Hello, welcome to this Ørsted Q2 2021 earnings call. For the first part of this call, all participants will be in a listen-only mode, and afterwards, there will be a question and answer session. Today, I'm pleased to present Mads Nipper, CEO, and Marianne Wiinholt, CFO. Speakers, please begin. Thank you very much, good morning, good afternoon, everyone, and welcome to the Q2 2021 earnings call. Having now been part of the Ørsted team for more than seven months, I'm pleased to say that we've continued to execute on many important strategic milestones in the second quarter of 2021. I'm constantly impressed by the sheer intensity with which our company manages to progress so many important areas in parallel. During the first half of 2021, we have been impacted by very low wind speeds across our portfolio. We do maintain our full-year EBITDA guidance of DKK 15 billion-16 billion, due to the strong performance from our CHP plants and high earnings from gas business, as well as additional earnings from finalized construction projects in offshore. Most recently, we won with a full bid for our 1,148 MW Ocean Wind 2 project in the competitive solicitation in New Jersey, which grows our firm offshore wind capacity to 18.5 GW and brings us closer to our new 30 GW by 2030 offshore wind ambition that was launched at our Capital Markets Day. This win is another tangible example demonstrating that we can and will continue to be the undisputed leader within offshore wind while creating value for shareholders. This quarter, we launched several key strategic partnerships in Japan, Korea, Norway, and Scotland, further positioning ourselves to reach our 2030 aspiration to become the world's leading green energy major. These partnerships included our Japanese consortium established with JWD and Eurus. It included an MoU with Korean POSCO to support the development of 1.6-gigawatt offshore wind projects off the coast of Incheon City, and to conduct feasibility studies on potential collaboration on renewable hydrogen in Korea. It also included our consortium established with Fred. Olsen Renewables and Hafslund Eco in Norway, and our newest partnership established with Falck Renewables and BlueFloat Energy for the ScotWind lease round, where seabed bids were submitted in July. I'll also point to the fact that the latter two of these partnerships confirm our commitment to floating foundations as a complementary technology to bottom-fixed offshore wind. As an example of our view that bottom-fixed and floating are complementary technologies, we also submitted bids for bottom-fixed offshore wind project rights at the ScotWind leasing round as a standalone developer. We also finalized a number of agreements during the quarter as we completed our 50/50 joint venture with PGE in Poland for the Baltica 2 and 3 projects. We closed the Brookfield Renewable Ireland acquisition and closed the 50% farm down for Borssele 1 & 2 to Norges Bank. On the topic of farm downs, we have now launched the structured process regarding the farm down of our Hornsea 2 project in the U.K. with the aim of closing a deal in 2022 after the asset has been commissioned. We continue to see very strong interest from potential partners for our assets, and with recent partnership transactions in mind, we are optimistic about also executing a strong deal for Hornsea 2. We've also progressed our market-leading renewable hydrogen and green fuels pipeline with the construction start of our first renewable hydrogen project, H2RES. This project will have an electrolyzer capacity of 2 MW and will use our 2 Avedøre Holme wind turbines to investigate how best to combine efficient electrolyzer facilities with fluctuating power supply from offshore wind. Moreover, we entered an agreement with HOFOR to source renewable power for the next phases of the Green Fuels for Denmark project. Within our onshore business, we commissioned our first large-scale combined solar PV and storage facility, Permian Energy Center, as well as our largest onshore wind project to date, the 367-MW Western Trail Wind Farm, both located in Texas. As a top five developer in the U.S. and recent entrant in the EU, we continue to demonstrate our on-time and on-budget construction capabilities, our adjustability to customer demands through hybrid projects, and the benefits of having a portfolio approach to offtake. On the topic of onshore, we recently announced that Declan Flanagan had decided to step down from his position in the company. 12 years after founding Lincoln Clean Energy and three years after Ørsted's acquisition, Declan felt it was the right time for a change. We have initiated the process for recruiting the next CEO of onshore, and effective immediately, Neil O'Donovan, our Chief Operating Officer of onshore, has been appointed interim CEO of onshore. At our recent Capital Markets Day, we set an ambitious growth target of reaching an installed onshore capacity for 17.5 GW by 2030. We have a very strong set of value-creating growth opportunities in our pipeline and remain fully committed of reaching that target. I am confident that the strong team and organization that we have built will continue the impressive work we've seen over the past three years. Let's now turn to slide four and look at our New Jersey accomplishment in greater detail. We are thrilled to have been successful in the second competitive offshore wind solicitation in New Jersey. Here, the full amount of our 1,148-MW Ocean Wind 2 project was awarded a 20-year contract starting at $84 per megawatt hour in 2029, and escalating 2% per annum, which equals a levelized 2017 price of $67 per megawatt hour. Subject to final investment decision, the project is expected to be commissioned in 2029. We see this project demonstrating our capabilities in creating value in a competitive environment by leveraging our expertise to help our customers achieving their ambitious renewables targets, deliver on strong local content, and ultimately execute a very attractive project. With the award, our ocean wind lease area will be utilized to its maximum capacity of 2.3 GW. Moreover, with our 4.1 GW of awarded capacity, we have the largest U.S. offshore wind development pipeline, which unlocks significant synergies in procurement, construction, and operation. In addition to the awarded capacity, Ørsted and our partners still have proprietary rights to around 4 GW of remaining seabed leases on the U.S. East Coast, which can be utilized for upcoming solicitations. Turning to slide five, where I'll give an update on our offshore and onshore construction projects and renewable pipeline. Starting with our offshore and onshore projects under construction, the construction work for all projects continues according to schedule. At Hornsea 2, as of today, 128 out of the 165 foundations and 59 of the 165 turbines are installed at sea. When commissioned in the first half of 2022, Hornsea 2 will become the world's largest offshore wind farm, exceeding our own Hornsea 1. At our Greater Changhua 1 and 2a project, we have started offshore construction work with installation of the export cable and pin piles for the foundations, and continue to progress the associated onshore construction. We expect to commission the project on time in the second half of 2022, but the continued dynamic COVID-19 restrictions in Taiwan could potentially impact the construction timeline. In the 1st quarter of the year, we discovered an array cable protection issue at several of our offshore wind farms across the U.K. and continental Europe. We are progressing the technical investigation process, and our assessments are unchanged since our last update and still point to a total financial impact of around DKK 3 billion across 2021 to 2023, with approximately 1/3 expected to be capitalized. We continue to see good progress on our onshore construction program. We do expect to commission Muscle Shoals in Q3 of this year as the project is in the final stages of testing and commissioning. By year-end, we expect to commission Haystack and our other assets under construction, Kennoxhead 1, Old 300, and Helena Energy Center. They are on track to be commissioned in the first half of 2022. During Q2, we added a 302 MW onshore wind project, Lincoln Land, in MISO, to our construction program. We entered into an agreement to acquire the project in May. We expect to both commission the project and close the transaction by the end of the year. While we continue to have a development-focused culture in our onshore business, we also have proven to buy well, and we see this project bringing diversification benefits and solid value to our portfolio. This brings our installed and under construction renewable capacity for the group to 16.5 GW. For our awarded projects, we are also seeing strong progress. Starting in the U.S., with the increased resources at the Bureau of Ocean Energy Management, or BOEM, and various indications of momentum on both the federal and state levels, we do remain confident that three of our largest U.S. projects, Ocean Wind 1, Revolution Wind, and Sunrise Wind, are on track to be commissioned before the end of 2025. Both Ocean Wind 1 and Revolution Wind have their notices of intent, and Sunrise Wind's notice of intent is expected during the third quarter of this year. As previously communicated, South Fork is still expected to be commissioned by the end of 2023, following its draft environmental impact statement issued in January 2021, and Skipjack Wind 1 is still on track to be commissioned by its previously updated expectation of 2026, which reflects our updated interconnection landfall plan and our proposed Maryland 2 project bid. Our awarded projects in Germany, Taiwan, and Poland also continue on track. This puts us at 25 GW of firm renewable capacity from projects commissioned, under construction, or awarded across offshore and onshore. With this, I'm happy to say that with our 25 GW of firm capacity, 22 GW of substantiated pipeline, and more than 35 GW of opportunity pipeline in offshore, we are well on our way to reach the 50 GW by 2030 ambition. Let's now move to slide six and an update on upcoming offshore wind auctions and market developments. We continue to see numerous auction and tender-based opportunities opening and being awarded in the coming 6-18 months. With our recent awards in Poland and New Jersey, the next results are expected for Maryland and Japan in Q4 of this year. In Maryland, we submitted a bid for 760 MW through our Skipjack Wind 2 project in response to the Maryland Public Service Commission's call for up to 1.2 GW of offshore wind. Our proposal includes numerous synergies with our already awarded 120 MW Skipjack Wind 1 project, pledges to environmental justice initiatives, and commitments to significant manufacturing operations that will enable Maryland to establish itself as a significant player in the offshore wind supply chain. In Japan, we submitted three bids with our joint venture partners, one with TEPCO in Choshi and two with JWD and Eurus in Noshiro and Yuri Honjo. The auction comprises a total capacity of 1.5 GW split between four zones. 415 MW for Noshiro, 730 MW between Yuri Honjo North and South, and 370 MW for Choshi. This auction is an important first step for Japan to achieve its target of 10 GW of offshore wind by 2030 and 45 GW by 2040. Looking at the rest of the auction timeline, we expect most auctions and tenders to kick off in 2021, with results expected during 2022. As we work towards our vision of Ørsted being a catalyst of change towards a world that runs entirely on green energy, I am proud to be part of a team with the talent, ambition, and the will to constantly push the agenda, and this quarter was no exception. With this, I will now hand over the word to Marianne. Thank you, Mads, and good afternoon from me too. Let's start on slide seven, where I will go through the EBITDA for Q2 2021. We realized a group EBITDA of DKK 8.2 billion, an increase of DKK 5.2 billion. The increase primarily related to the DKK 4.5 farm-down gain from the Borssele 1 & 2 divestment to Norges Bank. In addition, Q2 2021 included a positive effect of DKK 150 million from ceasing to report according to the business performance principle. Finally, Q2 2020 included earnings from our distribution B2C and City Light businesses, which we have divested. When we adjust for these effects, earnings in Q2 2021 was in line with last year. Earnings from offshore sites were negatively impacted by wind speeds significantly below the norm. In Q2 2021, the wind speed came in at 7.8 m/s, compared to the normal wind of 8.6 m/s. This difference in wind speeds, compared to a normal wind quarter, translates into a negative EBITDA impact of around DKK 900 million. As expected, Q2 2021 was also negatively impacted by higher transmission tariffs following the divestment of the offshore transmission assets at Walney Extension and Hornsea 1, and lower earnings from Horns Rev 2 due to the subsidy period ending in October 2020. These negative effects were partly offset by the full ramp-up of generation from Borssele 1 & 2, and from the last 400 MW of Hornsea 1 receiving CFDs from April 2021. In Q2 2021, the underlying earnings from partnerships primarily concerned adjustments to finalized construction projects, while Q2 2020 related to the construction of Coastal Virginia Offshore Wind and lower CapEx at Hornsea 1. Our onshore business was positively impacted by the ramp-up of generation from the wind farms Willow Creek and Plum Creek, as well as the solar PV farm Permian Energy Center. The ramp-up was more than offset by lower wind speeds, costs relating to the Brookfield Renewable Ireland transaction, a subsequent credit loss relating to the winter storm period in February 2021, and again from the divestment of Oak Solar in Q2 2020. In bioenergy and other, the underlying earnings significantly increased, driven by very strong performance at our CHP plants, where earnings increased due to higher power prices and sale of ancillary services driven by the colder weather. Within our gas and markets and infrastructure, the significant increase in gas prices led to a net positive effect from revaluation of gas at storage and storage hedges. If we then turn to slide eight, where I will take a quick look at wind speeds across Europe in 2021. In the first half of 2021, we have, as I said, experienced wind speeds significantly below the norm, and the financial impact from these low wind speeds in the offshore portfolio up until end of July is negative DKK 1.4 billion, with the majority of the negative impact realized in Q2 and July. On the slide, the deviations of the wind resource across Europe compared to the historic norm are shown. The light green and dark blue color indicate wind speeds below the norm, and similarly, the yellow and red colors indicate wind speeds above. From these wind maps, it is evident that while the wind speeds in most of Europe have been varying above and below the norm, the areas where the majority of our offshore assets are situated, namely in the North Sea and the Irish Sea. Here, we've seen wind speeds significantly below the norm, especially during the second quarter, and the low wind speeds continued into July. While fluctuations in wind speeds from month to month are completely normal, we regard this prolonged period during 2021 with these low wind speeds as quite unusual, but don't see any structural changes to our long-term wind speed projections. In Q1 2020, we had wind speeds significantly above the norm and realized a DKK 800 million outperformance compared to a normal wind period. The reality is that wind speeds will vary from quarter to quarter, but over time revert to the mean and be quite stable. If we then continue to slide nine and our financial performance and net interest-bearing debt. Net profit for the period total DKK 5.5 billion, a significant increase on last year, mainly due to the Borssele 1 and 2 farm-down gain. In addition, our net financial income and expenses amounted to a negative DKK 0.4 billion compared to a negative of DKK 1 billion in Q2 2020. The lower net expenses were mainly related to lower interest expenses due to the lower net debt. While Q2 last year was adversely impacted by the early termination of the project finance at our U.S. Block Island projects, resulting in a loss on an interest rate swap of DKK 0.4 billion. Finally, our tax on profit for the period was positively impacted by an updated assessment of our uncertain tax position and the increase of the U.K. tax rate from 19% to 25% from 2023. This was partly offset by the initial recognition of deferred taxes related to the tax equity at Permian Energy Center, Muscle Shoals, and our U.S. offshore portfolio. Free cash flow total DKK 1.6 billion in the quarter. Cash flow from operating activities included the tax equity contribution from our partner at the Permian Energy Center. The divestments related to the 50% farm-down of Borssele 1 & 2 and the 25% farm-down of Ocean Wind 1, as well as the final settlement with GIP relating to the Hornsea 1 transmission divestments. Our gross investments totaled DKK 12.1 billion, driven by continued investments into offshore and onshore wind and solar PV farms, as well as the acquisition of Brookfield Renewable Ireland. Our net debt at the end of second quarter amounted to DKK 12.1 billion, the lower net debt during the quarter primarily reflected the positive free cash flow, as I just described. Let's turn to slide 10, which shows our financial and non-financial ratios. Our key credit metric, FFO to adjusted net debt, stood at 63% for the 12-month period ending in June 2021, which is well ahead of our credit metric target. The metric was positively impacted by the farm-down gain of the Borssele 1 & 2 wind farm. Our return on capital employed came in at 12.5%, with increase compared to last year being attributable to a higher EBIT over the 12-month period. We are well on track to achieve an average return on capital employed of 11%-12% between 2020 and 2027, as guided at our recent CMD. Our greenhouse gas emission intensity decreased due to additional offshore and onshore capacity. This was partly offset by higher power generation from our coal-fueled units, where we have a regulatory obligation to make all of our energy capacities available to the market. We remain on track to meet our Scope 1 and 2 target of less than 10 grams CO2 equivalents per kilowatt hour in 2025. Turning to safety, where we have seen a reduction of 10% in the number of injuries. As a result, the total recordable injury rate has decreased from 3.7 in the first half of 2020 to 3.1 in this first half. Let's go to slide 11, where I will go through our implementation of the EU Taxonomy. As part of the European Green Deal to become the first climate neutral continent by 2050, the EU Commission has established the EU Taxonomy as an important enabler to scale up sustainable investments. The Taxonomy is a catalog of environmentally sustainable economic activities. Each with criteria to determine if they sustainably contribute towards a sustainable economy. At Ørsted, we want to be a catalyst for change, and we have committed to taking a leading role in the global green energy transformation. We therefore welcome the new reporting framework, and during the year, we have assessed whether our activities can be identified in the taxonomy and thereby be classified as taxonomy-eligible. Subject to fulfilling certain criteria on sustainability, contributing to at least one environmental objective, not doing significant harm on other environmental objectives, and complying with minimum social safeguards, the activities will be classified as taxonomy-aligned. Although the upcoming EU requirements for reporting on taxonomy-eligible activities does not come into force until January 2022, we have decided to disclose approximate levels for our taxonomy-eligible share of revenue, EBITDA, and gross investments today. We plan to complete the criteria screening before year-end, and also then report on taxonomy-aligned shares in our annual reports one year ahead of the requirements. It should be noted that the numbers we disclose as part of this quarter's results are approximate rather than exact numbers, as some uncertainty related to the final interpretation of the taxonomy still exists. In the first half of 2021, the taxonomy-eligible share of our revenue was above 65%. The non-eligible part of our revenue primarily concerned our long-term legacy activities related to sourcing and sale of gas, fossil-based power and heat generation at our Danish CHPs, and sale of power to end customers. The corresponding share of EBITDA was above 95%, and the share of gross investments was above 99%. Finally, let's turn to slide 12 and the outlook for 2021. We reiterate our full-year guidance for 2021 EBITDA of DKK 15 billion-DKK 16 billion, but we currently expect an outcome in the low end of this range, mainly due to the very low wind speeds in June and July. The guidance assumes normal wind speeds in the last five months of the year. As I mentioned earlier, the adverse effects from the low wind speeds on the entire offshore portfolio up until end of July is a negative DKK 1.4 billion compared to a normal wind year. This negative impact, as well as the warranty provision of DKK 0.8 billion relating to the cable protection system issue, are partly offset by the strong performance from our CHP plants and the high earnings in our gas business, as well as additional earnings from our finalized construction projects in offshore. As in previous years, our EBITDA guidance does not include earnings from new partnerships during the year, which means that the farm-down gain from Borssele 1 & 2 is excluded from our full-year guidance, and so is the gain from the Greater Changhua 1 farm down, which we expect to close later this year. Looking at the directional guidance for our business units, we changed the offshore guidance to significantly lower from lower due to the very low wind speeds and the warranty provision related to the cable protection system issue. Moreover, we changed the directional guidance for bioenergy and other to higher from previously lower, following the high earnings from CHP plants and gas markets and infrastructure in the first half of 2021. We are increasing our gross investment expectations to DKK 39 billion-DKK 41 billion from the previous level of DKK 32 billion-DKK 34 billion. The increase reflects the Brookfield Renewable Ireland acquisition and the associated CapEx spend for the remainder of 2021, as well as the expected acquisition of the fully constructed Lincoln Land project. With that, we now open up for questions. Operator, please. This concludes our presentation. We are now happy to answer your questions. This call will have to end no later than 3:30 P.M. Please respect only one question per participant, then you can go back to the queue for a second question. If you do wish to ask a question, please press zero one on your telephone keypad. If you wish to withdraw your question, you may do so by pressing zero two to cancel. Our first question comes from the line of Deepa Venkateswaran from Bernstein. Please go ahead. Thank you. My question is on the Lincoln Land Wind project. Given that this is, when you acquired it's already constructed by someone else, that seems to be a bit different from the previous acquisitions that you've done. Maybe you can elaborate on the rationale other than just the diversification on MISO and maybe talk on the value creation. Secondly, should we expect more of such deals where you would acquire existing projects, or should we look at this as a one-off? Thanks a lot, Deepa. I can have some comments to that, and Marianne, feel free to supplement. I think honestly, I think the two main reasons are that this is really an important diversification into MISO, as mentioned, but also that it is a value-creating project. We will generally maintain our focus on greenfield development. That's what we do best. When we do come across opportunities like this one that we believe we can buy well and therefore also create value from, then this is something that we will opportunistically choose to do, which was the case of this time. I'll also mention that this actually did come, we have not mentioned that, but this did come with another early-stage development opportunity as well, which is something that adds additional value to this acquisition as well. Thank you. Did Marianne want to add anything? No, I think it was covering. Okay. Thank you. The next question comes from the line of Alberto Gandolfi from Goldman Sachs. Please go ahead. Good afternoon, thank you for taking my question. I wanted to go maybe back to the topic of equipment. When we look at your slide five, you're in the final straight, particularly in offshore on Hornsea 2 and Greater Changhua, but there's about 8.5 GW of awarded projects where you have not begun construction yet. You have already set your top line on those projects. What I was wondering is, can you give us, please, more color on fixed costs procurement strategies? Specifically, how much of the equipment is pre-procured on a fixed cost? Do you still need to hire staff to develop those facilities? Have you already fully secured any third-party vessels or ships or EPCs that you might need? Perhaps you can talk about as well, if you've been able, also elaborating, extending, sorry, this point to cables, not just to the turbines. I'm just trying to figure out how we should think about cost inflation on those awarded projects. Thank you so much. Yeah. Thanks a lot, Alberto. I can try, and it's obviously a quite complex issue, but I'll say just as a fly-in to this, generally, the impact of the cost inflation sort of short and midterm is more moderate. It's obvious that many of these projects are being constructed quite a few years into the future, and therefore, if the current inflation rates either sustain or even worse, continue up, then of course there is an impact of this. As we elaborated in our Capital Markets Day, we are doing a number of things on these projects to ensure that we create predictability and certainty as to what our cost levels are going to be. That will never secure the full cost. There will always be an exposure. In this case, yes, we did secure vessels for some of these upcoming projects. We have worked with cable manufacturers for a while and have settled prices on some of that, also for HVDC cables. We are locking in also some of the heavier raw material categories such as steel. I believe we said that up to 70% of the near-term U.S. construction projects or nearer-term U.S. construction projects, we actually have that transparency already. Then, of course, what we try to do is, as early as possible, to lock the agreements with our suppliers to ensure that we create the transparency. There is, of course, if you look at projects that are going to be constructed all the way through 2029 as the latest one, there will of course be an exposure. We do believe that we are generally in a good place and compared to some of the many industrial companies, but also some of our partners in the supply chain. We are less exposed, with a moderate impact short to midterm, but of course, it's something we are following incredibly closely. I guess this is, Marianne, unless you want to add something, I think this is as close as we can get because it very much is a project-by-project approach. The next question comes from the line of Robert Pulleyn from Morgan Stanley. Please go ahead. Hi. Thanks. Good afternoon. I think the cost inflation might be done. May I just ask on the CapEx guide, previously it was DKK 32 billion-DKK 34 billion. The new one's DKK 39 billion-DKK 41 billion. Brookfield, I believe, is about DKK 4.2 billion. There's Lincoln acquisition. I was just wondering whether you could confirm, is there any other movements in your CapEx guidance that we should be aware of? In particular, is there any sort of inflation to existing CapEx expectations in 2021 captured in that uplift? That's the one question. Thank you. Yeah. Yes, I'm happy to answer. No, the increase only reflects the two things that you mentioned there. The Brookfield, the acquisition price, including the CapEx spent for the remainder of the year. That's approximately DKK 5. The last two is the Lincoln Land. It's purely that. No cost inflation in that number. Marvelous. That is great to hear. I will turn it over. Thank you. The next question comes from the line of Kristian Johansen from Danske Bank. Please go ahead. Yes, thank you. My question is regarding your earnings in bioenergy and other. Just wondering around the dynamics, if power prices stay at these levels and the same with gas prices, should we expect a continued elevated earnings level for this business? There's two different answers to the different areas. Yes, for bioenergy, we benefit from these prices. If we continue to see these prices, we will see elevated earnings. On the gas business, that is actually, as I've said many times before, it is a margin business. These positive fluctuations we see from revaluation of storage, and hedging of these storages, that is in a way, timing effects that will net out over time. We have positive earnings in the business, but it's not the same volatility as you will see in the CHP piece. Karen, if I can just briefly add. Also bear in mind that the Q2 over-performance in bioenergy was obviously both driven by the power price level, but also driven by the unusually cold spring in Denmark with April and also the first half of May. We did produce and sell a significantly higher share of value-creating heat from those plants as well, which contributed to the very strong performance in Q2. Understood. Thank you. The next question comes from the line of Sam Arie from UBS. Please go ahead. Thank you very much. Thanks for the presentation today. I think you explained very clearly on the quarterly results and the wind speed impact. I don't have any questions on that. I'd just like to ask one sort of bigger picture question now, coming back again to your very interesting page five. On the right-hand side of this, you show us your substantiated pipeline, which you also had in the CMD slides. I just wanted to ask, my assumption is all of this is going to get built. The question about auctions and so on is just what's the timing? Which assets get built when? I think if you look at the bigger picture in the world and the IPCC report this week and so on, it's hard to imagine that that 22 GW there isn't going to get built. Can you talk to us just a little bit about, I suppose, if there's anything in there which is kind of competitive, i.e., maybe there's 1 GW in there which you could lose to somebody else somehow, or is that all 22 GW of rights that only you can develop? Can you tell us a little bit about what it costs to add 1 GW to that substantiated pipeline? Another way of looking at it, how much should we expect that substantiated pipeline to grow going forward? Thanks a lot. A little bit off topic of Q2, but I'd love your comments on those. Thank you. Thanks a lot, Sam. Starting from the back, we can't say what it'll cost because it really is an impossible question to answer. We don't know what future seabed auctions will net out with, whether it's upfront payments or whether it is market development or whether it is simply commitments to doing local development. It really is borderline impossible to give an average number for that. You are right that if we speak primarily about the 12 GW of offshore farm or substantiated pipeline, a majority of that is actually proprietary seabed leases, which will very likely materialize, or it's unlikely that they won't materialize. There are also parts of that which is something we are developing together. For example, our Japanese bits would also be in there. That would mean that there is, of course, a risk that part of that will not materialize. The majority of it will, primarily a matter of time, but there is also some of it where there is a risk that it won't materialize, and therefore, that we will continue. We'll of course, work hard to continue to take some from our so-called substantiated pipeline and move into the firm pipeline so that that continues to go up to ensure that we safeguard our ability to deliver the 30 GW in offshore and the 50 GW in total. We also strongly believe that most of the onshore pipeline will also be built. Yes. There we are not up against competition on any of it. It's a number. Yeah. It's a pipeline that we feel very comfortable with. It is likely that a smaller part of that will not be built, but we also know that we are working to constantly increase that pipeline. Okay. Very good. I'd love to follow up, but actually, I think you've said a lot, so I'll just say, thanks very much. I'm sure we continue that discussion next- Happy to. The next question comes from the line of John Musk from Royal Bank of Canada. Please go ahead. Yes. Good afternoon, everyone. I just want to get your sense of what you think investors will be looking for in the future. Do you need to tick all three boxes around revenue, EBITDA, and CapEx? Obviously, the revenue number is much lower, and I'm perhaps slightly surprised by that. As a consequence of the answer to the first question, is there a need for you to do anything about that? Is there any way you can influence that other than further disposals of those non-compliant businesses? Good question, John. Thanks for that. We will focus on all three, and all three of them we see as equally important, and we think also that the markets see all three as important. On the revenue side, we are at 65, which in a way might seem low when you compare to the EBITDA number. It will be reduced. We have this reduction target for Scope 3 emissions. We have a lot of gas, that in a way will be taken out as the contracts expire. We have also seen that we are scaling down on the customer business. We made this divestment last year. The revenue part will significantly increase over time. One of the issues we have is that we cannot always distinguish between what is green power when we sell something and what is black power. If we can't distinguish, in a way, we cannot call it eligible, and therefore it goes into the black, you can say. As we mature, we will see this number going significantly up. As we understand it, being above 50%, in a way, is for now, in a way, something that many would be striving for. Our target is, of course, significantly higher than that. Is there a target that you're willing to communicate on that, what number on the revenue side? No. Since, in a way, the Taxonomy is not completely clear yet and there's still details missing, we haven't set a target. Although not the biggest part of the remaining 35% of the non-eligible, bear in mind, we have committed that our last coal-fired combined heat and power plant is decommissioned in 2023. That share will go away relatively short term. Okay. Thank you very much. Next question comes from the line of Dominic Nash from Barclays. Please go ahead. Good afternoon, and thank you for letting me ask a question. Can I ask a question on power prices? It's kind of similar to the inflation questions from earlier. When you look at the forward curves, you can see that they've shot up quite a lot in emerging markets. What's the potential sensitivity to you and your sort of hedging policy on your assets selling into this? On the medium term, what we're seeing today with the significantly higher power prices, is that going to impact your view of what you put into your numbers when you bid for these PPA auctions in the shorter term? Are you currently just sitting on the long term, still the same power price as we were 12 months ago? Yeah. You can say that with the position we are in, where we have subsidies and we have PPAs and we have a very high hedging percentage, we don't have much merchant exposure. That means that basically we don't benefit from the current high power prices, which of course is not good in this market, but which we have benefited from in many other situations. We are more than 90% hedged and from a very small exposure, because most of it, as I said, is subsidies. Where we can benefit is that we have our hedging strategy, and we are now able, when we roll in quarter by quarter, we can hedge at higher levels in year three and year four, for example, than we could just half a year ago. This does not change our view on the long-term power prices. Therefore, when we bid into these auctions, we still use, in a way, the same fundamental models that we have for long-term power prices. Thank you. The next question comes from the line of Jakob Magnussen from Danske Bank. Please go ahead. Thank you very much. It's a question on your adjusted net interest-bearing debt. You used to include asset retirement obligations, the net value of those in your definition of adjusted debt. I can see here in your table in note 13 that you no longer include those, so you get a lower figure for net interest-bearing debt on adjusted basis. Thereby, this also improves your FFO to adjusted net debt. I was just wondering why you are no longer including these asset retirement obligations in your definition. Yeah, good. Thanks. Good question. We have three rating agencies giving us a rating, as you know. There's only one of them that includes these asset retirement obligations, in their definition. The one that is the strictest one does not. Therefore, in a way, we try to make something in between these three rating agencies' requirements. And we found out that the right thing was to exclude it, in a way, since two of them don't include it. As I said, the strictest one don't. That's the reason. We have been punishing ourselves a little bit too hard. Okay. You're still hanging on to your 25% lower boundary target? Yes, we are. Okay. Thanks. The next question comes from the line of Louis Boujard from Oddo BHF. Please go ahead. Yes, good afternoon. Thank you for taking my question. Just regarding the short-term guidance to have a bit more color on it. I was wondering if you could give a bit more details on what you mean by higher or significantly higher or lower or significantly lower, if it is an absolute number or a percentage. More specifically, when I look at the onshore, for instance, you are DKK 100 million below last year. In the meantime, you expect higher. I know that there is some commissioning that are going to kick in in the second half. In the meantime, the consensus, I think, is already at DKK 1.65 billion on the figure. Does DKK 1.65 billion is significantly higher or only higher compared to the DKK 1.1 billion that you posted last year? Yes. I'll try to give some more color first on the guidance because I think it's quite relevant for you to understand, in a way, why we can stick to our guidance when we have these DKK 2.2 billion impact from the cable protection and the lower wind. I'll start there, and then I'll go a little bit more into detail with your other part of the question. Yes. Here we say that, in a way, when we started with the first guidance 2015 to 2016, we were at the upper end of the range. Let's say we were at 16. You deduct the DKK 2.2 from these two negative effects I just referred to. The question is, what is it that can offset these very big negative impacts? It is approximately DKK 500 million better result from construction gains, which the major part comes from the Hornsea 1 transmission asset divestment, where we got this final calculation from the authorities, which gave us a higher gain on that. DKK 500 million from construction gains. We are DKK 600 million higher on our CHPs, compared to what we estimated when we started the year. We always use the forward curve when you calculate this, but in a way, the prices are significantly higher. The remaining positives to come up to the lower end of the range, is effect from revaluation of storage due to the high gas prices. It is the impact from the Brookfield and the Lincoln Land acquisition, and then it is lower cost. That brings us up to the lower end of the range. Then you ask, in a way, what definition do we have on higher and lower and significantly higher and lower. We haven't shared that. We have some strict internal rules we use, but it's not something. It might be, we share it one day, but for now, in a way, we have chosen not to share it. Sorry for that. I hope you could use my answer on the first part of your question. Yeah. Thank you for the first part of the answer. Just as a final reminder, if you do wish to ask a question, please press zero one on your telephone keypad now. The next question comes from the line of Sam Arie again from UBS. Please go ahead. Oh, hi. Sorry, I couldn't resist coming back in for just one follow-up on the previous discussion. I apologize for dragging this again away from Q2 and back to the topic of the future. If you look at that substantiated pipeline on your page five, I asked if you could sort of talk about how much it costs to grow, and you said that's very difficult. Could you tell us how much it has cost to build the 22 GW that you have there? I'm not sure if that's a number you've given before, it would be very interesting to know. The reason I ask is, a question I get a lot of the time on valuation is, how much do we think the business would be worth if you never won another project, the sort of ex-growth valuation. I think that anybody looking at the shares through that lens ought to add the value of the pipeline assets, because even in theory, if you didn't develop them, they would have value and somebody else would. I just wonder if you can tell us kind of how much invested capital is in the substantiated pipeline, roughly speaking. Again, I don't think we can give a very specific number, but I think when, for example, the seabed leases in the U.K. for Hornsea 3 and 4, but also the North American seabed was acquired, it was actually a very low price. Next to zero. Next to zero, incredibly low. Today it represents north of 8 GW of substantiated pipelines. You can say that what's tied up there is very little. Then for when we buy into a development project, as now as, for example, in Japan, if somebody has been developing that, we would pay an amount for that, but also a relatively minor amount. I think it's fair to say that the current, again, I'm speaking primarily for offshore here, but that the price tag on the current 12 gigawatt is actually small. It's a low price tag. Yeah. If we should sell it today- It's totally different. it's a totally different story. We haven't paid a lot for these seabed. Of course, we are spending money on getting the EIAs on the whole permitting process, which is something we expense. We are talking, of course, many DKK billion for if you look all together just on Hornsea 2, Hornsea 3, Hornsea 4, in a way. It is a significant amount that we are spending, that we are taking through the P&L. Yes. Yeah. Also that, like Marianne says, the value of it today, if divested, which we have no plans to do, that would be totally different because what has happened since then with the, not least the recent seabed auctions. Yeah. Thank you for that clarification, because I was going to jump in there, Mads, for a minute and ask if you were talking down the shares for a minute. I think that you make the point very interestingly now. It's a little bit like the discussion we had on the RWE call earlier today about their carbon hedges, some of which they put on at very low values when the market didn't see the value, but which they now have on the balance sheet and are obviously worth massively more. Yeah. I think the value of that substantiated pipeline is a huge topic that we should keep discussing. It is an incredibly valuable asset, I think the ability to bid into the upcoming, for example, CfD AR4 round in the U.K. with our Hornsea 3 lease is one that will allow us, which we firmly believe to both be very competitive and also have a very value-creating project. That obviously is a privileged position. Very good. Fingers crossed for that event, and thanks again for your follow-up answers. We have another follow-up from Kristian Johansen from Danske Bank. Please go ahead. Yes, thank you. Just on your German zero- subsidy bid, I think that's what you call Borkum Riffgrund 3 now. As I recall it from when you got the allocation, you needed to take a FID by 2021. Can you just remind me whether that's correct, and, in that case, what the status is of that project? That is correct, Kristian. We expect to take FID in Q4, and we are well on track to do that. We can also say that the process of securing PPAs for that project is going very well. Extremely well, yeah. That was sort of my follow-up. It was more in terms of whether you have secured a sufficient amount of PPAs for that project or whether you need to secure more before taking FID. We can say that it's a highly attractive asset, so we are well covered. Understood. Thank you. The next question comes from the line of Dominic Nash from Barclays. Please go ahead. Yes, thank you for the follow-up. The question I've got here is the OFTOs in the U.K., as I understand it, have a sort of 20-year contract with yourselves. I think they're under consultation at the moment with Ofgem as to what happens in year 21. I'll just be interested to hear what you think the remuneration that you will need to provide to the OFTO owners would be, and when do we expect to get the response from the consultation? Thank you. Are you now talking about Hornsea 2 OFTO? I'm a little bit uncertain around the question. Sorry for that. No, all of them. All your wind farms are connected up to transmission assets, but I believe they're only on 20-year contracts. Yeah. That's all settled and agreed upon. We have fixed agreement and fixed transmission fees we pay. In a way, it's a completely regulated process, and the only thing that for us is the important thing is, in a way, what is the return requirement by the buyer? Because the lower the return requirement, the better for us. Then it is whether we get the allocation price approved, so whether we get some cost that we don't get covered. That's the only uncertainties. The rest is, from our point of view, completely regulated and certain. Oh, okay. Maybe I've missed it then, but I didn't know that we'd agreed a price yet for year 2021. I thought it was still up for debate. Yeah. We actually know the TNUoS, as it's called, for the whole period when we make the divestment, because that's built into the whole system. Okay, thank you. We have one more follow-up question from Deepa Venkateswaran from Bernstein. Please go ahead. Thank you. I wanted to ask a follow-up on the cost inflation, particularly because on the turbine contracts, there is an element of cost indexation where it's automatically passed on. Just wanted to check with you, obviously, you've talked about the hedging on the U.S. projects, but more broadly, at what point do you lock your costs down? For the German project, for which you've not taken FID and haven't placed a firm order, I presume the indexation would work against you for now. Just wanted to talk in terms of the indexation that we see and how that pertains to how you manage your risks. Yes, Deepa, you are right. In a way, we are sitting on the steel exposure. We do it case by case. Sometimes, in a way, we have gone and hedged like we did for the U.S. portfolio. We have not done that for Germany. Yes, you are right, we have an exposure there. It's, in a way, our choice when we need to lock it in. That is already, in a way, these high prices is built into the business case that we will take FID on in Q4. Okay. Presumably the improving power prices means that any PPAs you can sign now can be at a better price. Yeah. That's the dynamic of it. the 10% or so that might be the increase. Yeah. You're right. Okay. Yeah. Okay. Thank you. As there are no further questions, I'll hand it back to the speakers for closing remarks. Yes. Thank you. All we have left would be to say thank you very much for great questions and insightful questions. Thanks for your trust and support, and have a great day.