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, Annika. Good afternoon, ladies and gentlemen, and thank you for joining us today to discuss RWE's result for the first six months of the year. I'm joined by our CFO, Markus Krebber, who will run through the presentation before we move on to Q&As 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. With this, let me hand over to Markus for the update on H1 2020.
Yeah, 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 EUR 1.5 billion. The RWE Group's adjusted EBITDA stands at EUR 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 EUR 0.85 per share for this year. Our net debt now stands at EUR 7.8 billion.
This is a decrease by roughly EUR 900 million compared to Q1. Our clear target is to meet a leverage factor of around three times adjusted core EBITDA to net debt at year-end. 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's 2.7 GW development pipeline in onshore wind and solar.
This gives us a great option for future growth and a broad entry into the French market. I will come back to that in a minute. Regarding our coal and nuclear business, we are pleased that the Coal Phase-out Act, which found broad consensus, was brought into German law. The 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 four. This transaction is a strategic pipeline enhancement and our broad market entry into France.
It strengthens our existing pipeline of 22 GW, 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 MW in operations by 2025. We are also pleased that this creates a great opportunity to enter the French market. 1.9 GW of the development projects are in France, of which roughly 300 MW 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 a pipeline and 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 MW; and Poland, a small position of more than 10 MW. What are the next steps? We have agreed an exclusive put option with Nordex on a purchase price of EUR 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 five. In our core business, adjusted EBITDA increased by 9% to EUR 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 hydrobiomass gas division mainly benefited from the resumption of the GB capacity market. The supply and 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 GW, but there is more to come in the second half of the year. 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 MW and a co-located 40 MW battery, which is due to be commissioned in 2021.
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 farm. The additional pro rata capacity is 300 MW. What are the next steps? The development of the project will continue with a view to participating in CFP auction rounds in three to five years' time. Furthermore, we welcome the announcement from the Irish government that the Dublin Array offshore project has been designated as one of seven relevant projects, meaning it will be fast-tracked through 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 consent application and investment decision, construction could begin in 2024 with COD in 2026. 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 US construction sites, so that we had to shift COD of approximately 500 MW from 2020 to 2021. Due to the adjusted commissioning plan, we expect the overall financial impact for this year to be a small to medium double-digit million EUR amount.
Please note that the PTC income level of the US 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, contracts 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 difference. As soon as wind farm testing is completed and COD is reached, we will report it as installed capacity. Good availability at the Cranell onshore site has been achieved, and the commissioning of the individual wind turbines 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 MW, will slip into Q1 2021, whereas the commissioning of Raymond East with 200 MW is expected in the second half of Q4 2020. COD of Scotia Ridge has moved within the fourth quarter to the end of December this year. On the basis of the adjusted timeline, construction work is on track. Commissioning ramp-up will start soon. 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 2021. 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 EUR 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 amount to EUR 316 million, mainly driven by Triton Knoll construction work. The sale of the Sea Breeze installation vessel is a 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 EUR 273 million at H1. Value drivers are an increase in capacity of approximately 380 MW 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 Casa Daga, 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 Limond ale, we confirm the outlook for the full year. The hydrobiomass gas division delivered a good performance over the first six months. Higher earnings results, mainly from the British capacity markets. 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 $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 EUR 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 coal firing, which we expect to last until November 2020. This will impact the outlook by a small to medium double-digit million EUR amount. Despite this, we also confirm the guidance for this division. Moving on to another quarter of favorable earnings development from the supply and trading division. At H1, adjusted EBITDA amounted to EUR 322 million on the back of a strong trading performance and good results from the gas and LNG business. We did not expect the division to replicate the exceptional performance of the first six months of last year. The division's outlook is EUR 150million-EUR 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 and nuclear division. Adjusted EBITDA has doubled year on year and amounted to EUR 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 EUR 795 million due to the high adjusted EBITDA of RWE Group. The negative effects in the financial result of minus EUR 150 million from Q1 were partly compensated by the E.ON dividend of EUR 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 carried forward, and the low taxation of dividends, including the E.ON and AMPREON dividends. 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, as when the nuclear provisions are utilized, they can be refinanced via financial debt.
In H1, the adjusted operating cash flow topped EUR 2 billion and is built up on the high adjusted EBITDA, as well as positive effects in working capital. The change in operating working capital of EUR 437 million is mainly driven by the payment from the British capacity market from 2018 and 2019, 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 EUR 7.8 billion. First and foremost, this was due to timing effects from hedging activities of roughly EUR 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 three times net debt to core adjusted EBITDA at year end, which considers the investment of approximately EUR 400 million for the acquisition of the 2.7 GW Nordex development pipeline. Volatility in commodity prices and interest rates could temporarily drive it slightly above three times, 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 EUR 2.15 billion-EUR 2.45 billion.
Adjusted EBITDA for the group will range between EUR 2.7 billion-EUR 3 billion and adjusted EBIT between EUR 1.2 billion-EUR 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 EUR 850 million-EUR 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, EUR 0.85 per share for fiscal year 2020. With this, I conclude my remarks, and I'm now happy to take all your questions.
Thank you, Markus. As always, in view of time, please stick to two questions only. Operator, please start the Q&A session.
Ladies and gentlemen, if you would like to ask a question, please press star one on your telephone keypad.
If you change your mind and wish to withdraw your question, please press star two. You will be advised when to ask your question. Our first question is coming from the line of Wanda Serwinowska from Credit Suisse. Please go ahead.
Good afternoon, Wanda Serwinowska, Credit Suisse. Two questions for me. The first one is on the negative power price. In the U.K., there is a clause in most of the CFDs to say that if the power price goes negative for more than six hours, then basically CFDs cease to apply for that time. Does the rule apply for all your assets in the U.K., and does the same or similar rule exist in other markets that RWE operates in? 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 NG increasing the annual target from 3 GW to 4 GW per annum. Thank you very much.
Yeah, 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. I mean, it has not had a significant negative effect, which was not planned for us even this year. For us, it's a minor technicality. If you want the details, I think please call the team also to understand where the German measure deviates 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 targets. I mean, our targets have been communicated a couple of months ago, so do not expect us that we give you new targets every month. When we deem it appropriate that we need to update the market about new plans or revise plans, we will do it, but we will not do it on a quarterly basis.
Thank you. I mean, 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 is not the issue for this year or next year, but we have seen more and more often negative power price on the market.
Yes, we will come back.
Thank you very much.
I mean, just a remark.
I mean, the moment it becomes viable, you usually, I mean, the team comes back. 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. 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 it incentivizes investments in flexibilities like batteries. If you get more of that, it will definitely take at first the negative power prices away. We do not see it as a big issue going forward, but the team will come back on the technicalities.
Thanks a lot.
Thank you, Wanda. Next question, please.
The next question is coming from the line of Vincent Izrael from JPMorgan. Please go ahead.
Yes, good morning. Good afternoon. Quick one. Could you provide us a bit more color on the Nordex pipeline, but at an asset level? We see the geography, so mainly it seems to be a footprint in the French onshore markets. We understand the strategy behind. It would be great if we could get a bit more color on the project level of all the big projects which are in there and basically what is the expected time for contribution there. That would be question one. 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 value-accretive?
Would you, in such a situation, consider potentially even funding larger acquisitions by reconsidering your stake in E.ON? Thank you very much.
Yeah, 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 do not see it as very relevant for the near future. 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. Acquiring existing assets asset by asset is not part of our investment plan. I mean, on the Nordex pipeline, 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 EUR 62-EUR 67, so you can see that that is very attractive. It was, on the European landscape, the one target market where we really missed the presence. It was really a good opportunity for us. We looked into the pipeline in detail, as you can imagine, in the due diligence. I mean, we have very good locations, good wind conditions, clusters in geographic proximity that will provide efficiencies.
I mean, again, I will not talk about specific locations now because the transaction is not closed and we are bound to confidentiality. 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 CO2s by 2021. On average, we would at least expect 100 MW from the pipeline per annum so that we have by 2025 another 500 megawatts under operations. Including the purchase price of EUR 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%-8%. Please, I mean, this is a very mature market and we had to buy it, so do not expect it at the upper end of the 4.5%-8%, but clearly in the range. We saw the price as attractive. I mean, it is 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 diligences in France. We know also how other pipelines look like. Just looking at it from the outside in, you have seen acquisitions in that market which were priced at EUR 150-EUR 250 per megawatt, and we are at the lower end of that. 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 then early-stage development.
Thank you very much.
Thank you. Next question, please.
The next question is coming from the line of Peter Bisztyga from BofA Securities. Please go ahead.
Hi. Yeah, thanks for taking my question. So just another one on the Nordex portfolio. Could you sort of tell us how the EUR 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 EUR 5 billion CapEx budget? Does it displace something else out of that budget, or is it in addition?
I guess if it's in addition, then where have you found that extra balance sheet capacity, please? My second question, actually, was just on carbon, which has obviously been very volatile over the last couple of quarters. I guess your supply and trading division might have profited from that. 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 the sort of mid to high 20s? Thank you.
Yeah, Peter, thanks for the question. On the Nordex pipeline, yes, it will come on top of the EUR 5 billion, as we have said with the announcement of the transaction. Now your question regarding funding. I mean, as I said in the speech, we expect to be within the leverage target of the three times net debt to EBITDA, including the EUR 400 million.
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 the 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 end the year at around 3.0. 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.
Later, the project investments after the, I mean, when we do CODs, that will be part of the capital allocation approach. Of course, as I hinted to, it will come on top of our existing targets. I mean, 100 MW here and there, that will not move the needle on a company of our size.
And carbon?
Sorry, carbon. Sorry, exactly, carbon. Yeah, I mean, even within the team here, we have two 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, 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. Maybe what is different this time than in the last financial crisis, in the last financial crisis, we have seen that 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 the huge program of the central banks and the fiscal support now, different.
Maybe some industrials take more 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 two camps, short term, long term. Since this market is nothing you can fundamentally analyze, it's always a sentiment question. I think the more dominant factor is definitely the mid-term to long-term political view. I can simply not imagine that if prices go down to EUR 15 again, that the politicians will sit there and do nothing.
Okay. Interesting. Thank you very much for that.
Thank you. Next question, please.
The next question is coming from the line of Alberto Gandolfi from Goldman Sachs. Please go ahead.
Thank you and good afternoon. 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 net liabilities, and the rest could be used for growth. Could you please confirm that? When it comes to growth, can you help us understand the logic? Would it be contingent to maybe a big offshore wind or perhaps to identifying something external like you just did with Nordex and maybe something even bigger? Secondly, just thinking about M&A from a different perspective, like RWE as a potential target. We are seeing oil companies very quickly moving into the space, BP with a 50 GW net target by 2030. A company like yourself would be like a plug and play, developing with existing capacity.
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?
Yeah, 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 LEAG net provisions. We just said we currently use it. We could also back the LEAG net provisions by other financial portfolios. I mean, when you look at the potential sourcing of financing, yes, I mean, we potentially need half of it to back the LEAG net provision, and the other half would be available to capital rotation. I mean, that has not changed. It is exactly what we said before. Usually, we have two questions, so you had 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. Thank you.
Because I think that's a more interesting one. I do agree that we could 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 plans 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. Existing pipelines become much more valuable.
I think the investors of big oil and others need to ask themselves the question whether it's really 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. On the question whether we could become a target or not, I think your company is well positioned to help the oil companies figuring that out and be still and wait what happens. Got it. That's speculation. I mean, that's not in our control. What can we do? I'm actually happy that also others see the field of renewables and the overall power sector as attractive because that's the core of our strategy. I think we have all the ingredients to be successful. We have the very experienced team.
We have a deep pipeline which actually needed to be developed over a decade. Of course, we have investment discipline and will ensure that we put the money where we get a decent return. 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 do not 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. Where I also do not see a limiting factor is funds because if you have good projects, I think investors are actually looking for investment opportunities. 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.
Thank you. That's great.
Thank you, Alberto. Next question, please.
The next question is coming from the line of Rob Pulleyn from Morgan Stanley. Please go ahead.
Hi. Yes, good afternoon, everyone. First question, Markus, is can we talk about the EU Recovery Fund and how do you think internally that RWE will benefit from this? As a second part to that, not a second question, can you help us understand practically how the money flows from a number on a presentation slide into actual projects? Because that still seems very unclear. 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? Thank you.
Let me start with the easier one, Rob. I mean, we are working on the lease extensions, and it will be around 800-1.2, 800 MW to 1.2 GW. We are optimistic that we can finalize it and by then book it as leases secured by the end of the year. It is going well. On the European Recovery Fund, let me start with the second part of the question. Yeah, I mean, I think we will learn about it over the next, let's say, two 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 it's just they have only little funds like the Just Transition Fund and stuff like that, where it'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. People are paying net in and getting money net out. What now as a next step needs to happen is that the individual countries need to come up with programs and plans where to invest the money. If that ticks all boxes, they will get their proportional share of the money. We need to wait for national actions where they're going to put and where they want to invest. 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, simpler financing. I mean, it's still totally unclear. 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. 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. 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 contract? 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.
I think the important step now is to get the right partners together and think it through what is feasible. You should usually start with the demand. I mean, who actually needs the hydrogen? Then you do backward re-engineer it. I mean, I think these are the big fields. Our current business already, so especially renewables and storage technology, and the new one which will come in addition is hydrogen. Also, I want to kind of not spoil the party, but I mean, if we talk about profits from especially hydrogen, probably we need to wait a couple of years before it is relevant in terms of investments, but also in terms of profitability. 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.
That's super interesting. Thank you very much. Good luck with the lease rounds. Thank you.
We will update you whenever we have good news.
Thanks, Rob. Next question, please.
The next question is coming from the line of Sam Arie from UBS. Please go ahead.
Hi. Good afternoon, everybody. Thank you for the presentation and great results today. I just wanted to ask two questions, one on returns and one on farm down. On returns, I think you had spoken at the CMD about 100 to 300 basis points spread above WAC as being typical in the renewable business. These days, 100 to 300 basis points does not actually sound that crazy as an estimate of the WAC, actually, as well.
I do not know, the lower the WAC, the lower the spread that you need to make the same kind of value creation ratio. It just seems to me that a year or two ago, it was common to talk about high single-digit returns in renewables or mid to high single-digit returns. I am talking about unlevered project returns. Are we now more likely to be going into the low single-digit returns territory? Is that possibly a fair outlook for offshore wind as well, where returns historically have been a bit higher? I would just love to know what your thoughts are about that at the kind of industry level.
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. If you like, the competitive pressure of auctions will mean that this kind of extra value arbitrage that you currently get in a farm down might eventually get captured by the consumer or the public body that's doing the tender. I'm just wondering, do you think that's a reasonable expectation? Have you thought about whether in the future you will sort of as standard go to auctions or tenders with a finance partner alongside? Have you talked to any specific funds or partners about that kind of long-term approach? Returns and farm downs. Thank you.
Sam, thanks. Thanks for the discussion.
I mean, on returns, I agree that we definitely see that the WACs are coming down. I mean, I also carefully read your report, and you also put now very low numbers to WACs, which I think is the right thing. I am not there that I would say we see now low single-digit returns for offshore. That is 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 WAC is significantly lower. When you talk about the absolute level, I am not at low media. 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 2022 horizon already, visibility of the profitability, I would not call that low. It is more medium. Farm downs, I am not sure whether I got your question. I currently do not see that you have tenders where you need to bring your financing or where you have an advantage if you do not go into the auction alone and getting an advantage when you already bring the financing partner. I have not 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 production becomes a dominant theme. That if you want to put money in some place, you need to prove that it is actually good for the regions where you get the lease. It is good for the people.
You create jobs. You use local suppliers. That is becoming more and more important. What I do not see is that it is an advantage that you already with the auction say that you are going to farm down or bring a financing partner.
Interesting. Okay.
Look. Does it help you or do you want to have a clarification?
No, no, no. That is fine. I do not want to take up too much time, but I am sure we will talk about this again. And thank you for two helpful answers just then.
We will. Thank you.
Thank you, Sam. Next question, please.
The next question is coming from the line of John Musk from RBC. Please go ahead.
Yes. Morning and good afternoon, everyone. Firstly, on the hedging of the outright books, it looks as if you have accelerated the fully hedged portion, particularly in 2022.
Obviously, it's quite a small chart, but from maybe roughly 30%-50%, which is probably more than you would normally do in a quarter. Just wanted to understand some thinking behind that. Is there a particular view on power prices or spreads at these levels? Secondly, on the three times leverage factor, just to 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. What we actually closed by that was the spread position. What you could read into it is if you think spreads are fair, it's part of de-risking now to close it.
I think if you look at current market prices and spreads, I think everybody expects 100% recovery by 2022. If you want to lock that in, you better close the position now. That is what we have done. That does not tell you what we—I mean, we do not know how the global economy will look like, but it is better to lock it in now than to keep it open. On the leverage side, the three times net debt to EBITDA includes our plans on capital rotation. It is our net investment target. I mean, we have outlined a net investment of around EUR 1.5 billion-EUR 2 billion per annum. If we are going to invest gross more given the profile, then 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. I mean, on the other things, we are considering our options. We will bring it to the net figure. I now do not want to speculate on gross and net because we always said that the leading metric is 13 GW net. Whatever we do on disposals, we will reach the 13 GW net. Also, the EBITDA guidance for 2022 is a net guidance. How we are going to achieve it is 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.
I mean, if you now want to get a comment on the rumors on disposals, the comment is no comment because we will update you when we have taken a decision. We will not update you whether we have on a certain asset a market test or not.
Okay. Thank you.
Thank you, John. Next question, please.
The next question is coming from the line of Deepa Venkateswaran from Bernstein. Please go ahead.
Thank you. My two questions. Firstly, in the U.S., 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 the conversion of your pipeline in the U.S.? Or practically, how might it change anything for you? My second question is on Germany itself.
Obviously, Germany has pretty lofty targets for 2030, but we're seeing the auctions are continuing to go under-subscribed on onshore wind. Do you see this situation changing with any kind of reforms? Would you be taking the lead as, I don't know, Germany's national champion on this to also grab maybe more of the share in the German renewables market? Thank you.
Yeah. 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, 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. I mean, that's pure speculation. I would say it will not make a huge difference.
On Germany, of course, we would like to do more in onshore and onshore in Germany. We see under-subscribed 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. There is some interesting development because the Minister of Economic Affairs, he tabled a law, a draft law yesterday or two days ago where they really want to accelerate the permitting process and the court proceedings. 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. That would be both very helpful.
Speedy processes, and you can go straight to the final court level to get a decision, and you do not need to go through the hierarchy. Also, nobody can, by pure tactics in the courts, delay projects. Let's see how the draft will go through Parliament. The draft version, at least, looks very favorable for the industry.
Okay. Thank you.
Thank you, Deepa. Next question, please.
The next question is coming from the line of Piotr Dzieciolowski from Citi. Please go ahead.
Hi. Good afternoon. It's Piotr Dzieciolowski from Citi. I have two questions. The first one would be a small one on Nordex. Can you say what's the kind of current cost structure of it? Is it a significant number, small number in annual euro figure as you take over the whole company?
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 restore longer-term equilibrium on the CO2 prices? What should we be looking at in terms of 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 to-be-developed projects. Part of that is also capitalized.
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, I mean, yeah, actually, the interesting thing is that the current CO2 price is already above the fuel switching price from hard coal to gas. The current stack in most of the times looks gas first, then lignite, and then hard coal. If you take out hard coal now, that shouldn't change the equilibrium for the CO2-relevant fuel switching price. There shouldn't be a change. The interesting element is, 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. 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. I would not overrate the annual price which causes fuel switching. That was, in the old days of oversupply, a good indicator. Now, with significant more tightness to come, maybe that's not the relevant indicator anymore.
Okay. Thank you.
Thank you, Piotr. Next question, please.
The next question is coming from the line of Elchin Mammadov from Bloomberg Intelligence. Please go ahead.
Hi there. Two questions for me, please. The first one is on negative prices. 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 if the prices stay negative for the subsequent few hours, your CFDs and whatnot, you can't recoup it yourself today.
Have you seen it being an issue with you for the second quarter? Do you think the negative prices will become more or less prevalent going forward? The second question is on hydrogen. Again, where do you think the value will lie? Is it in the production of hydrogen, transportation of hydrogen, converting it to other fuels like kerosene, etc.? Where do you think the money will be? Will you be a big player there? Thank you.
If I could answer the last question, life would be easier. I think it is too early to tell. It also depends on how the incentivization framework will look and how big the market will become. Of course, it has two angles. You can incentivize green production, and you can incentivize demand for green hydrogen.
In the end, it will be then kind of demand-supply on the different angles. Where I actually do not see scarcity is the production of green hydrogen in terms of electrolyzers. I mean, that is a proven technology. Where we definitely have scarcity already today is renewable projects because, I mean, if you believe all the demand forecasts, and I have no doubts 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 is just a question of time. This is really scarcity. On the demand side, I think that will be a competition by the off-takers. Who can do it cheaper? That is 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 off-take. I mean, we are currently also a very relevant player in gas trading and providing solutions to customers. That will also our role be in H2. You can do that without producing it as we currently do with LNG and natural gas. The first question on negative prices, I mean, for us, we have seen it in the U.K. and Germany, but it was not a relevant issue. It was not a big number.
Okay. Thanks a lot. Appreciate it.
Thank you. Next question, please.
The next question is coming from the line of Ahmed Farman from Jefferies. Please go ahead.
Yes. Hi.
Thank you. Two questions from my side as well. I was just wondering if we could get a little bit more color from you around the sort of how do you see the sort of 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. It's not a market where RWE had scale in the past. I was interested in understanding a little bit more how you see the sort of the value proposition from RWE. 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 opportunity.
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 be quite beneficial? Thank you.
Yeah. Ahmed, thanks for the question. I mean, 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. Now we have not only a foot in the door but a significant pipeline. The Nordex team was actually very successful in the French market. I think they ranked number two in terms of success rate in two auctions in the last year. They have not only built this pipeline. Their business model was to build.
When they were close to FID and they got them through the auction, they sold the projects to their potential customers. I mean, what is the value creation potential for us? I mean, we continue what they have done in the past, and we close our strategic gap. The team is not there just to deliver the pipeline which we have acquired. They will continuously develop projects. The French market overall is very attractive. It is 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. If you believe that onshore wind in France is good, it will definitely create value.
I mean, we are a firm believer that also the political environment in France and their targets to go straight from nuclear to renewables will not be questioned by some of the next governments. It is a very intact growth platform. The gaps in our pipeline, I mean, I think it is always good to be honest. I mean, if you look into that, we are very wind-heavy. Doing more on the solar side would definitely be good. Let's see how we can achieve it. I mean, 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. Still, it is compared to the wind side underrepresented.
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 is historically explainable because E.ON stopped, and Energy had also funding issues. We have a gap between 2022 where we will commission Triton Knoll. Maybe the next projects will be commissioned according to the current pipeline around 2025, maybe 2026. This is the profile how it looks like. If you ask me, you have two wishes. I would like to fill that time gap, and I would like to have more on the solar side.
Thank you. Very clear. Thank you.
Thank you, Ahmed. Next question, please.
The next question is coming from the line of Firmino Morgado from GLG. Please go ahead.
Thanks for allowing me. Hello.
Just, I mean, two quick questions. One, you've seen 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. 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. What we said is, let's participate in different technologies, be it concrete or be it steel. I mean, you have also different, I mean, I'm not an expert on that, but probably you have totally different approaches to that.
What we said is we want to be part of consortiums of several technologies to be an early learner. We want to learn how this stuff works because it is a bit different than fixed bottom. It is in terms of wind yield, in terms of maintenance costs, and so on. We want to learn that with different technologies. That does not 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. You asked for our role. Our role is we want to construct, and we want to operate also offshore wind farms. We do not want to build the turbines or the foundations.
Very clear.
Just perhaps to tie up with Alberto's question and the role of oil companies, do you envision, actually, that deep offshore will be better to do in joint venture or in conjunction with oil companies, that they've experience from offshore?
That's speculation. If you look at our partnership landscape, we are operating one offshore wind farm together with Equinor. They are a partner in one of our farms. One of the floating technologies we are in, we are together with Shell in. I think that can go the one way or the other. It's too early. We are open to discussions, but we could also do it ourselves.
Related question.
When I compare RWE and your strategy and what you want to be with the leaders in renewables, so in Europe, the grow in the 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 do not 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.
Since the core business, given our investment plans, will definitely grow, also the dividend should grow. We discussed it before. I said, I mean, a good proxy is maybe the EUR 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. That is the commitment we have given. We want to grow the dividend in line with earnings development in the core business.
If the core business, I mean, for whatever reason, cannot sustain, I mean, cannot grow, I mean, what is your commitment? You got 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.
I 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 over the IR team, please. I mean, if we do not have enough growth opportunities, the first thing which is questionable then is why do you only pay out 50% of your profits as dividend because you cannot employ it somewhere? That would totally change the dividend policy, but it is not a question of a cut then.
Thank you. Next question, please.
As a reminder, if you would like to ask a question, please press star one on your telephone keypad. The next question is coming from the line of Rob Pulleyn from Morgan Stanley. Please go ahead.
Yeah. Hi, Rob Pulleyn. I rejoined to ask another question, if that is okay.
Given you've answered or not answered the question on the Humber, can I ask about US deferred tax liabilities? It's 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. Will we see a similar tax impact at RWE as it reaches COD on your U.S. projects? Thank you.
The question to the tax, the answer to the tax question is easy. No. We don't expect any huge number. Maybe the situation is different because you said a U.S. utility because we don't have tax capacity ourselves. Since we don't have tax capacity, our taxes in the U.S. are zero. We need to actually bring in financing partners to reap the tax benefits. 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 a European name.
No, we don't see anything like that. You blame me on not answering the Humber question. What was the Humber question?
No, Humber. Humber offshore.
Humber. No, we want to sell Humber. Yes, no. That's probably you don't get a lot of money for some trees. No, I didn't answer the Humber question because I said, I mean, this is a 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. As long as we have not taken a decision to do something, we don't talk about it.
Fair enough. Thank you.
Thank you. 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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