Earnings Call: Q4 2018

Mar 14, 2019

Thank you very much. Good morning to everyone on the phone and to those of you who are joining us via webcast. I am joined here by Rolf Martin Schmitz and Markus Krebber for the presentation on fiscal year 2018 and the outlook for 2019. Rolf will give you a strategy update focusing on the progress of our transaction with E.ON, as well as the status of the discussions around the German coal phase out. Markus will provide details on our 2018 financial performance and the outlook for 2019. As always, in order to focus on your questions, we have kept it short. Let me hand over to Rolf. Thank you, Gunhild, and hello, ladies and gentlemen. 2018 has been pivotal for RWE's future. We have laid the foundation for the transformation into a fully operational company again, with a strong and sustainable platform for future growth. With the envisaged asset swap with E.ON, we are creating the leading renewables player. The combined platform will be the third largest in Europe and number 2 in offshore wind globally. More than 60% of our generation portfolio will be CO2 free or low carbon emitting. It is also this part of the portfolio on which we will focus our future growth efforts. The execution of the transaction is well on track and fully within our timeline. We are also making good progress with integration planning to ensure a swift and smooth integration of the new businesses. After intensive analysis and work, the Commission on Growth, Structural Change and Employment presented its final report at the end of January. While the Commission's proposals will have wide-ranging implications for RWE, we believe that they provide a good basis to achieve mutual consent on plant closures, providing planning certainty for our lignite operations. Irrespective of the discussions on the coal phase out, we continue with our own efforts to reduce RWE's carbon emissions with changes to our generation portfolio. Last but not least, we decided to propose to this year's AGM the conversion of our preferred shares into common shares. With this step, every share will bear a voting right, which is customary on international capital markets and called for by many institutional investors. The proposed conversion aims not only to strengthen our corporate governance, but also to improve our shares' trading liquidity. This is in the interest of all RWE shareholders. Let's now have a look at the progress of the transaction with E.ON. We are well on track with the execution of the transaction and have taken important steps in the integration planning. Since our last results call in November, we have reached some major milestones. Most relevant filings with competition authorities have been submitted. We have appointed the future renewables management team under the roof of the RWE, and we have formulated a high-level strategy for the renewables business. Slide 6 gives you an update of the transaction timeline. Let me underline here that we are fully in line with the original timetable, which we communicated when we announced the transaction. As highlighted on the slide, we have submitted all relevant filings to the respective competition authorities. E.ON also filed their part of the transaction with the EU Commission on January 31. I am pleased to say that the European Commission has already given competition clearance for our acquisition of the E.ON and Innogy renewables operations. At the same time, the German cartel office approved our acquisition of a 16.7% stake in E.ON. Both approvals are good progress for the transaction. Outside the EU and Germany, we have filed the acquisition of the E.ON stake with the CMA in the U.K., and the acquisition of the U.S. E.ON assets with U.S. antitrust authorities will follow shortly. We still expect the transaction to close in summer this year, and we are very much looking forward to that. on January 17, we announced the future management team and presented the target operating model of the combined renewables business. The team will be headed by Anja Dotzenrath as Chief Executive Officer, who is currently CEO of E.ON's renewables business. It will further consist of Holger Himmel as Chief Financial Officer and Tom Glover as Chief Commercial Officer, who will be in charge of the commercial management of the renewable assets. Holger is currently CFO at Innogy Renewables, and Tom brings his extensive expertise from RWE, where he is currently responsible for the commercial asset optimization of our conventional generation fleet. The team will be completed by three Chief Operating Officers who will lead the operational units and be responsible for project development as well as construction and operations. We are excited to have been able to nominate a highly qualified and diverse management team with extensive expertise and international experience in the field of renewable energy. Before Christmas, we also concluded our high-level strategic considerations. The transaction is going to create a leading renewables player in Europe with a strong position in the U.S. However, our clear strategic ambition is to take this newly created platform and build a truly global renewables player. The focus will be on the three leading technologies: wind onshore, wind offshore, and solar PV, aided by storage technologies, where we continue to cover the whole value chain from development through to commercialization. We will continue to grow the portfolio in Europe as well as the Americas, but also want to enter selective new markets in Asia Pacific. We have a growth ambition of some 2-3 gigawatts per year, for which we have roughly EUR 1.5 billion per annum of our own funds available. This is a net figure, which will be complemented by potential farm downs, partnering, and external financing. You see, these are ambitious aspirations, but we are excited by how the two renewables businesses have progressed over the last 12 months, and we are confident that the new team will drive the business forward once the transaction is closed. They will also develop and define the high-level strategy further, on which we will provide more details after closing. Let's now have a look at our current business portfolio. Slide 9 provides an overview of selected focus areas of our three segments. Within the lignite and nuclear segment, we have turned our particular attention to the decommissioning concept of our nuclear power plants. We have developed a new process focusing on end-to-end dismantling approach, lean principles, and a zero-waste attitude in order to optimize the total decommissioning costs. We have been starting this new approach this year at our Biblis nuclear power plant and roll it step by step out to the complete fleet. Moving on to the European Power segment. In October, we have decided to de-mothball our Dutch CCGT Claus C with a capacity of 1.3 gigawatts. Improved generation spreads and market perspectives led to this decision. The first commissioning activities will start December 2019, and Claus C will be fully commissioned latest by Q4 2020. Whilst Claus C is being reintroduced onto the Dutch market, we are also looking at the opportunity to connect the plant to the Belgian grid. This will depend on the details of the capacity remuneration mechanism that the Belgian government is planning to introduce and the ability to construct a direct line in connection to the Belgian grid. We will also continue with the conversion of our Eemshaven and Amer 9 hard coal-fired power stations to increase the biomass co-firing capabilities. The current co-firing capacity at Amer 9 amounts to 50% and is targeted to reach approximately 80% by early 2020. We are also working on diversifying our biomass sourcing and focusing on identifying additional sources of biomass. The focus in the U.K. is clearly on the management of our generation fleet during the suspension of the capacity payments. The U.K. government is pursuing the reinstatement of the capacity market. It is continuing to operate the scheme, short of making payments, to ensure that capacity providers may be eligible for deferred payments. We continue to maintain the availability of our power plants and are in constant dialogue with relevant authorities and other stakeholders to manage the suspension and the impact on our portfolio. For Supply & Trading, the focus remains on growing its global LNG business and to expand the Asian business. In late December 2018, we signed an agreement with the Australian oil and gas company Woodside for the midterm supply of LNG. This transaction represents another key building block in the further development of RWE's flexible LNG portfolio. Supply & Trading also realized further milestones in its Asian expansion. The Singapore office converted into a principal trading enterprise, which is now concluding both physical and financial transactions in most energy and energy-related commodities. We also expanded our presence in China by successfully establishing a wholly foreign-owned enterprise in Shanghai and a branch office in Beijing. Ladies and gentlemen, Germany should end coal-fired power generation latest by 2038. This, together with significant early plant closures, was a recommendation by the Commission on Growth, Structural Change, and Employment in their final report. While the report did not provide specific details on which plants to close, the majority of early lignite closures are expected to take place in the Rhenish mining area. RWE is prepared to shoulder the lion's share of the measures until 2022. However, the implementation of these recommendations will have wide-ranging implications for our lignite operations and employees. It is therefore only right and consistent that the Commission stipulates adequate compensation for these plant closures. It is also obvious that the compensation must be significantly higher than the one paid for earlier shutdowns. In contrast to the security reserve, the suggested additional plant closures will also have an impact on our mining operations, including substantial redundancies. The Commission also expressed its desire to preserve the Hambach Forest. We are currently analyzing the technical feasibility of this request. What is already clear is that maintaining the forest will cause additional burdens. Having said all that, we believe that the commission's proposal is a good basis for discussions with the government. We have a clear chance to reach an agreement on the phase out of coal-fired power generation in Germany, which will be supported by a broad public consensus. It would ensure that the energy sector will reach its ambitious climate targets and provide planning certainty for operators. Ladies and gentlemen, RWE is fully aware of its environmental and social responsibility, especially when it comes to climate change. We therefore have set ourselves ambitious CO2 reduction targets, and our efforts are paying off. Since 2012, we have been on a continuous path to bring down our carbon emissions. In 2018, we saw another reduction of 10% compared to 2017. This means that we have now lowered our emissions by more than 50 million tons or 30% compared to 2012, which puts us fully on track to achieve our 2030 target. With the implementation of the commission's recommendation, we would accelerate our emissions reduction and end coal-fired power generation by 2038 at the latest. Coming back to the more immediate future, it is clear that 2019 will be a transformational year. We are working full steam ahead on the execution of the transaction preparation for the integration of the renewables business. We are excited and looking forward to become a leading renewables company, as well as developing and expanding the business further. By the end of the year, we also hope to have planning certainty for our lignite operations in order to grow up and implement a revised operational plan. This will set the stage for strong operational earnings, which will support our growth ambitions and can end an attractive dividend. With this, I conclude my remarks and hand over to Markus. Yeah. Thank you, Rolf, and at least for the U.S. and U.K. still, good morning, ladies and gentlemen. 2018 was not only an important year for the future shape of RWE, but was also challenging when it comes to our ongoing operations. Despite the negative headwinds, such as the suspension of the U.K. capacity market, we met our financial targets. Our adjusted EBITDA and adjusted net income are well within the guided range for 2018. As a result, we can deliver on our target to increase the ordinary dividend by 40% to EUR 0.70 per share. Our hedge strategy has also shown to be beneficial in light of the recent development in spreads, as you will see later on our hedge slide. Against the backdrop of a volatile and rising CO2 market, our strategy to hedge our portfolio against higher CO2 prices proved to be the right decision. As part of the optimization of our capital structure, we announced at the beginning of February that we would exercise the right to redeem the 750 million British pound hybrid at the first call date on March 20 this year. Due to the solid financial position and the improved earnings prospects after the envisaged asset swap with E.ON, we have decided not to refinance the canceled hybrid with a new hybrid bond. After the redemption, we still have hybrid bonds with a combined value of approximately EUR 1.1 billion outstanding. Another important step to optimize our capital structure is the planned conversion of the preferred shares into common shares. We will propose to the AGM to convert a total of 39 million non-voting preferred shares to voting common shares without additional consideration at a ratio of one to one. As Rolf mentioned, this will strengthen our corporate governance and is in the best interest of all our shareholders. With this, I would like to explain the major financial developments of 2018 and the outlook for 2019. Let me start with the development of our adjusted EBITDA on slide 15. For RWE standalone, adjusted EBITDA came down by EUR 0.5 billion to EUR 1.5 billion in 2018. This is mainly the result of a decline in generation margins and lower generation volumes, and to a smaller extent, the absence of positive one-offs, which we realized in 2017 in European Power. As well as a slightly below average earnings level at Supply & Trading. Slide 16 provides the details of lignite and nuclear division. Adjusted EBITDA came down to EUR 356 million for fiscal year 2018. The earnings decline of some EUR 300 million for adjusted EBITDA is mainly driven by the expected lower realized generation margins and volumes. The reduction in volumes is primarily a result of the closure of our Gundremmingen B nuclear unit at the end of 2017. Further cost improvements had a positive effect. By the end of 2018, we had reached our efficiency improvement target of EUR 200 million targeted for 2019 compared to 2016, for the most part. CapEx in 2018 remained on a relatively high level. This is driven by accelerated resettlement activities in our lignite mining business. We currently recognize an increased interest from affected residents in the mining area to move location in light of the ongoing uncertainty. We expect a similar trend in 2019. Looking at the current year, we expect the division to reach an adjusted EBITDA of between EUR 300 million and EUR 400 million. We will see a positive impact from the fact that realized margins for 2019 are slightly higher than in 2018. But this will be offset by the negative earnings impact from the production restriction at our Hambach mine after the decision of the higher administrative court in Münster from early October last year. At that time, we said that we expect an annual earnings impact of approximately EUR 100 million to EUR 200 million for the years 2019 to 2021. After optimizing our hedging and operations, we now expect a negative impact at the lower end for 2019 and toward the upper end for 2020 and 2021. The outlook does not yet include any potential impact from the proposal of the Commission on Growth, Structural Change and Employment. We have to await the outcome of the negotiations with the government. While it remains unclear what impact the proposed coal phase out will have on our earnings, we currently don't expect major implication for our adjusted EBITDA in 2019. The European Power division, shown on slide 17, realized an earnings decline of approximately EUR 130 million. Out of this, EUR 80 million refer to non-recurring items in fiscal year 2017, mainly from the sale of real estate in the U.K. Our hard coal and gas plants realized lower margins. However, we saw higher revenues from the U.K. capacity market, but this was less than we had originally expected. Under the U.K. capacity market regime, we had secured payments of approximately EUR 100 million for 2018. For Q1 to Q3 2018, we received payments of around EUR 50 million. The remaining EUR 50 million for 2018 are outstanding, as the U.K. capacity market was suspended in November last year after the decision of the European Court of Justice. The U.K. government has indicated that it want to maintain the capacity market, which prompted the EU to open an in-depth investigation last month. We will have to await the EU Commission's decision to know if we will receive the suspense payment at a later point in time. Operating cost improvements were another positive factor. Similar to our lignite and nuclear division, we have already achieved our efficiency targets that we had set ourselves for 2019, for the most part. At European Power, this is an annual efficiency improvement of EUR 100 million compared to 2016. CapEx increased to EUR 245 million. This is driven by higher maintenance CapEx for our generation fleet and growth projects, such as our biomass conversion in the Netherlands. We expect CapEx to stay on this level in 2019. We will see a peak in inspection and overhauls of our gas and hydro assets in 2019. For our earnings outlook for 2019 of EUR 250 million to EUR 350 million, we don't assume any income from the U.K. capacity market as long as the legal situation is unclear. Originally, we had secured revenues of approximately EUR 180 million for the fiscal year 2019. Now to our current hedge position on slide 18. Average hedge prices for our outright position in 2020 and 2021 increased by one and four euros respectively, compared to the level we reported in Q3. The gain of four euros per megawatt hour for 2021 is mainly due to the increase in hedge ratio from more than 60% to more than 80%. Additional hedges were concluded at market prices, which were significantly above the average hedge price. However, locked-in carbon cost also increased to seven euros per megawatt hour. This increase in carbon cost is rather moderate because the financial carbon exposure above the market pass-through factors was hedged in the past at favorable prices. The outright volumes shown on this slide reflect the expected production restrictions from the court's decision on the Hambach Forest. Due to optimization measures, we expect only a negative impact of approximately five terawatt-hours for 2019. While for 2020 and 2021, our expectation is more towards the upper end of the corridor of nine to 13 terawatt-hours. The slide does not yet include any impact from potential further plant closures as a result of the proposal from the Commission on Growth, Structural Change and Employment, as it is still unclear which plants will close by when. We hope to have more clarity by the end of this year. On page 19, you can see the development of fuel spreads until the end of December 2018, which are relevant for our hedge prices you saw on the previous slide. Fuel spreads showed quite volatile development, but recovered in the second half of last year. As we expected, the price setting spreads of calendar years 2017, 2018, and 2019, closed at around the same level at the end of the year prior to delivery. Let's move on to Supply & Trading on slide 20. Adjusted EBITDA fell slightly short of our average earnings level of approximately EUR 200 million, while trading closed the year below last year's level, and our principal investment business suffered from a value adjustment. Our gas and LNG activities again showed a very strong performance. Looking at 2019, we assume that our Supply & Trading business will reach at average earnings levels. However, due to the normal volatility of this business, we expect an adjusted EBITDA in a corridor of EUR 100 million to EUR 300 million. Slide 21 provides the earnings drivers down to adjusted net income. Our adjusted net income amounted to EUR 591 million for 2018, compared to EUR 973 million in the previous year. The decline in adjusted EBITDA was partly offset by an improved adjusted financial result. Besides the typical adjustments for the non-operating result and the corresponding taxes, we have mainly correction from the financial result, driven by the mark-to-market valuation of securities under the new IFRS 9 rule, as well as the impact from adjustments of discount rates for long-term provisions. Furthermore, taxes are adjusted for deferred taxes. Now on to distributable cash flow on Slide 22. In fiscal year 2018, distributable cash flow amounted to EUR 261 million compared to EUR 533 million last year. This is mainly a result of the decline in adjusted EBITDA and higher CapEx spendings. The latter is even above our original expectation of approximately EUR 400 million, mainly due to higher CapEx for plant maintenance and intensified resettlement activities in our lignite mining business. We expect a similar situation for 2019. Hence, CapEx is expected to again be in the order of EUR 0.5 billion. Furthermore, the distributable cash flow is lower than we expected in Q3 2018, when we guided for a positive change in operating working capital. This is a timing effect due to higher gas inventories as well as unusual high net accounts receivable. We expect this to reverse in 2019, which, ceteris paribus, will have a positive effect of approximately EUR 250 million on our change in working capital for this year. Change in provisions and other non-cash items came down compared to the previous year, mainly on the back of a lower utilization for legacy provisions. We expect a further significant decline in the amounts used for legacy provisions as already indicated our capital market day in March 2017. Hence, total change in provisions and other non-cash items is currently expected to reach around EUR 0.5 billion in 2019. Cash interest came down as expected after the redemption and buyback of hybrids. They will slightly increase in 2019 as a result of the implementation of IFRS 16, among other things. Minority and hybrids are at EUR 64 million. This will be a similar amount in 2019, despite the fact that we will call the British pound hybrid in March. The cash outflow reflected here is a retroactive interest payment for the period March 2018 to March 2019. Different to the distributable cash flow, the P&L will only show the pro rata interest cost of this hybrid in 2019. Details of the development of the net debt are shown on Slide 23. At the end of the year, net debt stood at EUR 2.3 billion, approximately EUR 2.2 billion lower than at the end of fiscal year 2017. This mainly results from changes in variation margins, which will revert once the underlying transactions are realized or commodity trends turn around. Net debt increased by about EUR 1 billion from the change in provisions, of which EUR 0.8 billion relate to pension provisions. This is mainly due to adverse capital market developments resulting in a decline of pension assets. Furthermore, discount rates for our German pensions provisions came down. Now on to RWE standalone outlook for 2019 on Slide 24. Irrespective of the timing of the closing of the transaction with E.ON, we will provide KPIs and the outlook for RWE standalone over the whole year. Based on the development I explained for the individual divisions, we expect adjusted EBITDA to reach between EUR 1.2 billion and EUR 1.5 billion. Let me remind you again that this outlook does not include any payment from the UK capacity market. It does include a dividend from Innogy of EUR 700 million and is different to the proposed Innogy dividend for 2018 announced yesterday by the Innogy management. The EUR 700 million is based on our agreement with E.ON on the sale of our Innogy stake. Adjusted depreciation will increase towards EUR 650 million. One reason for this is the first-time implementation of IFRS 16. While we expect a flattish development of our adjusted financial result in adjusted taxes, we see an improvement for the hybrid cost after we will have called the British pound hybrid as of March 2019. As a result, adjusted net income is expected to reach between EUR 300 million and EUR 600 million in 2019. Net debt, which totaled EUR 2.3 billion at the end of 2018, is likely to rise substantially in the fiscal year underway. As just mentioned, last year was characterized by high cash inflows from variation margins. Once the underlying contracts are realized, some of which mature in 2019, the effects will be reversed. This brings me to our dividend outlook for 2019. This will be the last year that we will base our dividend on distributable cash flow. On that basis, we are targeting a dividend of EUR 0.80 per share for fiscal 2019. This represents a further increase and delivers on our target to pay a sustainable dividend with further upside potential. Once the transaction with E.ON is closed, we plan to change our dividend policy. For the new RWE, we see a traditional payout ratio as more appropriate to define the dividend. The payout ratio will depend on the ability to find attractive future growth projects. However, we want to at least maintain the absolute dividend level of fiscal year 2019. This concludes my remarks, and we are now happy to take your questions. Gunhild, please. Thank you, Markus. To everybody on the phone, if you register your questions and the operator will put you through. Operator, please, the first question. Thank you very much. We have received the first question. It comes from Vincent Gilles of Credit Suisse. Your line is open. Please go ahead. Yes, thank you. Morning. Afternoon, everyone. Two questions. The first one is on compensation for early closure of coal and lignite plants. Mr. Schmitz, you are quoted in Reuters today talking about 1.2 gigawatts to 1.5 billion, obviously per gigawatt. I get it right at the end. Question is obviously whether you really said that. It is reported by the press, but I do not really trust them, and on which basis you can come to that number. We have seen that number in the past, but also maybe if you can share with us why you are coming out with this number because you have a high degree of certainty it is reasonable, or you had conversation with the government. Anything you can share with us. That is question number one. Question number two is on renewables. Over the last 10 days, all of us have gone through CMDs presentations from large utilities in Europe, and the magic number seems to be 2 to 3 gigawatts of renewable capacity per year. I am wondering whether there will be enough projects actually available given the number of candidates now. My question is, what will be your unique selling point, in a way? What will you be doing differently from the crowd that will ensure us that you will be creating value in renewables at a time of very high competition for a limited number of assets? Thank you very much. Thank you. Thank you for the question. First, the compensation. There is no other number, and there will be no other number than EUR 1.2 billion to EUR 1.5 billion per gigawatt. We are just expecting the discussion with the government, and these numbers are coming from the compensation, which we see for chances which we have with our power plants in next years. Especially, these numbers come from the problems or from the numbers which we need to have another recultivation and another setting of provisions and so on in the lignite mines. I would say, we have set this number in the room. You should not have too low numbers if you discuss something with someone. Later on, we see these numbers, and we will see what is possible to get. We have to do a business judgment, and we have to be very clear for our shareholders that they will not lose money by regulation from the government. The 2 to 3 gigawatt, yes, there are other people who try to do the same, but on the other year, we have now released the fifth year, that we have more than $300 billion investments per year. I would say that is enough for us with our small amount of 2 to 3 gigawatt. Unique selling point. The unique selling points, Gunhild said to me here, we can only show you our pipeline in the past and say we do our best to do better further on. We are not operational in the business today. Therefore, I have not seen direct insight to the business, but we see that they are successful and they deliver the numbers. Thank you. Thank you. Next question, please. Thank you. The next question comes from Alberto Gandolfi of Goldman Sachs. Your line is open. Please go ahead. Thank you. Afternoon. Thanks for taking my questions. I have two questions which are on the renewable business. The first one is on these 2-3 gigawatts, let's say EUR 1.5 billion net investment, if I understand right. What do you expect to be the IRR or the IRR minus WACC? Would it be fair to assume that you're broadly expecting to deliver about EUR 150 million of incremental EBITDA per year? Maybe it depends a bit clearly on the composition offshore versus solar onshore. The second question, could you go a bit more in depth on how you intend to fund these? Because in the 2-3 gig, is the EUR 1.5 billion the equity component, or is it, as I think I understand, a net investment, i.e., 2-3 is gross, then you're going to be farming down or divesting some assets. The EUR 1.5 billion is CapEx. So what would be the net contribution? It's not 2-3 gig, it would be a bit less. Talking about funding, can you maybe elaborate how do you see the E.ON stake, and how do you see any compensation for lost profits on lignite in this context? Would you use these two elements, the E.ON stake and potential compensation on lost profits, not on recultivation, just lost profits. Would you use it as potential incremental funding, maybe for longer term offshore projects? This would upgrade clearly your return in the medium to longer term versus a 5%, 6% dividend yield you might be getting from an infrastructure utility. Thank you. Yeah, Alberto. This is Markus. Thanks for the question. Let's first figure out the difference between how can you build 2-3 gigawatt with EUR 1.5 billion investment. What we mean by net is net after farm downs and also after partly debt financing it. Depending how you structure the project and so on. We currently assume that the gross funds needed to build 2.3 gigawatt, depending on which technology you have, and the more offshore, the higher the number. It needs to be EUR 2.5 billion-EUR 3 billion gross investments. Yeah, of course, on the net investment, you should at least or should expect something around a 10% EBITDA contribution, which is reasonable. But please, when you model it, keep in mind that it has some delay. It doesn't kick in immediately, right? You have construction time, depending on which technology you are talking about, of a year to two years. The question regarding the E.ON stake. That depends. What we think about how attractive the valuation is, what other funding sources are available. We currently see that the EUR 1.5 billion, which we expect to invest net, is the earnings or the cash contribution of the operating business. So the EUR 1.5 billion can be funded by our operating business. Then, of course, if you use the E.ON stake, it might come on top. But it's always a question when to sell and where to invest. So we will take that totally opportunistically. Thank you. The compensation, I would not mix up compensation with investment opportunities. Compensation is clearly compensating potential losses. I would more consider it as, if we have a damage from early closures, we need to increase our provisions and the potential compensation we get or we can claim later, is offsetting the debt side. But it is not something which is available for investments. Clear. Thank you. Thank you, Alberto. Next question, please. Thank you. The next question is from Deepa Venkateswaran of Bernstein. Please go ahead. Your line is now open. Thank you. Two questions from me. Firstly, there was a ruling this week from the Cologne Court on the Hambach legal case, saying that there is no legal basis for stopping. How should you view this? Does this strengthen your hand in your negotiations with the government? Do you see the appeal to this finalizing before you end up your negotiations? Maybe just some color on your timing on negotiations is helpful. I think the second question is, net debt adjustments, because of the deal. Last year, you said that there would be around EUR 2.8 billion of debt that would be transferred from E.ON and Innogy, that would move into your business. Now we have got results from both E.ON and Innogy and, triangulating between all your three financials. I see that E.ON has classified roughly EUR 2 billion as debt of the discontinued business. I kind of work out, looking at your standalone and your group financials of continued business, that is probably EUR 2 billion sitting kind of in the Innogy businesses that you will retain. So that is around EUR 4 billion. Is it fair to assume that it will be EUR 4 billion of debt moving from E.ON and Innogy, kind of accommodating for all the lock box adjustments plus any provisions and other things moving over? Thank you. Coming to the first question. Yes, this ruling yesterday from the Cologne Court was very positive for us because we have won in all the parts. But it does not have anything in the moment directly in relation to the Hambacher Forest, because they will directly go to the next court and therefore we expect that there will be a ruling that we can really go cut down the trees end of 2020 or in 2021. Therefore, the discussion with the government, yesterday, our first meeting and just coming a little around looking to the process and so on. We expect that we will need this year for the discussions with the government, because first they want to do the structural change legislation, then come later also the things belonging to the coal phase-out. That will be finished then in Q1 or Q2 next year because they need this for the legislative process. Therefore, the impact now from the Cologne Court is good, but it does not give any direct impact. It just support our discussion that we are legally able to cut down the trees in Hambach Forest. Okay. Oh, sorry. Please. Sorry, just on the timing. You mentioned that, so what would happen in Q1 of next year? Is it just your negotiations on compensation will conclude then? Is that what you said on the timeline? No, the legislation will be then finished to the coal phase-out. I think that we have to be earlier with our contract, but the contract is under the permission that the legislation will be then in duty. Okay. But you can get the contract or the draft of the contract agreed by the end of this year? We had it with the nuclear things in the same way. We had a contract. We have made a draft to it, and then we waited for the legislation, and that must fit in. Because after the legislation, we can really underwrite the contract. Okay. This will be next year. But I think the contract will be finished. Q3, maybe, I hope. Okay. I take your question on the debt side, Deepa. Of course, the two numbers you mentioned are correct. How does that reconcile with the 2.8 we have mentioned when we announced the transaction? The 2.8 was without the IFRS 16 effect, which is for the renewables business alone, a bit more than half a billion. Then please take into account that we still have the lock box mechanism in place. So for example, I give you an example, the farm down proceeds for Triton Knoll are of course not reflected in the balance sheet part, which Innogy shows, but we are entitled to get that from the lock box mechanism, which is in a positive effect. But overall, yes, with all uncertainties, the number will be around that area, 3 to 4. Okay. Thank you, Deepa. Next question, please. Thank you. The next question is from Peter Bisztyga of Bank of America, Merrill Lynch. Your line is now open, please go ahead. Yes. Good afternoon. My first question is just on your 2019 guidance. If I add up the different components of your divisional EBITDA guidance, I am getting to a range of EUR 1.2 billion-EUR 1.6 billion, whereas you have gone for group EBITDA guidance of EUR 1.2 billion-EUR 1.5 billion. I am just wondering why you have decided to skew towards the bottom end of the range, and is this just you being conservative? My second question, back on the issue of compensation. Can you comment on the legal opinion published by the German Parliament a while ago that there is no legal basis for compensation for coal generators? Thank you. Yeah, Peter, let me start with the first question. You are right, but please keep in mind that, and maybe we were not explicit enough also in our communication, which we sent out this morning. Under other than consolidation, we expect for 2019 around close to EUR 100 million cost for the integration of the renewables business and also the full separation of Innogy, because we need to split the IT system, which usually is very expensive. This is a clear one-off. This is included in the full company guidance. Of course, we will make it transparent when the numbers are in the accounts, that these are clearly one-off effects. We should expect a lower integration cost and separation cost amount in 2020. But then we are two, these are clearly one-offs. To the legal basis for compensation, this was only one report, which was delivered from the government or from people in the government. We have some other reports with contradictory results. Therefore, the commission said very clearly there should be compensation, and there should be a consensus between the government and the companies. Therefore, for us, it is clear there must be compensation. We have a legal basis for this. We have the studies for this. I would not too see the legal opinion of the scientific service of the government as too strong. Okay. Thanks very much. Thank you, Peter. Next question, please. The next question is from Ahmed Farman of Jefferies. Please go ahead, your line is open. Ahmed? You can ask your question now. Your line is now open. Slipped on. Let's take the next question. Maybe you can contact him. Okay. Then we go to the next question. It is from Sam Arie of UBS. Your line is now open. Please go ahead. Hi. Good afternoon, everybody. Thank you for the presentation. I'm kind of a ways down the list of questions, so we're down into some detailed points. I'd like to just clarify a couple of things on the transaction and maybe one on the compensation discussion. Starting with the transaction arrangements with E.ON, I think it was clear yesterday that Innogy announced a lower dividend than expected, but my understanding is you're protected on that by the agreement with E.ON, so you'll still receive the dividend at the level expected a year ago. Just wanted to confirm that's correct. Also, in terms of valuing the, let's call it 17% stake, in E.ON that you're going to have. I have come across a bit of confusion on this in conversations. But I think the correct way to do that is to take the 440 million shares by the current E.ON share price or whatever E.ON share price is expected, rather than to take 17% of the market cap that displays on terminals at the moment and which doesn't take into account the rights issue or the issue of shares to you that E.ON has obviously announced it's going to do. So in other words, it's 17% of EUR 25 billion market cap on today's price, which will give you a number of about EUR 4 billion or EUR 7 per RWE share. So I just want to check that methodology sounds correct to you as I think I've come across both out there. And then just my quick question on the compensation is, am I right that it's your expectation that compensation will cover lost profits as well as any additional cost of early closure, so not just compensating for the increased provisions and so on, but actually the loss of value in the assets that close? Thank you. Let's start with the last question, which is the easiest one. Of course, yes. Our expectation is clearly, and we are also the management team have our duties, need to protect the rights of our shareholders. So we can only accept agreements with the government where we are not only compensated for lost earnings or profits, but also for additional costs. To be clear, especially on current market prices, if you don't take the hedges into account, the additional costs are the major items which need to be compensated, especially the much higher recultivation cost for replanting and just maintaining the mine until we can bring it into the final state. So the cost side will be the more relevant one for compensation than the lost earnings one. On the other questions, yes, you are right on both ends. The right way to calculate the value in E.ON is to take the 450 million shares we receive, multiplied by the current share price, because we should not expect the share price decline significantly because of the issue they do. So it's not 17% of the current market cap because they will increase their capital by around 20%. That results into the stake of 17% after the increase by 20%. On the dividend, we have the same agreement that E.ON has offered to the minority shareholders which have tendered, and that is that regardless what Innogy proposed to pay, E.ON will add up until EUR 1.63 per share. So EUR 1.63. That is the level we will get for 2000 or six four. Six four, sorry, 164. So we're going to receive then in a combination of payments from Innogy and E.ON, around EUR 700 million for 2018. Yes, 18, 19. Very clear. Thank you for your answers on all the questions. Thanks, Sam. Next question, please. The next question is from John Musk of RBC. Your line is now open. Please go ahead. Yeah. Hi, everyone. Two questions, I guess, on the existing generation business. You talked a bit around the work you're doing on nuclear decommissioning. Can you remind us as to what you may have already included in your provisions and how material that might be? Is that something we should be factoring in around lower nuclear provisions? Then secondly, you've hit all your efficiency targets. I think it's the EUR 400 million in total a year early. Is there more that we should be thinking about to still put in for our numbers, for efficiencies going forward? Let me start with the second question first, John. It was EUR 300 million, not EUR 400 million, EUR 200 million in lignite and nuclear, EUR 100 million European Power. We have achieved close to that number, so a bit will come in 2019, but we are almost there. So far we have not set up additional efficiency programs. We actually don't see any in Supply & Trading, nor renewables, nor European Power, which will grow. It became totally new now. But in lignite and nuclear, of course, with the potential agreement on early closures. But this will then be a mixture of course we do whatever we can to reduce costs as fast as possible, but that will also reduce our losses. But will come at restructuring charges, but this entire stuff will be part of the compensation discussion with the government. So I would focus on assumptions, what is the net on compensation rather than split it into individual parts of gross losses and then an offsetting efficiency program. On nuclear decommissioning. Yes, we are going forward normally, and we try to be better than the provisions that we have. But you know that we are starting with this process, and it would be too early because now we try to use a new process, which we have made and so on in Biblis. It would be too early to give some hints in this way. Yeah, the EUR 5.9 billion we have in provisions are still conservative. I think we have said it in the past that we first want to see a track record over a couple of years before we take an assumption on how much it will cost for the remaining lifetime. Even if we go aggressive and say it is going to be 10% cheaper, it is for the remaining lifetime of decommissioning, a number of EUR 30 million-EUR 40 million per year. It is too early to adjust the provisions already now. But when we have new indications, we will clearly give an update. Okay, thank you. Thanks, John. Next question, please. Then we now take the question of Ahmed Farman of Jefferies. Please, Ahmed, your line is now open. Yes. Hi. Thank you for taking my question. Just two from my side. I just want to first come to slide 19. If I am reading it correctly, the spread chart or the spreads that you are showing us here are in backwardation. The 2021 spreads are below 2020, and 2020 is below 2019. Is that surprising to you? Because I thought your implicit fuel hedging strategy was all based around a bit more optimistic view on spread developments and given all the news flow we are hearing about closures or upcoming closures. So interested in your thoughts on that. My second question is on the coal phase out. When you mentioned earlier that you expect to have the agreement with the draft agreement with the government, does that mean that by Q3 or so, you are hopeful to have the necessary clarity on the compensation or the value of the compensation? Are there any parallels that you think that we can draw between this process and the process you went through in the Nuclear Liability Fund? Because at the time I remember, there was an auditor that was appointed, and there was a review of the assumptions around the liabilities, which then formed the basis of the actual settlement. So just interested if you think, we can see some parallels here to that. Thank you. Coming to the second one, we will see. We hope that we can really come to a contract or draft of the contract in Q3, maybe Q4, because the government needs this contract as a basis for the legislation, which it has to do afterwards and which needs some time. The methodology to find now ways may be easier in this case because we know in which way it could go further on with the normal business. You have some outlook to this and some planning to this, you know which provisions you need and so on. If you need which power plants you have to take out, then you need what is going on with your mines, and then you can go to people who can really directly on a neutral way say, "Now you have to deliver these provisions. Now you have to deliver that and that." We know what stranded investments are, and we think it is not so complicated to come to an end. Ahmed, your question on page 19, the spreads. On the right-hand side, you see that the spread level, which shown where the number one is displayed is. This is actually the month prior to delivery, so actually December of the year before delivery. You see that the spreads are slightly increasing here from calendar year 2017, then maybe a couple of cents higher 2018, and then almost EUR 1 higher in 2019. In 2020, spreads have recovered significantly, already earlier, so not closer to delivery, but they are already on a level which is EUR 2, EUR 2.5 higher than six months ago. On 2021 it is still low. I mean, it will not surprise you if I tell you that we think that the spreads which you can calculate from the financial markets for 2021 are currently quite low, and we keep our spread position open because we expect development to be positive as we have already seen prior to delivery for the years 2018 and 2019. Okay, thank you. Thank you. Next question, please. Thank you. The next question is from Martin Tessier of MyFirst. Your line is now open. Go ahead. Yes. Good morning. I have the first question on your 37.9% stake in the Austrian company, KELAG, that you will take on with the deal with Innogy and E.ON. Could you give us more information on how you consider this participation, whether you consider it as core, non-core or under assessment? My second question relates to your Supply & Trading business. On page 9 of your presentation, you mentioned a strong increase in the LNG portfolio in terms of million tons. But if we look at the performance of this business in fiscal 2018, EBITDA and EBIT were down by more than 30%. Also, guidance stays the same with an expected long-term average of EUR 200 million of EBITDA. It looks like quite counterintuitive. Could you give us more detail on that, please? First, looking to KELAG. KELAG, the main business and the main source of the results is coming from hydropower plants, and therefore for us, it's core business or near to core business. Therefore we are happy to have it back in our portfolio. It was before in our portfolio and comes back now because it's directly related to renewables. They are building up wind portfolio, PV, and so on. They go to Southeast Europe for smaller hydropower plants, and therefore it's core business. This LNG, it's Markus. Yes. On the Supply & Trading business, the result under Supply & Trading for the EUR 200 million EBITDA we expect on average, it is a combination of four business line. It's trading, then it's gas and LNG, principal investments, and then commodity solutions, so the large customers business. The gas and LNG business was very strong again in 2018 as it was in 2017. If you compare the numbers, decline was driven. We had a valuation adjustment in the principal investment business, which was a medium double-digit million number, and we had a slightly weaker trading business in 2018 than 2017. But LNG was above expectation and as strong as in 2017. Thank you. Thank you, Martin. Next question, please. The next question is from Jose Lopez of Millennium. Please go ahead. Your line is now open. Hello. Good morning. Thanks for taking my question. I just had a question about, earlier this month, a group of NGOs from different countries, they filed a suit with the European General Court in Luxembourg, and the suit is asking the court to prevent the EU countries from counting forest wood as a renewable energy source under the 2018 Revised Renewable Energy Directive. Now, do you see any risks to the subsidies received by your Dutch coal-to-biomass conversion plants? How would you manage this risk? Would you be seeking to perhaps ask the Dutch government for a letter of comfort so you can carry on with the CapEx, and if regulation changes, you are guaranteed to be compensated for the executed CapEx in the event that you cannot count biomass anymore as a renewable energy source? What is your thinking around this issue and how to manage this risk? Thank you very much. Thank you. We have not got any hint that it will not go further on as it is planned, and therefore we do not see this risk at the moment. If there would be something, we have to claim against it. You must not wake up sleeping dogs, and therefore, it is better at the moment nothing to do. Okay. Thank you. Thank you. Next question, please. Thank you. The next question is from Nick Ashworth of Morgan Stanley. Your line is now open. Please go ahead. Thank you. Afternoon, everybody. A couple of questions from me as well. Firstly, I think, Rolf or Markus, one of you mentioned the potential for a time lag between compensation and provision and/or cost increases coming from coal exit. Is that something which is a possibility? Secondly, connected to that, I think Markus, in one of the answers to the questions, you talked about operating cash flow funding renewables CapEx from here. If there is any time lag, does that put that under any pressure? Also right at the very beginning of the presentation, I think Rolf, you said future growth is going to be focused on renewables. Does that also mean that, you've talked about renewables CapEx. Is there any CapEx which is going to go towards thermal generation aside from maintenance from 2020 onwards? Thank you. Nick, your first question, I would not expect a huge time delay. No, I wouldn't expect a time delay on building provisions and also considering already the compensation. Because I think the trigger event for a reassessment of the provision level is signing the contract with the government. Signing the contract with the government will also entitle you to compensation. So that goes hand in hand. Then we're going to set up our own efficiency program, if you assume restructuring charges, that will also be part of the compensation discussion. So there could be a time delay in the cash flows, but definitely not in the building of provisions or- Balance sheet. Yeah. So on the balance sheet or on the debt side. On the operating cash flow and renewable investment side, as typically in renewable projects, you have a lead time of investments, and that needs to be factored in, be it a year or two. Then future investments in conventional- Yeah. Thermal generation, if there would be chances, for example, in gas, in our core regions, yes, we will find some money to invest and to do this, but we do not see it at the moment. Maybe later on, if security for supply, we'll need some more. But in relation to the whole CapEx, which we see for the next years, is only a small amount, which could be invested in gas-fired power plants or gas turbines. Okay. Thank you. Thanks, Nick. Next question, please. Thank you. We have received a follow-up question of Deepa Venkateswaran of Bernstein. Your line is now open. Go ahead. Thank you. I had one question. This is on the global growth aspirations in renewables that you have put out. One question is, you have not really shown any type of generation against India. Is that deliberate? Or, I.e., indicating that that is probably not as advanced. For some of the other countries, for instance, the Asia PAC offshore wind, or even U.S. offshore wind. Right now, neither E.ON nor Innogy have any leases or any partnerships. How is your thinking about these absolutely new countries? I also see that solar PV is looking quite big in the U.S., which has traditionally not been an area of focus for either of them in such a big way. I just wanted to know whether you would think of making additional acquisitions or partnerships to go into these new countries or technologies. Yeah. On India, Deepa, if something develops in offshore in India, we find the right partners, that could be part of the strategy. For the time being, we have excluded onshore and PV in India, because I think it is important to give the management team a clear steer and not to get lost in too many optionalities. Mm-hmm. Sure. On the other things, yes, you are absolutely right. Both companies, for different reasons, have currently not a foot in the door in offshore in the U.S. But they have already started planning the market entry and partnering for the Asian markets. When we have access to the operating business, so that's too early now to discuss or speculate, we will also look into opportunities to accelerate market entry via acquiring development platforms. But we do that together with the management teams. Currently for competition reasons, we cannot sit together, the three of us, and discuss it. So it's currently too early. We currently rely on what both companies are doing on a standalone basis. The moment that the full clearance of the transaction is there, we can sit together and make specific plans. Okay. Thank you. Thank you, Deepa. Next question. The next question is a follow-up question of Ahmed Farman of Jefferies. Your line is now open. Please go ahead. Yes. Hi. Thank you for taking my follow-up question. Just one more on the policy discussions in Netherlands, where there's also a proposal for a coal phase out and probably will affect your Eemshaven plant. As part of the discussions there, is there, at this stage, a proposal for compensation on the table there as well? If not, what is your strategy to that? Because I think the way the policy proposal is that you may have to close Eemshaven by 2029. Thank you. Yes, the first to close in 2025 and then the last in 2029 or 2030. There's no compensation planned, and we have to claim against it. Okay. Thank you. But you know, in 10 years, the policy could change very often. Okay. Thank you. Are there any more questions? At the moment, there are no further questions. As a reminder, if you would like to ask a question, please press 01 on your telephone keypad now. We haven't received any further questions. I would hand back to you. Oh, now we've received another question. It's a follow-up of Sam Arie of UBS. Your line is now open. Please go ahead. Oh, thank you. I thought I'd squeeze the last question in. I apologize, actually, if you maybe commented on this already, but just to make sure we're clear. On the process with the U.K. capacity market, what's your expectation about when we will next know something? I think we asked Uniper a similar question, and they thought that there might be some kind of update in coming months, but I wondered if you were aligned with that. I have heard some people in the market talking about an extended process which could drag on for a year or 18 months. Obviously, you're probably closer to it than we are. Any kind of indication what the timeline is from here would be very helpful. Thank you. Yeah, Sam, to be honest, I don't know. It's not our process, and there is no standard process to resolve this issue now. The only thing we know is that both ends, the European Commission as well as the U.K. government, they want to resolve it as soon as possible, but that can mean a lot. We currently don't have any indications. We are in constant contact. The moment we know something, I think, but then everybody knows it will be public. Currently, there is no clear process where we actually have indications when we get more clarity. It can go quick. It can also drag on. I don't know. Sorry, that was probably not what you wanted to hear, but No, that is an honest answer to the question. That is exactly what we wanted. I think everyone is keen for an update, so let us hope they come with something very soon. Yeah. Okay. Thanks, Sam. Thank you. There are no more questions. There are no more questions. Thank you very much, everybody. I hope we will see many of you soon on various roadshows, and enjoy the rest of your day. Bye.