you see this situation changing with any kind of reforms? And would you be taking the lead as, I don't know, Germany is a national champion on this to also grab maybe more of the share in the German renewables market?

Yes. Deepa, thanks for the question. The first one is easy. We actually don't expect a significant impact from a potential federal election outcome in the U.S. on our business. I mean even today, I mean, many things depend on state level. Of course, the tax support is a federal thing, but also the current administration extended the PTCs given the COVID situation. So I mean it's pure speculation. I would say it will not make a huge difference. And on Germany, of course, we would like to do more in onshore and -- in onshore in Germany. And we see undersubscribed auctions. The problem is that the projects are not ready to be bid into the auctions. We have permitting issues. We have pending law cases and so on. But there is some interesting development because the Minister of Economic Affairs, he tabled a law, a draft law yesterday or 2 days ago, where they really want to accelerate the permitting process and the court proceedings. And they also introduced something which is now heavily discussed also with the NGOs that even if you dispute a permission in court, that should still, until the decision is there, allow the construction to go on. And that would be both very helpful. So speedier processes, and you can straight to the final court level to get a decision. And you don't need to go through the hierarchy and also that nobody can, by pure tactics in the court, delay projects. But let's see how the draft will go through parliament, but the draft version at least looks very favorable for the industry.

The next question is coming from the line of Piotr Dzieciolowski from Citi.

It's Piotr Dzieciolowski from Citi. I have two questions. The first one would be small on Nordex. Can you say what's the kind of current cost structure of it? How is it, significant numbers, small number in annual euro figure as you take over the whole company? And secondly, I wanted to ask you on the CO2, go back to this discussion because before the COVID-19, I thought there is an equilibrium, which is determined by the switching between coal and gas power plants. Now if we take coal assets out, what will be, according to you, your expectation, the next equilibrium kind of threshold? How will the market will restore longer-term equilibrium on the CO2 prices? What should we be looking at the elimination of CO2? What's the next thing to look for?

Piotr, thanks for the question. I mean on Nordex, it's easy. I mean we take over the company, yes, but it's a development company. So what you actually have is the salaries and OpEx for the 70 people and of course, the development expenditures for the two developed projects. But I mean part of that is also capitalized. So it's a very -- I mean, in terms of addition to the cost base, it's almost not relevant. I mean the most relevant one will be the DevEx for the project and then the CapEx. On CO2 equilibrium, yes, actually, the interesting thing is that the current CO2 price is already above the fuel switching price from hot coal to gas. The current stack in most of the times looks at gas first, then lignite and then hot coal. So if you take out hot coal now, that shouldn't change the equilibrium between -- for the CO2 relevant fuel switching price. There shouldn't be a change. The interesting element, as I said, it's already trading above the current fuel switching level. That can only be explained that, actually, the industry expects a shortage. And -- but this is always difficult to judge because this market is not an annual market. It's also since you can easily keep your certificates for longer, you can also say it's partly a view on what to come in future years. So I would not overrate the annual price, which causes fuel switching. That was in the old days of oversupply a good indicator. But now with significant more tightness to come, maybe that's not the relevant indicator anymore.

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

Two questions for me, please. The first one is on negative prices. And I'm sorry if you covered it before. I missed the very beginning. Basically, Ørsted reported yesterday, it was a small issue for them because of -- if the prices stay negative for the subsequent few hours, your CfDs and whatnot, you can't recover yourself today. So is that -- have you seen an issue with you for the second quarter? And do you think the negative prices will become more or less prevalent going forward? The second question is on hydrogen. Where do you think the value will lie? Is it in the production of hydrogen, transportation of hydrogen, converting it to other fuels, like e-kerosene, et cetera? Where do you think the money will be? And will you be a big player there?

If I could answer the last question, life would be easier. I think it's too early to tell. It also depends on how will the incentivization framework look like and how big will the market become. And of course, it has 2 angles. You can incentivize green production, and you can incentivize demand for green hydrogen. And in the end, it will be then kind of demand/supply on the different angles. Where I actually don't see scarcity is the production of green hydrogen in terms of electrolyzers. I mean that's a proven technology. Where we definitely have scarcity already today is renewable projects because, I mean, if you believe all the demand forecast, and I have no doubt that, that is a good assessment, we need so much green energy that every project, which is actually in the pipeline of somebody, needs to be built one day. It's just a question of time. So this is really a scarcity. On the demand side, I think that will be a competition by the off-takers, who is -- who can do it cheaper. That's nothing for us. I mean if you ask me where I see our role, it's definitely on the production side, green power, potentially depending on how the consortia will look like, also the production of green hydrogen and then the structuring of the offtake. I mean as we are currently also a very relevant player in gas trading and providing solutions to customers, that will also our role be in H2. And you can do that without producing as we currently do with LNG and natural gas. The first question on negative prices, I mean, for us, I mean, we have seen it in the U.K. and Germany. But it's not -- it was not a relevant issue. I mean it was not a big number.

The next question is coming from the line of Ahmed Farman from Jefferies.

Two questions from my side as well. I was just wondering if we could get a little bit more color from you around sort of how do you see this in terms the value creation opportunity relating to the Nordex pipeline, especially the sort of the near-term assets. Because you mentioned it's a mature market. Some of the near-term projects are fairly well developed, close to FID, sort of market where RWE has scale in the past. I was interested in understanding a little bit more how you see the sort of the value proposition from RWE. And I guess the second question is relating to that. I think you mentioned earlier, right, this was one of the markets you didn't have presence. And therefore, you were sort of looking for opportunities. Looking at your existing portfolio, either from a pipeline perspective or a skill perspective, are there any sort of specific gaps that you see that you think sort of scaling up could sort of benefit -- be quite beneficial?

Yes. Ahmed, thanks for the question. I mean on -- I would not say that we failed on France because we were simply not present. It was always a strategic target to get a foot in the door, and now we have not only a foot in the door but a significant pipeline. And the Nordex team was actually very successful in the French market. I think they ranked #2 in terms of success rates in 2 auctions in the last years. And they have not only built this pipeline. Their business model was to build. And then when they were close to FID and they've got them to the auction, they sold the projects to their potential customers. And I mean what is the value creation potential for us? I mean it's -- we continue what they have done in the past, and we closed our strategic gap. And the team is not there just to deliver the pipeline which we have acquired. They will continuously develop projects. And the French market overall is very attractive. It's not so densely populated like Germany, so you have more space. They have huge build-out targets and even better remuneration framework with a double-sided 20-year inflation-linked CfD. So if you believe that onshore wind in France is good, it will definitely create value. And I mean we are a firm believer that also the political environment in France and their target to go straight from nuclear to renewables will not be questioned by some of the next governments. So it's a very intact growth platform. The gaps in our pipeline, I mean, I think it's always good to be honest. I mean if you look into that, we are very wind heavy. So doing more on the solar side would definitely be good. Let's see how we can achieve it. I mean we have definitely -- we have definitely ramped up our development activities, and you will see more to come, especially in the attractive solar markets like in the U.S. But still it's, compared to the wind side, underrepresented. And the other one, which is definitely significantly tougher, maybe impossible to close. If you look into our offshore pipeline, there is, in terms of COD dates, and that's historically explainable because E.ON stopped and Engie had also funding issues, but we have a gap between '22, where we will commission Triton Knoll. And then maybe the next project will be commissioned, according to the current pipeline, around '25, maybe '26. And that is -- I mean this is a profile how it looks like. And if you ask me, you have 2 wishes, I would like to fill that time gap, and I would like to have more on the solar side.

The next question is coming from the line of Firmino Morgado from Man GLG.

I mean two quick questions. One is in deep offshore wind floating. I mean what's your view in terms of the different technologies that are around and what you envision that will be the role of RWE?

Okay. Thanks for the question because, I mean, I can use it as an opportunity to clarify what our interest is. I mean we are not turbine manufacturers. So we are not betting on a certain technology. And I have no view and also the team has no view what is the potential best floating technology for which market and which sea conditions. So what we said is let's participate in different technologies, be it the -- be it concrete or be it -- still, I mean, you have also different -- I mean I'm not an expert on that, but probably you are. You have totally different approaches to that. And what we said is we want to be part of consortia of several technologies to be an early learner. We want to learn how this stuff works because it is a bit different than a fixed bottom. It is in terms of wind yield, in terms of maintenance costs and so on, and we want to learn that with different technologies. That doesn't mean that we will, in future, if we go into offshore, only use the technologies where we have been a partner early on. We can also use others. And you asked for our role. Our role is we want to be -- we want to construct and we want to operate also offshore wind farms. But we don't want to build the turbines or the foundations.

Very clear. And just perhaps to tie up with Alberto's question and the role of oil companies, I mean, do you envision actually that deep offshore will be best to do in joint events or in conjunction with oil companies that have experience from offshore?

I mean that's speculation. I mean -- but if you look at our partnership landscape, I mean, we are operating one offshore wind farm together with Equinor. I mean they are a partner in one of our farms. One of the floating technologies we are in, we are together with Shell in. But I think, I mean, that can go the one way or the other. I mean it's too early. I mean we are open to discussions, but we could also do it ourselves.

And the related question. When I compare RWE and your strategy and what you want to be with the leaders in renewables, so in Europe, the role in Enel certainly, one of the components missing on the investment thesis is the full commitment to a growing dividend. I mean when do you think that you can have that full commitment? And what kind of growth do you envision that you can sustain?

I mean I would not compare us to Enel. I mean Enel is a fully integrated utilities with, I mean, most of the value sitting in the networks. And they don't operate offshore. I mean our business model is, I mean, is different. We have actually given a clear commitment to a growing dividend. We said we want to continuously grow the dividend broadly in line with the development of the earnings of our operating core business. And since the core business, given our investment plans, will definitely grow, also the dividend should grow. And we discussed it before. So I said, I mean, a good proxy is maybe the €0.05 on top every year, which we have now delivered for the last years. I mean it can be maybe even more because, of course, the percentage goes down if you stick to an absolute cent number. But that's a commitment we have given. We want to grow the dividend in line with our next development in core -- in the core business.

But if the core business, for whatever reason, cannot sustain -- I mean, cannot grow, I mean, what's your commitment? You will cut the dividend in line with the decline of earnings on the core business?

I mean we should now -- I mean we should stick to the two questions rule. So I'll still answer that one, but then we should give the next one the opportunity to ask questions. Otherwise, we need to do it in a one-on-one session or with the IR team, please. I mean if we don't have enough growth opportunities, I mean, the first thing which is questionable then is why do you only pay out 50% of your profit as dividend because you cannot employ it somewhere. So that would totally change the dividend policy, but it's not a question of the cut then.

[Operator Instructions]. The next question is coming from the line of Rob Pulleyn from Morgan Stanley.

Rob Pulleyn. I rejoined to ask another question if that's okay. But given you've answered or not answered the question on Hambach, can I ask about U.S. deferred tax liabilities, a wonderful subject. A U.S.-exposed utility reported yesterday a large tax charge as projects reached COD and they entered into a tax equity partnership. So will we see a similar tax impact at RWE as it reaches COD on your U.S. projects?

The tax answer -- the question to the tax -- the answer to the tax question is easy. No, we don't expect any huge number. But maybe the situation is different because you said a U.S. utility because we don't have tax utility ourselves. So since we don't have tax capacity, our taxes in the U.S. are 0, and we need to actually bring in financing partners to reap the tax benefits. So the tax effect on our business is more or less zero for a long time.

No, sorry, Markus, I said U.S.-exposed company. It's actually European.

No, we don't see anything like that. And you blame me on not answering your Hamburg question. What was your Hamburg question?

No, Hambach, Hambach offshore.

Hambach. No, we want to say Hambach here. So that's probably you don't get a lot of money for some trees. No, I didn't answer the Hambach question because I said, I mean, this is the rumor and we don't comment on rumors. What I just can reiterate is, of course, active portfolio management is part of the strategy. But we will give you an update when we have taken a decision. And as long as we have not taken a decision to do something, we don't talk about it.

Are there further questions?

We have no further questions in the queue, so I'll hand you back to your host for any concluding remarks.

Perfect. Thank you all for dialing in. Stay safe and healthy and speak to you again latest at our Q3 results. Have a good day. Bye-bye.

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