Welcome to the RWE conference call. Michael Muller, CFO of RWE AG, will inform you about the developments in the first half of fiscal 2021. I will now hand over to Thomas Denny. Thank you.

Thank you, Jessica, and good afternoon, everyone, and thank you for joining us today to discuss RWE's results for the first 6 months of the year. I'm joined by our CFO, Michael Muller, who will lead you through the presentation before we continue with Q&A. Before we start with H1, let me remind you of our save the date for our Capital Market Day at 15th of November. Would have loved to meet you in person but given the uncertainties caused by the pandemic, we have opted for a fully virtual event. Nonetheless, I'm sure it will be a highlight in your H2 calendar, and I'm looking forward in our CMD in November. And with this, let's kick it off. Over to you, Michael.

Yes. Thank you, Thomas, and good afternoon, dear investors and analysts. Probably the most interesting news was already released 2 weeks ago, relating to the upgrade of our full year guidance. So let's start with this. On the back of an outstanding trading performance in the first half of the year, we have increased not only the guidance for the division itself but also for RWE Group on all KPIs from adjusted EBITDA to adjusted net income. This is great news, considering with a difficult start into the year. In H2, adjusted EBITDA of our core business stood at €1.2 billion, thanks to the high earning contributions from Supply & Trading. Adjusted EBITDA of the RWE Group reached €1.8 billion. Net debt significantly decreased to €0.9 billion mainly on the back of a strong adjusted operating cash flow, reduced pension provisions and margin inflows. Another great success saw the issuance of our first green bond at the beginning of June. The issuance met with strong interest in the market and was more than 3x oversubscribed. The bond has a volume of €500 million and a tenor of 10 years with conditions resulting in an annual return to maturity of 0.655%. The funds will be used for wind and solar projects. What is also new is that in the course of extending our syndicated credit line, we have linked the credit terms to 3 sustainability criteria. First, the share of RWE's renewable assets in the overall generation portfolio; second, the reduction of carbon footprint of other lease assets, and third, the share of green investments according to the EU taxonomy. This clearly demonstrates our commitment to decarbonize our portfolio. Another good news is our construction program. All projects are lined up to reach more than 13 gigawatts by the end of 2022. Having said this, 90% of our investments in the first half of the year are eligible under the EU taxonomy. Turning to the news from operations. Ahead of us are a couple of very interesting offshore auctions for which we have teamed up with experienced local players to form competitive consortia. We will join forces with Natural Grid ventures in the New York Bite auction expected in Q4. In Norway, we have partnered up with Equinor in Hydro Rhine in the tender for the SM-2 area announced for Q1 2022. On Page 4, you see the H1 performance on an EBITDA level. The adjusted EBITDA of the core business of €1.2 billion is driven by the outstanding performance of the Supply & Trading business. At €525 million, the earnings contribution in H1 2021, even top the previous year's very strong performance. Nevertheless, adjusted EBITDA remains affected by the negative one-off effects due to the Texas cold snap, which led to a loss of around €400 million in the onshore wind solar division. Furthermore, in H1, both wind divisions have suffered from weaker than normal wind conditions, particularly in contrast to the very strong Q1 last year, which was well above average. Our hydro biomass division provided a good earnings contribution, but slightly below last years. Group adjusted EBITDA included a solid performance from Coal/Nuclear and stood at almost €1.8 billion. This is comparable to last year's numbers and a good result. Turning to Page 5. With respect to operations, our wind and solar installed capacity stood at 9.3 gigawatts at the end of the year. After commissioning the 250-megawatt secured rich onshore wind farm and increasing capacity at Rampion by an additional 80 gigawatts as a result of our increased stake. As already announced in our Q1 earnings call, the Rampion transaction closed on the 1st of April and is economically as well as capacity-wise fully reflected as of Q2. Our Raymond West onshore wind park was commissioned at the end of July, so that the capacity increase and farm down will be reflected from Q3 numbers onwards. I'm really pleased to let you know that we have 3.9 gigawatts of capacity currently under construction with completion by 2022. With that, we will meet our build-out target of more than 13 gigawatts by 2022. In Q2, we have taken investment decisions relating to 400 megawatts mainly for solar projects located in the U.S. as well as solar and wind projects in Europe. These include our 150 megawatts fifth standard solar project in California co-located with a battery of more than 100 megawatts. Furthermore, another 23-megawatt onshore wind project in France has reached final investment decision as well as the 17 megawatts Sanbostel onshore project in Germany. All projects are expected to be fully commissioned in 2022. Given the recent discussions around component prices increases, I can reassure that all these projects meet our internal hurdle rate. So let's continue with the performance of the individual divisions. Ladies and gentlemen, adjusted EBITDA of the offshore wind amounted to €459 million, after the first 6 months. Earnings were lower as wind conditions in H1 have been much weaker this year, both compared to the normalized wind conditions but even more compared to last year's very strong wind levels. This was slightly offset by the full consolidation of Rampion. Gross cash investments of €1.1 billion are mainly spent for the construction of the Triton Knoll offshore wind project in the U.K. Construction at Triton Knoll is well on track. At the end of Q2, a total of 13 out of 90 turbines have been commissioned. Earnings from the commissioning phase are expected to kick in, in the third quarter and ramp up during the rest of the year. In addition, we have also allocated investments to the Sofia and Kaskasi projects. Offshore construction for the 342-megawatt Kaskasi project would start at the end of the year. And lastly, the deposit payment for 3 gigawatt offshore seabed lease awarded in the U.K. around four has further contributed to the cash investments. We confirm the outlook for the division of €1.05 billion to €1.25 billion for the full year. Moving on to the onshore wind solar business on Page 7. Adjusted EBITDA amounted to minus €42 million at the end of H1 for the division. The main driver is the negative one-off linked to the Texas cold snap in February. The financial impact remains unchanged from our guidance issued already in Q1 of approximately minus €400 million. The book gain from the file down of the Texas assets realized in Q1 partly compensates this. Both are indicated as nonrecurring items. The below normal wind conditions in H1 this year compared to the very strong previous year brought down earnings further. The additional capacity could not compensate for this fully. Gross cash investments amounted to €665 million, which is spread over various projects, such as the 200 megawatts Hickory Park solar project with co-located storage, as well as various smaller European projects. Gross investments stem mainly from the farm-down divestments, stem mainly from the farm down of the Texas projects in Q1. Overall, we can confirm the outlook of €550 million to €250 million for the full year. Our Hydro/Biomass/Gas division achieved an adjusted EBITDA of €297 million in the first 6 months of '21. Year-on-year earnings from the Dutch biomass operations have been lower in H1. This is a timing effect from the subsidy scheme that will revert in the second half of this year. Also, we no longer receive income from Georgia Biomass this year as we sold the asset in summer 2020. In contrast, margins have improved as we had a slightly higher income from the British capacity market and very good earnings from the short-term optimization of our assets. Altogether, the division performed as expected, and we can confirm the guidance for the full year of €500 million to €600 million. Moving to the Supply & Trading division. The Supply and Trading division realized an outstanding trading performance in H1, exceeding the already very high previous year's results. With an adjusted EBITDA of €525 million, the division has already surpassed the financial year 2021 outlook given in March. For the full year, we have increased the outlook for the division to significantly above €350 million as per our announcement at the end of July. Ladies and gentlemen, having now reported on the core business, let's move to the Coal/Nuclear division. Adjusted EBITDA for Coal/Nuclear amounted to €545 million. Year-on-year earnings increased due to a higher realized hedge generation margin. Nevertheless, costs associated with the German phase-out need to be considered and are expected to gradually increase throughout the year. Due to the flooding in Germany, in the middle of July, we experienced a damage at the Inden mine, and as a result, operations have temporarily been limited at the Vicevila power plant. Meanwhile, operation in the mine has started again and the mine has resumed coal delivery to the power station at full capacity. The estimated EBITDA impact will amount to approximately €25 million this year and €10 million next year. Despite this financial hit as a result of the flooding, we can confirm outlook of €800 million to €900 million for the full year. Moving on to the earnings drivers down to adjusted net income. Adjusted net income amounted to €870 million in H1, which is in line with the positive development of adjusted EBITDA. The adjusted financial result is slightly higher than expected for H1 and mainly linked to negative interest and higher interest costs for FX derivatives. The adjusted financial result includes the E.ON dividend of €186 million, which was paid in the second quarter. Year-on-year, the adjusted financial result has significantly improved as we recorded a negative one-off last year. Adjustments in tax are applied with a general tax rate of 15%. Adjusted minority interest have turned positive at the end of June due to an extraordinary effect related to deferred taxes in the U.K. After the increased U.K. tax rate from 2023 onwards became legally effective in Q1 this year, deferred tax liabilities had to be increased with a negative impact on minority shares of earnings. For the full year, we expect adjusted minority interest to be around the guided level of around minus €100 million. And now on to the adjusted operating cash flow on Page 12. The adjusted operating cash flow describes the impact on net debt from operating activities. It is adjusted for special items and other effects that balance out over time. In H1, the adjusted operating cash flow amounted to €1.7 billion and it results from the change in provisions and noncash items as well as the positive effects in working capital. The latter is mainly related to the decrease of trade receivables from energy sales after high levels at the year-end 2020. Turning on to the details of the development of net debt on Page 13. Net debt decreased significantly to €0.9 billion. Besides the very good adjusted operating cash flow, this relates to timing effects, amongst other variation margins from hedging activities. Due to the latest increase in commodity prices, we received questions on expected margin inflows in the coming years. We will expand our disclosure going forward and provide details on the net variation margins for our power generation activities over the liquid tenor and respective cash outflows. This includes margins from the sale of generated electricity as well as margins on the respective fuels and CO2. For H1 2021, we recorded a net inflow of margins for power generation hedging of €0.4 billion compared to last year. As of June 30th, we have accumulated a net position from variation margins for our power generation of €1.9 billion, which had a positive impact on net debt. This position will unwind over the next 5 years. All these numbers are, of course, based on the assumption of stable commodity prices. Another driver is the change in provisions and pension provisions by roughly €800 million, resulting from higher discount rates. If commodity prices and interest rates remain stable, the leverage factor should be well below 3x net debt to core adjusted EBITDA at year-end. Finally, moving to the outlook for the fiscal year. As I mentioned before, exceptionally high earnings from Supply & Trading have led to an increased earnings forecast for fiscal year 2021. Therefore, in July, we upgraded our outlook for this year. We now anticipate that adjusted EBITDA of the core business will range between €2.15 billion and €2.55 billion. Adjusted EBITDA for the group will now range between €3.0 billion and €3.4 billion and adjusted EBIT between €1.5 billion and €1.9 billion. Furthermore, we also increased our guidance for adjusted net income, which now ranges from €1.05 billion to €1.4 billion. We confirm the dividend target of €0.90 per share for this year. An update on the dividend policy will follow at the CMD in November and will focus on the need to balance both growth and dividend payments. It will be based on group earnings, and we need to consider the decline in coal and nuclear results in the next years, which need significant green investments to compensate for it. As we also received a lot of question on the impact from the further -- from the future higher U.K. tax rates, we expect our general tax rate to increase accordingly to 20% in 2023. With this, I conclude my remarks, and I'm now ready for your questions.

Thank you, Michael. Operator, can we start the Q&A session, please. Start with the first question.

[Operator Instructions]. And the first question comes from the line of Peter Bisztyga from BofA Securities.

So first one just on component price inflation. Your comment on IRRs earlier was sort of slightly cryptic. And I'm just wondering whether you're saying that you are seeing some cost inflation, but you're managing to keep IRR stable or you're not seeing any cost inflation. Can you just sort of clarify what your exposure is? Are you seeing any turbine OEMs try to renegotiate contracts? Any color on that would be very helpful. And then on the -- my second question was on your variation margins. Thank you for the additional disclosure. That's very helpful. But I'm just wondering if you could split out what happened in Q2 versus what we saw in Q1, please, on those numbers?

Yes. Peter, thanks for the question. I mean on the component prices, I think the message we want to send is you need to look at that in different kind of time horizon. First of all, all the projects that are under construction, we have fixed contracts, so no exposure to commodity prices. Obviously, those projects, which we're still developing, there are potential discussions with suppliers on prices. Obviously, it's not all the ideas in the end get realized. And secondly, obviously, also steel prices are only a small portion of the overall CapEx. And when you look at the investments, this -- return calculation, there are also important other elements than just the component prices. And the message we want to send is that you shouldn't be concerned that there is any impact from that on our returns. So they're still in the guided range of 100 to 300 above our cost of capital as we have guided that. And obviously, any projects in the foreseeable future, we need to see what really happens to commodity prices, if they are on this high level on a lasting basis and that probably also then has impact on auction prices and so on. Yes, I mean talking about variation margins, I would hand over to Thomas to give the exact number.

Yes. Thanks, Peter. I actually don't have the number with me, but I'll pull up after the call and get that to you after the call in the afternoon. Is that okay?

All right. Yes. Thanks so much.

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

So I have two, please. The first one is, again, on cost inflation, just to be a bit going a little bit deeper here. Would you agree that there is a bit of a larger risk in the offshore business versus onshore. So onshore I mean I'm not talking about the 3.9 gigawatts you are developing right now. I get that on those costs, procurement costs are fixed. But would you say, for instance, on Sofia that the moment you are bidding versus the moment you're actually paying the bill for the equipment or perhaps you haven't fully contracted all transport vessels. That leaves some exposure. Am I right in thinking that? And maybe I don't know if you can quantify any of it. The second question is theoretical. I hope you can answer, if not, I have a backup question, if you don't mind. But the question is, we have been reading in the press, the possibility of perhaps with the new government coalition shutting down your lignite activities in 2030 instead of 2038. Considering the very successful financial hedges you've already put in place on carbon, under that event, do these contracts give you the possibility of sitting on a long carbon position that you may be able to monetize before 2030. So could you sell some of the excess allowances at 57%, 58%, and maybe you pay 20, 25, 30 and booking monster capital gains for a few years?

Yes, thanks for the question. I mean the first question on offshore onshore, more risk exposed is I mean yes, offshore is slightly higher exposure simply because there is more steel involved in those projects. That's fair to say. And you are also right, there are some time mix between kind of auctions and when you take kind of the financial -- the investment decision. On the other hand, I think also offshore projects offer more opportunities to optimize the project. So when you talk about turbine size or O&M activities because, I mean, relative to the overall business case, these aspects are much more relevant for offshore. So coming back to your hypothesis that offshore is more exposed or less exposed, I wouldn't follow that argument. The second question is around the coal exit. I mean you phrased it as future assets. I mean it's clearly speculation now. The contract itself foresees coal closure by 2038, it has the option to bring that forward to 2035, that's what is in the contract. I mean, the contract doesn't say anything about our carbon certificates. So that's basically our topic. But bear in mind, I mean, the hedges we currently have in place are to match the implicit exposure we have from the fleet. So I mean, kind of in a nutshell, what I tried to say is, yes, we are obviously internally discussing what are potential options. But it's too early to say anything here, and we just need to wait what really happens. But I mean, overall, I think we are very happy with the hedges we have in place given the current development of development prices. That's for sure -- for commodity prices. That's for sure.

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

Rob Pulleyn from Morgan Stanley. So can I follow up on the question on inflation, and I suppose this is a sort of a multi-barreled question. Is -- I presume you have CapEx contingencies per project. And I was just wondering what percentage of CapEx that might be? And where is cost inflation sort of eating into that, i.e., are those contingencies standing strong? Or have they already been absorbed. I think that would give us a lot more color around the degree of risk on the IRR targets. And I suppose the second question associated with that, as you mentioned in your prepared remarks, Kaskasi will sort of suppose start spending in 4Q. I was wondering if any of those costs are locked in before the framework agreements, warehousing steel, et cetera, et cetera.

Yes. I mean let's start with Kaskasi. So yes, everything was locked in. And as you rightly said, in the second half, it will kick in. Talking about the contingency. Obviously, I can't reveal now what contingency we typically have in those projects. But I mean, yes, we do have contingencies in there, and the contingencies are -- I mean, one of the reasons for having contingency is also a price volatility. So that's for sure. So therefore, what I definitely can assure that there is sufficient contingency in the project to cope with price increases, but exact numbers, I obviously can't reveal yet.

No, that's -- that's understandable. And thank you for the color, that's fantastic. If I may sneak in a follow-up, which is actually on a different question. But I think we've all seen these quite remarkable divergence between coal spreads and gas spreads in Germany. I was wondering from your perspective, how long you expect this to be prolonged?

I think that's -- we don't need a crystal ball to give you an answer on that. I mean, we are -- of course, we do have a view. But then there's also a second question on whether we can share with you or not. So please understand we cannot really comment on the future or commodity prices in this call.

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

So my two questions. So firstly, on the variation margin, could you just help understand a few numbers that I'm grappling with. So I think you mentioned that there was an inflow of around €400 million in H1. How do I reconcile the €3.3 billion that you show as other changes in financial debt on Page 13? And then I also read in your note that fair value adjustments to OCI has offset impairments in the lignite assets of around €800 million. So I'm just trying to reconcile this €400 million, €800 million and the €3.3 billion. So that's the first question on variation margin. And maybe there is something else also going on, if you can just help understand what is the delta between the €3.3 billion and the €0.4 billion. And I think second question is on your stake in E.ON. I believe we're probably at the point where maybe you are permitted to basically go down to whatever level you want. How are you thinking about the E.ON stake? Or do we sort of need to wait for your CMD to have more clarity on where the stake being out in the bigger picture?

Yes, Deepa. So maybe we explain what in this other changes in net financial debt. So there are various elements in there. One is the one around margins from our generation hedging. As I mentioned, that includes not only CO2, but also the fuel and the power we sell, yes? And we believe this is important to communicate because that kind of needs to be put into perspective of what we communicate as a guidance for the conventional segments because, obviously, the guidance includes the hedging. So therefore, we want to avoid that, that's a double counting of this element. What is else in there? I mean there are variation margins from our trading business, which are, by nature, pretty volatile. This volatility states that it's clearly not linked to the performance. So that's just related to the positions. So there's volatility there. Then you rightly -- or implicitly mentioned the CO2, the strategic CO2 position, that's also included there. But there are also effects in like the -- the cash we received back from a tax audit related to periods -- former years so before 2012, that's also included in the numbers. Your second question around the E.ON...

Can I ask a follow-up on your answer, sorry. So the €800 million is kind of on top of the €400 million. And for the middle chunk, right, the trading business, should we assume that this will unwind because obviously, when we're thinking about net debt for next year and so on. I suppose we want to know how much of this would unwind in the ordinary course of business, so within the next 6 months or so. And therefore, you should adjust for that valuing you?

I mean the trading piece is, as I said, pretty volatile. So that probably will unwind in the next -- this year or in the next years to come. So rather short term, but you never know how kind of commodity prices develop, so that can also well be in a different direction. And I mean concerning your numbers you deducted from the OCI, you also need to be a little bit careful that is not directly linked to those 2 numbers. Then the next question around the E.ON stake. I mean, as you know, the E.ON stake itself is not of strategic importance for us. So we have always said that if we have attractive opportunities to invest, we would also use the proceeds -- at least the excessive proceeds from the E.ON stake because you know that we have put also the E.ON stake against our lignite provisions. So part of that is blocked against this one. So there is definitely some headroom which we could use for investments. But I mean, if you look at the -- our financial situation, there is currently no need to dispose that asset. And as we also mentioned, there is currently a tax benefit as long as we keep 15%. So therefore, that's the trade-off in the end. We need to take what is our view on the stake. Do we have investment needs? And is that the best financing in the moment of time or not.

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

I'd like to ask one on the coal side and one on the renewable side, if that's okay. On the coal side, look, I think Alberto mentioned earlier, the discussion in the press about potentially some political groups wanting to bring the coal exit target forward. And I think my understanding is you have some protection against that from your existing signed contract. But can you just comment on the provisions in that contract around the state approval? I think I'm right in saying, even if there was a problem with state aid, the contract is still valid. But could you just walk us through the details of that, so we'll kind of understand. And then secondly, on the renewable side, so we focus on the positives, too. Look, I just wondered if you could comment on your latest thinking around the U.S., we've obviously seen the big infrastructure bill go through, and there's talk of a €3 trillion, €4 trillion additional reconciliation bill with a lot of money in it for the clean energy sector starting to make the U.S. look really like an outstandingly interesting market. And it'd just be really interesting to hear from you how you how you're thinking about the U.S. and how important the U.S. seems likely to be in your planning?

Yes, thanks for the question. I mean on the €2.6 billion, as you know, the European Commission currently reviewing it. That's the process. Obviously -- I mean, we are not a direct participant in that process because it's formally the federal government of Germany. But obviously, we are involved and we are supporting. Unfortunately, I cannot comment on that process. It's ongoing that we are now exchanging questions, and we need to see where it takes us. But I mean as we have communicated previously, we are very confident with the €2.6 billion. And in the contract, there are provisions that in case we don't get the €2.6 billion. We need to find measures that kind of bring us in a similar position as before. So that's how the contract stands and we now need to see how this approval by the year commission follows. But as I said, we are confident with our arguments here. I mean the other aspect which I like to mention is we are obviously now having quite some discussions in Berlin around the way forward of conventional generation and renewables. And what politicians are really realizing is that the important lever to bring down coal is to build out renewals. So therefore, also their focus clearly is on to find ways how to accelerate and ensure a sufficient build-out of renewables. And when that happens, there will be automatically the impact on coal. And I mean you can obviously understand that also given our business model, this is what we are pushing. So we are providing support to the government on what are relevant levers you need to pull in order to accelerate the build-out because I think it's first good for the decarbonization of society. And secondly, also perfectly matches our business model. So that's the direction we should take a look on. Question around the U.S. I mean, one is the strategic, we clearly see the U.S. as one of our core markets. And I think also the whole sentiment is as in Europe, shifting towards more renewables and also the infrastructure, I think, is an important element because it leads to investment into grid infrastructure, which is also important to cope with more volatility you get from the renewable build-out. So definitely leading in the right direction. But it's too early to comment on the exact impact because it's not yet clear how legislation and impact on renewables will exactly be. So that's something we are carefully observing but a clear strategic direction for us is continued build-out in the U.S. because we feel it's an attractive market going forward.

Very helpful on both topics. If I may just say as an observation from my side, it seems as very striking to me the relatively low valuation the market puts on your renewable business, especially when you factor in the exposure you have to the U.S. and to Europe and the fact that you don't have exposure to some of what some people might think are lower value geographies around the world, Latin America, Africa, some bits of Asia and so on. So I just think it's great to have that discussion with you about the U.S. in the mix of these other points.

Perfect. Well, appreciate it, your comment

The next question comes from the line of Lueder Schumacher from Societe Generale.

Two questions on my side. The first one, quite straightforward. Did I hear you right that you say the variation margin as of the end of June is €1.9 billion. And if not, can you confirm what the total variation margin as of the end of H1 is? My second question is also quite straightforward. On Slide 10, you mentioned higher realized hedge generation margins is one of the reasons for the performance. Is that just versus 2020? Or has the old hedge of €32-megawatt hour actually improved?

Yes. Lueder, thanks for the question. I mean, first, on the variation margin, as I also referred question of Deepa. So the €1.9 billion, that's the accumulated value of the hedge variation margins related to our power hedging in the liquid tenor. So related to power, the fuels and CO2. However, in the position, the accumulated position of other changes in net financial debt. There are other margin payments in, as I said, for the trading business, but also for our strategic position, but these are positions for kind of, yes, market competitive reasons, we can't reveal. Yes. But the first one...

If you can't reveal details on this, this is fine, fair enough. But I think in order to work out the relevant total net debt number, it would be quite helpful to have a total variation margin across all business lines, not just power hedging. Is that something you could share with us?

Yes. I think the -- you need to take a view on what you need to reflect in your model. And could be shared with you is really the margin or what is inflated to our liquid tenor on the hedge period where we're also giving you a certain earnings guidance. And that's in our -- that's what we disclosed in order for you to be able to compare apples to apples. And I think it's important here and it really differs potentially and also for how you look at the other bit of course. We have also received inflow of margins, but then it really depends on how you have built up your models and how you reflect that in your valuation. And therefore, I think it's not possible to give a general answer because it's a very specific question but we can, of course, go into more detail, we understand how you look at the formulation perspective. And then I see how I can help you with that. But I think difficult to answer on this call.

Yes. And the second question -- the second question, Lueder, you're right. So the increase is related to the previous year.

Okay. So still €32 megawatt hour?

Yes.

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

I think questions regarding suppliers and [indiscernible] already out. So a lot more is related to CO2 anyway, given those are prices are the mission, which is the hedging. It's a material information, which needs to better understand its exposure going forward. It being either in the profitability outlook or from a balance sheet point of view. So it's a straight question, I'll ask it just in case this time it works is how many allowances do you have? And otherwise, you say you fully hedge until 2030. So does it include the CCGT fleet as well? What load factors for lignite and CCGT do you assume so we can try to do some work with this.

Sorry, I didn't get the first question.

Basically, I'm asking either straight how many CO2 allowances do you have? If you don't want to give that, I'm saying, you say you hedge until 2030. So does it include the CCGT fleet when you say you're hedged. And if so, what load factors are you using for your fossils in lignite, CCGTs. So we can work something on those lines. I do have some number already, but it's difficult to be sure about?

Yes. So I mean please understand that I can't reveal the number of CO2 certificates we have on our balance sheet. But I think what is important is to understand how do we hedge and you have to distinguish between 2 different aspects. One is, and that's where we gave the guidance on the variation margin, it's the liquid tenor. Obviously, in the liquid tenor, whenever we sell power, we also buy the CO2 that is required to produce that power. So in that period, it's a clear hedge between power and the CO2 you need. And that's obviously where you also have higher volumes of CO2, but you need to submit those to the days that -- in the year after you produce it. So that's the one element. The other element is then further years out, where we have the strategic position. And what we have hedged there is only to bring our portfolio in line with the market. Because if you look at our portfolio, we do have a higher exposure to carbon than the German portfolio. And that's why this delta is hedged by CO2, so that effectively whenever CO2 prices move up, that should compensate for the delta that is not -- the power price is not moving up, so that financially, our position always stays the same. And if you look what we have observed in the last months, this hedge is actually working perfectly fine.

So you're saying that the strategy you had, which was for a medium term before, where basically you stay exposed to just the evolution of the fossil -- synthetic fossil?

As Michael said in the first year, I mean, we are always -- in the first 1, 3 years, we always fully hedged thereafter. We are implicitly hedged. We just have the exposure for the gas spreads or [indiscernible] depending on how the market looks like. But that covers the -- let's say, the liquid tenor of the hedging. And that's where we also have from us received an earnings forecast. For this year, for next year, for the nuclear already the year. But that is clearly separated from, let's say, the illiquid tenor, which is for the second half of the decade where we have, as Michael said, only hedged our excess carbon intensity versus the market. But of course, you cannot hedge any power or fuel or carbon emissions because it's still too far out and you don't have a liquid power price for the year. And that's why you need to actually separate both topics from each other. And that's why we have also clearly disclosed the valuation market related to the earlier parts of the illiquid tenor where we have also given you the earnings guidance for that.

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

Yes, two questions from me. Firstly, bigger picture with the balance sheet in better shape and we can discuss variation margins at another stage. But how do we -- how are you thinking around capital allocation now between organic opportunities and the need to potentially gain additional foothold through acquisitions. I know this is perhaps something that will be dealt with more at the CMD, but should we be considering acquisitions are still very much part of your strategy? And then secondly, perhaps more simple. Can you just strip out from the H1 numbers, the negative impact from lower wind speeds in EBITDA?

Yes. John, let's start with the easier one. So that's the impact. I think on the offshore wind business, it's around €150 million year-on-year. And in the onshore business, it's €50 million year-on-year. So in the segment that you have from lower winds compared to the very high winds we had in the previous year. I mean, your question around the balance sheet. I mean, to understand our view. I mean, clearly, we are set up with the whole organization to grow the business organically. So the priority is on organic growth. However, having said that, if there are attractive opportunities out in the market, I mean, like we demonstrated with the Pegasus pipeline, which we believe perfectly fits our portfolio, and then you can also get them at an attractive price, that's definitely something we are looking at. But the clear perspective -- the clear target is to grow the portfolio organically and that's where we also need our balance sheet for. And as I said, we are well prepared to pursue that.

[Operator Instructions]. And the next question comes from the line of Olly Jeffery from Deutsche Bank.

Two questions for me as well, please. The first question is just looking at build-out. So the full year results, the residual target to get to the 13 gigawatts by 2022, it was 1.1 gigawatts, which obviously, you've now found within 6 months. Is that kind of an appropriate run rate that we could expect to continue in the second half? And at what point when you're finding products in 2022, for example, do you expect that they will be built by the end of the year? Or are they more likely to contribute to 2023, just to help think about where you might end up for 2022 in terms of assets constructed. That's the first question. And the second, please just on Supply & Trading. I know you've been asked before, but I just want to go back to it again. I know your long-term guidance for this is €250 million EBITDA a year. I guess is there any level of profitability that you'd see in the business that would make you change that because the number of quarters in a row now where we've been in excess of what you see as normalized levels. It's gone up for quite a long time now. So is there any point where you might reassess that guidance in terms of what you expect to be achieved in that division?

Yes, thanks for the question. I mean, first, on the build-out. Obviously, you are right in assuming that we continue developing projects and taking FIDs. Actually, the numbers we report are the numbers at the end of half year. And since then, we have already taken additional FIDs. So that's continuing. But obviously, the closer you get towards the end of 2020, the less likely it is that those projects will contribute to the number by the end of 2022. I mean what we've guided is to be at 13 gigawatts plus. We said when we acquired the Pegasus pipeline, we would add another 100-megawatt per annum on top of that. So that leads you to a number more around 13.2 gigawatts which I think is a fair number to assume for the end of 2022, yes? And obviously, then the rest will continue to contribute to later years. And these are topics we -- obviously, I want to discuss with you at the Capital Market Day because there we want to provide you with a longer-term perspective. I mean, referring to the Supply & Trading business, I mean as a former CFO at Essen, I'm obviously very delighted by the continuous good performance. But we still feel, given that is -- it is a volatile business that we are very confident with the guidance we have out between €150 million and €350 million. But I mean, you probably know how the trading business works. There is a assymetric profile, yes? So you have downside protection because of limits in place and stop losses at place. But obviously, if you have the right positions in place and the market is developing in the right direction, you let it go. And then you have kind of significant upside, which actually happened in the last years, yes? So in a nutshell, we are still very confident and happy with the guidance we have out, and that's also what you should assume for the years to come. Yes, not increase fund, right.

The next question comes from the line of Tancrède Fulop from Morningstar. Tancrède Fulop: I have two. The first one on dividend. Last year at your Capital Market Day, you guided for dividend for steady growth in line with core business, so excluding coal and nuclear. And today, you made quite cautious comments saying that we have to take into account the earnings decline from coal and nuclear investments required, which might imply cuts in the absolute amount of dividend. So what's changed between now and last year at the Capital Market Day when you issued your dividend guidance, is my first question. And the second one on your CCGT in light of the current commodity environment with very high gas and CO2 prices and given your hedging, what kind of evolution of profitability of your CCGTs can we expect next year and the year after?

Yes. Thanks for your question. On the dividend, you have carefully listened to my comments, that is good. But I mean, to give you a clear signal, we don't expect any dividend cuts. So that can be excluded. But on the other side, I mean, we do see attractive investment opportunities going forward. And therefore, we also want to make sure that we have sufficient investment power to follow those investments. And that's why we want to communicate, look at the development of the core business. There won't be any cuts but it's probably a little bit more muted to invest into new projects. And obviously, then with a well-developing business, that should also then be more upside for the dividend to come at later years. Around the CCGTs, I mean, with CCGTs, you have to be a little bit careful because there are different value streams contributing to the CCGT. This is obviously the wholesale margins on the spreads is ancillary income, but it's also the capacity market. And I mean most of our CCGTs are in the U.K. and the way the U.K. capacity mechanism is designed to kind of fund the missing money. So if you earn more on some of the dimensions that could -- that will eventually compensate that in the other elements. So I would rather expect stable incomes from the CCTGs here, so not an increase.

The next question comes from the line of Piotr Dzieciolowski from Citi.

I actually have a one two-part question. I wanted to ask about this cost inflation effect on the market. Have you seen some of the PPAs or some of the auction prices going up with developers trying to pass it through? And if not, then when would you -- shall we expect this kind of behavior? And then has this different cost of development on the CapEx change the way some of the smaller players behave on the market, maybe they wanted to sell some projects because they didn't get some financing. Has there been any impact on how the market will operate?

I mean let's first talk about the impact of cost inflation on the market. And I think that perfectly also reflects kind of my comments, as I said earlier. In the end, you need to look at the bigger picture, yes? So pressure on component prices from the suppliers is one dimension. But in the end, you need to kind of consider is that really impacting the return of the projects and what are the overall economics. So therefore, there are more drivers in the market than just requests or push from suppliers to increase prices. I mean on auctions, we haven't lately seen much auctions, so let's observe what happens in the new auctions to come, but that's probably a more medium-term effect. And are the same is true for PPA prices. I mean what we observed with PPA prices is clearly, at least in Europe, that there is more demand for PPAs. I mean, with more commitments towards decarbonization and also our customers laying out a clear commitment to procure green power, there is an increasing demand for PPAs and that may potentially also have impact on PPA prices. So in a nutshell, I think there are more impact -- multiple factors impacting the prices going forward, and that's the important part. Around smaller developers, I can't comment. I haven't seen anything like that yet.

Okay. But have you seen maybe more pipelines coming for -- because people can't develop them or can't squeezing their margins, so?

No.

There are no further questions in the queue. So I'll hand the call back to your hosts for some closing comments.

Great. Thank you, Jessica. Thank you, Michael, and thank you all for dialing in. And that closes the call for half year 2021. I'm looking forward to later for our Q3 numbers on 11 November and of course, at our CMD in a few days thereafter. Have a good day. Good summer, Stay safe. Bye-bye.

Thank you for joining today's call. You may now disconnect your lines.