Guidance

Jan 20, 2023

Summary

2023 EBITDA guidance is DKK 20bn–23bn excl. new partnerships, with offshore earnings expected to rebound sharply. Hedge reforms, Sunrise Wind impairment and U.S. project economics remain key focus areas.

Welcome to the Ørsted conference call. For the first part of this call, all participants are in a listen-only mode. Afterwards, there will be a question-and-answer session. To ask a question, please press star five on your telephone keypad. This call is being recorded. Today, I am pleased to present Mads Nipper, CEO, and Daniel Lerup, CFO. Speakers, please begin. Good morning, everyone, and thank you very much for joining the conference call. Yesterday evening, we published our preliminary and unaudited EBITDA for 2022, as well as our expectations for 2023. In a year with highly unusual market conditions, not least the very volatile energy prices and a substantial increase in inflation, we are pleased to achieve our latest 2022 EBITDA guidance, which is, in fact, above our initial expectations for the year. The significant volatility throughout the year led, however, to a very different composition of our earnings mix than we had expected. We benefited from our diversified asset portfolio and achieved significantly higher earnings in both onshore and Bioenergy & Other, which gained from the market conditions and outperformed our expectations going into 2022, while earnings in offshore decreased. To a large extent, the unexpected negative development in offshore was driven by adverse impacts from hedges and delays at Hornsea 2 and Greater Changhua 1 and 2A construction projects. Despite these unusual market conditions and challenges, we achieved a record-high EBITDA, including new partnerships of DKK 32.1 billion, which is a notable milestone for our business. And similarly, our EBITDA, excluding new partnerships of DKK 21.1 billion, was a record-high EBITDA for the company. As a response to the unintended adverse impacts from our hedges, we have established and are now in the process of implementing a new risk management framework to reduce the volatility from our hedging instruments and bring back the inherent predictability of earnings that our very high degree of contracted and regulated activities possess. Supporting our financial performance is an operational fleet of assets continuously operating at excellent availability rates and contributing to the security of energy supply across all markets in which we operate. At the nine-month reporting of 2022, we updated our full-year guidance for 2022 based on the latest outlook for power prices and weather conditions for the remainder of the year. Since then, we have seen unexpected developments, which, as I said, led to a different composition in our earnings mix. In offshore, we saw several adverse developments towards the end of the year, including ineffective hedges, volume-related over-hedging, as well as higher balancing costs. In addition, we saw further installation delays at Greater Changhua 1 and 2A. In Bioenergy & Other, we realized significantly higher-than-expected earnings from our gas storage activities and released a provision related to our B2B business in the U.K. This was partly offset by lower earnings from our CHP plants due to the lower-than-expected power prices. Going into 2023, we expect a significant increase in the earnings from our renewable assets, while earnings from our Bioenergy and Other business is expected to decrease due to lower energy prices. Daniel will elaborate further on our 2023 expectations in a few minutes. I will also take this opportunity to say that we remain very confident in our long-term EBITDA growth ambitions. Despite the recent unexpected and adverse developments, we do remain confident in our business, the renewable sector, and its promising outlook. Over the past two decades, we have transformed ourselves from a fossil fuel-based company into a global leader within the renewable sector. We realized this transformation due to our strong and innovative capabilities within project development, construction, and operations. We continue to see increase and exciting opportunities across our business segments, exemplified by increasing targets and support by governments for the build-out of renewables. At the same time, we are encouraged by the political support towards our industry, such as the Inflation Reduction Act in the U.S. and the proposed Net-Zero Industry Act in Europe, which would expand the addressable market and represent an important support for the entire industry. We will continue working towards our vision of a world that runs entirely on green energy. Turning to our next slide, where I will cover the impairment that we have incurred in 2022 related to our U.S.-based offshore wind project, Sunrise Wind. The offshore wind energy industry faced unprecedented cost inflation and rapidly rising interest rates in 2022. Our 50% owned U.S. offshore wind development project, Sunrise Wind, has been particularly impacted by these general market trends, as well as project-specific CAPEX increases. As previously disclosed, the project costs have increased substantially since we were awarded the bid. In the past year, it has experienced further acute cost increases, specifically driven by the prices for installation vessels and the associated services. Rising interest rates have had a corresponding impact on our cost of capital, despite the benefit of our previously discussed $2 billion U.S. dollar interest rate swaps. The higher cost of capital and cost increases have been partially offset by anticipated increased tax benefits from recently enacted tax legislation in the U.S. As a result of these factors, we will recognize an impairment of DKK 2.5 billion on Sunrise Wind in 2022. Notwithstanding this impairment, I want to emphasize our continued commitment to Sunrise Wind and the rest of our U.S. offshore wind portfolio. We will continue to work to mature and develop the projects with the aim to ensure that we can deliver renewable energy to the states with a satisfactory value creation. We continue to explore all ways in which we can improve the project economics, and similarly, we will continue our constructive dialogue with all relevant stakeholders and partners. With that, I will now hand over the walkthrough of our fourth quarter EBITDA and 2023 guidance to you, Daniel. Thank you, Mads, and thank you everyone for joining the call. Let me start with slide five and the EBITDA developments for the fourth quarter of 2022. For the group, we realized an EBITDA excluding new partnerships of DKK 6.6 billion compared to DKK 5.0 billion for Q4 2021, implying an increase of 31%. In offshore, we realized an EBITDA of DKK 3.7 billion, which is slightly below last year's results. There have been a number of moving parts within the quarter that I will now walk you through. For Q4 2022, wind speeds were slightly higher the same quarter last year, which led to a positive impact of around DKK 200 million. However, the wind was below the norm. For the quarter, we saw a number of unintended developments related to our hedging framework. We have recognized a loss of DKK 0.7 billion related to inflation index power purchase agreements on some of our U.K. ROC assets. This loss reflects future losses that we anticipate to realize on these contracts if inflation and power prices remain at current levels. In short, we agree to buy our partner's share of the power generation from our U.K. ROC assets within a cap floor structure that is inflation indexed to provide them revenue certainty. To reduce our associated power price exposure, we have entered into power hedges that reflect inflation expectations at that point in time. Since actual inflation forecast has outpaced inflation expectations, there are a portion of our hedges towards 2026 that are deemed ineffective, and as such, we are required to recognize this loss in our P&L immediately. However, if inflation expectations or power prices decrease again, we will reverse part or the full amount that we have recognized in our accounts. Additionally, post-COD expiry of the hedges in 2026, we will benefit if power prices are above the partner's cap price. Also, we saw negative effects from volume-related over-hedging. When we hedge our future power generation, we try to take into account the difference between the price we will receive from our power generation and the price our hedges will be settled at, i.e., what we describe as intermittency. In addition to cater for intermittency, when we enter into hedges years in advance, we have entered into trades to mitigate the more near-term risk of even higher price differences between peak and off-peak periods over the 2022/2023 winter period. Throughout the past quarters, the volatile and high power prices have resulted in a positive market value of these hedges. However, the value of these trades were reduced during the fourth quarter due to the narrowing of the base peak spreads. As we cannot apply hedge accounting on these trades, we have recognized a negative impact in Q4. However, the market value of the hedges remains positive given the future outlook on peak and off-peak periods. The negative impact was partly offset by a lower level of over-hedging than in Q4 2021. Finally, we saw a positive effect from the IFRS 9-related hedges of DKK 0.1 billion in Q4 2022. On the topic of hedging, I would like to reiterate the message that we are in the process of implementing our new hedging framework. Going forward, we will reduce the hedging levels and shorten the horizon to minimize the risk of future unintended adverse hedging impacts. Our hedging frameworks have historically served us well, as it has provided us stability and visibility of earnings. However, due to the significantly higher power prices, we have seen adverse impacts to our financials when we have not generated power at the levels we had forecasted when we hedged the production. Realizing the effects from our revised hedging framework will take time. Despite not having entered into new power hedges since late 2021, we have a high hedge level in offshore for 2023. If prices continue at a high level, we expect to continue to see offsetting effects in the portfolio and thus a low risk to our overall financial performance. As a proactive way of reducing the unintended impacts from our hedge portfolio, we have opportunistically bought back forward sold volumes at favorable prices to reduce the risk of over-hedging. Going into 2023, we now see a lower hedge level compared to 2022 of around 90%. On a group level, we hold a hedge level of around 70% for 2023. On the updated hedging framework, we will communicate more details as part of our full year results on February 1st. For the remaining part of our offshore sites, earnings increased by DKK 0.2 billion, driven by ramp-up generation at Hornsea 2 and from value-creating market trading activities. This was partly offset by negative effects from our high ROC recycle settlements in Q4 2021, higher-than-expected balancing costs, and our expanding portfolio leading to higher OPEX, BSUoS, and TNUoS tariffs. Earnings from our existing partnerships were DKK 0.1 billion lower due to further commissioning delay of the turbines at Greater Changhua 1, increasing the total project costs. Consequently, this reduced earnings under the construction agreements. Turning to onshore, we increased earnings more than 60%, mainly driven by ramp-up generation and higher achieved power prices across the portfolio. In Bioenergy and Other, we increased earnings close to 50%. For our CHP plants, earnings were in line with Q4 2021, whereas earnings within our gas business increased by DKK 1.3 billion compared to Q4 2021. This increase was mainly driven by a positive effect from our gas storage activities and the release of a provision related to the close-down of our B2B business in the U.K. Turning to the next slide, I will walk you through our financial guidance for 2023. As in previous years, our EBITDA guidance does not include earnings from new partnership agreements. EBITDA, excluding new partnership agreements, is expected to be in the range of DKK 20 billion-DKK 23 billion in 2023. We have expanded our guidance range from previously DKK 2 billion to DKK 3 billion due to increasing energy market volatility. As in 2022, we could see offsetting effects between the business units compared to our directional guidance. Within offshore, earnings are expected to be significantly higher than in 2022 due to a number of factors. In 2023, we expect a positive impact on EBITDA from the ramp-up of generation from Changhua 1 and 2A, which we are expecting to be commissioned in the second half of 2023. The negative impact from overhedging and ineffective hedges are not expected to be repeated in 2023. Also, we expect an upside to our assets under CFD and ROC regimes, as related subsidy price will be inflation-adjusted in April, providing a positive effect from Q2 2023 and onwards. For our remaining sites, we expect a positive impact due to the higher generation from Hornsea 2 and lower balancing costs. This will be partly offset by higher operating costs and lower expected trading results. We do not expect material earnings from our existing partnerships. Finally, we expect an increase in costs related to project development, our P2X business, as well as general cost inflation. Turning to onshore, we expect earnings to be in line with 2022 due to a number of offsetting effects. We expect ramp-up generation from the wind part of Helena Energy Center, Old 300, Sunflower, Haystack, and Ford Ridge. Additionally, we expect a positive full-year earnings effect from Ostwind, which we acquired in Q2. The ramp-up will be offset by expectedly lower prices in the U.S., as well as price caps in Ireland. Finally, we expect a slight increase in project development and general costs. In Bioenergy and Other, we expect earnings from both our CHP plants and gas markets and infrastructure to be significantly lower than in 2022. In 2022, our CHP plants benefited from very high power prices and spreads, which is not expected to be repeated to the same extent in 2022. In 2022, earnings in gas markets and infrastructure saw a positive effect from optimizing our Northwestern European gas activities, where we were able to lock in gains from the offtake flexibility in some of our sourcing contracts and gas storages. In addition, we had a positive effect from the release of a provision related to our B2B business in the U.K. In 2023, we expect earnings to be fairly limited, reflecting normal margins in these activities, as well as lower volumes due to the lack of the Gazprom volumes. Despite the challenges faced in 2022, we are encouraged by the fact that the financial outlook for 2023 showcases a significant earnings improvement from our operating renewable energy assets, particularly within the offshore business. As per our guidance for 2023, we are expecting to see earnings increase of more than 80% for our generating offshore assets. It is a key growth and value-creating part of our business, and going forward, we will continue our work towards securing a stable and visible level of earnings that our renewable assets are capable of delivering. Let there be no doubt that despite the record-high EBITDA results within our guidance, we are disappointed with the many adverse impacts from our hedging activities. In 2022, we have learned the hard way that our long-standing risk management framework was designed for very different market conditions and had ended up being too complex. We are taking the consequences of this and are now implementing a new framework. While 2023 will still be a transition year, the new framework will. The new framework will continue to support high predictability of earnings while substantially reducing the downside in extreme market conditions. With that, over to the operator. Thank you. To ask a question, please press star five on your telephone keypad. To withdraw your question, please press star five again. We will have a brief pause while questions are being registered. The first question is from the line of Deepa Venkateswaran from Bernstein. Please go ahead. Your line will be unmuted. Thank you. My two questions. On the 2023 guidance, it is a bit below what the street has been expecting. I just wanted to check, what is your assumptions on adverse hedging impact into 2023? I think a lot of us have probably assumed a clean unwind, but can you let us know what is implicit, at least in the midpoint of your guidance on further hedging losses or proxy hedging or whatever? Secondly, is there anything else of a one-off nature or anything that you think the market might have missed in its expectations? My second question is on the U.S. impairments. Firstly, wanted to understand why only Sunrise and why not the others? I mean, if you look at the auction prices of Sunrise, it was at the upper end. I was just wondering what was specifically about Sunrise. Could I also check that when you have done your impairment, is it only on the DevEx that you have incurred so far, or is this kind of looking further out, including any future CAPEX that you might put and the overall value creation, and this is a forward-looking impairment? Just checking whether you are going to have ongoing impairments on this or the other projects. I suppose you reinforce your commitment to these investments, so could you just kind of maybe square the circle on registering the impairment but continuing to invest in the U.S.? Thank you. Yes. Thank you, Deepa. As you can see in the guidance slide, we have roughly DKK 6 billion coming back on hedges in 2023, as the impacts we saw in 2022 were mainly effects relating 2022. We will have a small runoff of the IFRS 9 temporary effect that now sits at roughly DKK 1.2 billion for 2022, and a couple of hundred million DKK we expect will be running off in 2023, and that is accounted for in our guidance. When it comes to the impairment- Maybe just one more comment here, Deepa. You asked, are there other things that the market could have missed? That will, to a very large extent, because we are looking at probably a different ramp-up curve for Changhua 1 and 2A than the market expects, because we have previously expected, A, a delay which would be going into the beginning of the year, and that will now extend into the second half of the year. So the miss on generation compared to when that would be close to fully ramped up is, we believe, the other key component that we would highlight which could be contributing to that miss to market. Impairment, Daniel. Yes. On impairment, as we said, we are fully committed to the entire U.S. portfolio, and we do still see value in that portfolio. The reason why we are now doing an impairment on Sunrise Wind is, of course, due to the general cost increases on both CAPEX and interest rates. But specifically on Sunrise, that is one of the later projects in the NEP portfolio, meaning that it has taken a harder hit on the transportation and installation costs compared to the other projects. We have, of course, gone through all of the projects now for impairment purposes, and we are not expecting that we will need to impair more going forward. But as you know, this is, of course, depending on, among other things, the development in the interest rates. The value that we have impaired is not the full value that we have on our books for Sunrise. It is a little more than half of that. That is a combination of both DevEx that we have capitalized and then regular CAPEX elements. Okay. Thank you. Thank you, Deepa. The next question will be from the line of Casper Blom from Danske Bank. Please go ahead. Your line will be unmuted. Thanks a lot. Just as a follow-up to Deepa's questions regarding the U.S. portfolio. You say you still see value in the portfolio. Is that to be interpreted as if all projects, in your view, still hold a positive NPV, though not with the same IRR as originally expected? That would be my first question. Secondly, on the offshore sites earnings, if we look a bit ahead, have you made any changes to your longer-term expectations to what level of earnings those assets can generate? I mean, are you taking into account higher OPEX than originally planned when you got these projects years back, or anything else that even if you're still within your 2027 EBITDA guidance of DKK 35 billion-DKK 40 billion, has there been some sort of movement within that range? Thank you. Yes, I can kick it off. Good morning, Kasper. When we say that we believe we can make value-creating cases from the U.S. and we're going through this impairment test, yes, it is clearly our ambition and our expectations that we can do NPV-positive cases in the U.S. As we mentioned, we are in continuous and good dialogue also with key stakeholders, including, for example, in New Jersey, with the relevant stakeholders that give us that belief. I can't be more specific than that, but we do clearly believe that it is a portfolio which will be able to be positive. On the longer-term value creation in offshore sites, then you're right, there are additional costs. But on the other hand, the inflation indexing of our contracts means that on a net overall, that should actually be a positive. We have not, in that way at least, seen any adverse impacts on our longer-term outlook for our portfolio. If anything, on the contrary. Interesting. Thanks a lot, Mads. Thank you, Kasper. The next question will be from the line of Alberto Gandolfi from Goldman Sachs. Please go ahead. Your line will be unmuted. Thank you, and good morning. Thanks for taking the time to go through all of this, and for the patience. I'm going to go back to the impairment again, if you don't mind. There's a question split into two. The first question is, forgetting one second about the impairment, if you were to mark to market equipment costs today and interest rates today, do you think that the U.S. project backlog is NPV positive? What would be an IRR divided by WACC, you think, right now on this basis? The second question, forgive me, my line fell temporarily. If this has been asked, but why only Sunrise and why only half of the impairment here, if I understood this right? So, what makes this special? If the conditions remain as they are, should we expect more impairments on the rest of the backlog? An appendix to this, does this make more or complicated the idea of finding partnerships that will pay you a premium over invested capital if the net present value of this project is not as you expected it to be? Thank you so much. Yeah. Thank you, Alberto, and I will start from the bottom. It is not our expectation that this will impact the investor interest in a situation where we want to go out and farm-down. They will, of course, be looking at the forward-looking cash flows. As we said, we still see value-creating cases in these projects, and that will, of course, also be the basis for what we would be divesting at a later point in time. The reason why Sunrise has ended up being impaired and not the others is because Sunrise in the NEP portfolio is the last part to be built, and therefore also the project where we have signed some of the bigger contracts latest on in the cycle of signing the contracts, and therefore deeper into the cost inflation and supply chain bottlenecks that we are seeing. It is again, back to what we have indicated earlier, that we are seeing a significant increase in cost on transportation and installations, and that is the impact that we are seeing on Sunrise. Also, the fact that it is being built at a point in time where there is a lot of competing projects being built in 2025. The first question you asked, Alberto, I am actually a little bit in doubt what the question there was about. Could you maybe repeat that? I am not going to give an IRR over WACC indication to you. Absolutely. No, what I was wondering is, the impairment you just announced last night, does it reflect the current equipment cost, the current interest rates? If it does not, why not? Basically, the idea, what I am trying to figure out here is how many of the project backlogs are not hedged, basically from interest or raw materials or equipment. Is impairment reflecting sort of a projection, a recent average, or where we are right now? So I am trying to gauge if there is going to be more impairments on the same projects or more impairments on other backlog projects. If we had expected more impairments, we would have to take it now. It is based on an updated view on how do we predict that the market would look like when we are to build the different projects, and then, of course, taking the updated view into the cases on inflation and interest rate environment. That is clear. Thank you. Thank you, Alberto. The next question will be from the line of Jenny Ping from Citi. Please state only one question. Your line will now be unmuted. Thank you. Unlucky that I am the one with one question to start. I will come back with others. Just firstly, continuing with the U.S. discussion, can I just check, Mads, you said earlier that although you can't give any details at this stage on the dialogues you're having with the different stakeholders and regulators, can you just sort of outline, without going into project specifics, what is the discussions you're having in more general terms? Is it upping the price? Is it delaying the projects? What is on the table as a way to potentially improve the NPV of these projects? Thanks. Yeah. I mean, again, thanks, Jenny, and good morning. It is a quite firm promise with the stakeholders we have a dialogue with that we can't be specific and not even sort of generally, because that can be something that could indicate something very specific and could be interpreted in that way. But it is something that can potentially materially impact the value creation of these projects, which, as we mentioned, obviously are not where we want them to be, but we have not taken that into consideration. When we did the impairment test, we had not just put in wishful thinking for the expected or intended outcome of those discussions. But it could be. I mean, there is nothing that we are not potentially discussing, but as you know, for example, we have IRA or tax benefit pass-back clauses in some states, and there are other ways in which we could also potentially improve it. But that is as close as I can get it. We are discussing everything with stakeholders that can potentially do this, and some of them more likely than others. And sorry for being super general, but that is being loyal to the promise we have with our stakeholders. Thanks. Thank you, Jenny. The next question will be from the line of Rob Greens from Morgan Stanley. Please state only one question. For additional questions, please re-enter the queue. Your line will now be unmuted. Thank you. Good morning. The question, if I am allowed one, is you talked about installation vessels being particularly tight and therefore higher cost in 2025. Given the shortage of Jones Act vessels, do you have a vessel or vessels lined up, or could we see a situation where we see further delays? That is the question. If I may ask a clarification, because I did not hear it earlier, the line was a bit fuzzy, is how does the impairment on Sunrise compare to the carrying book value? I think you may have answered this, but if you could just reconfirm that would be great. Thank you. Yes, to the first question, Rob, the answer is yes, we have the Dominion vessel that has been commissioned. That is slightly delayed, but nothing that we expect would impact the overall project, because it is ready from 2024 already. So it is available, and it is contracted already. On the book values, we will not give specific numbers on all of our book values, but I can just say that the forward-looking value in the Sunrise projects is still positive, and that is why we have not impaired all of the book values that we have on Sunrise. We have impaired a little more than half on that project. Thank you. I will turn it over. Thank you, Rob. The next question will be from the line of Kristian Johansen from SEB. Please state only one question. For additional questions, please re-enter the queue. Your line will now be unmuted. Yes, thank you. If I understand you correctly on Sunrise Wind, it sounds like you have now sort of locked in the contract on installation vessel and realized the cost is higher than budgeted. If that is the case, can you specify how much of your CAPEX for your U.S. portfolio, excluding Ocean Wind 2, because that is still out, so for the other part of the portfolio, how much of CAPEX have you locked in at this stage? Can you give a percentage? We are getting very close to the 90%, so we have very high certainty on CAPEX right now. Bear in mind, Kristian, that it is not just Ocean Wind 2 which is far out, it is also Skipjack project, which is also backloaded in the decade. This is just to clarify, the 90% is that for the entire portfolio? No, that is for the near-term development portfolio, so the NEP project and Ocean Wind 1. Understood. Thank you. Thank you, Kristian. The next question will be from the line of Vincent Ayral from J.P. Morgan. Please state only one question. Your line will now be unmuted. Yes. Good morning, and thank you for taking my question. Looking at the situation in U.S., which remains, let's say, difficult, I wanted to take a step back regarding partnership and the ability to use tax credits. We saw PSEG selling back its 25% stake, and that was less than 48 hours ago. Just wonder about the timing with regard to all of this, is it that they had to trigger the option now or not? Because Eversource have put its partnership potentially under review, and you're saying that you're having discussions on what can be done to improve the value creation of all these projects. So I suspect it could have something to do with the ability to use tax credit. Where I'm coming here is I'd like to understand what is your position. You have already one partner which decided out, and you have to look for other partners. We know CAPEX is up, returns are not great out there. It looks from outside like a difficult position to be in. It could be just a matter of time before your discussions are finished, and I'm trying to assess if in this situation, Eversource is better actually to wait, or does it have any option coming where it will have to decide? It would be interesting for us to know. Thank you. I can kick it off. Thank you, Vincent. I mean, you should not see the discussions between PSEG's message and our message about the 25% in Ocean Wind 1 related to what we are talking about here. That is a matter of PSEG having a desire for their tax credit profile different than what is now at the table. That also means that we will, from a total value creation point of view, there will be greater value in finding a different tax ITC, so investment tax credit partner, to maximize value for the project. That is the main reason, and the one-off effect that this would get would not be what was the primary interest of PSEG. That is the primary reason for that. We do not have any concerns, as Steen alludes to before, because, I mean, for example, on Ocean Wind 1, now being the 100% owner, that would allow potentially also a farm-down process of 50%, which would be closer to what we know. Therefore, we strongly believe also something that can help us create value. So, we do not have any strategic concerns around partnerships in the U.S., and all of these dialogues are in very good spirit and also very constructive with our existing JV partners. Yeah, but what I am trying to understand is, you will be looking for a new partner to have the ability to use the tax credits, which PSEG was supposed to bring to the table. When you are looking for someone, what they are seeing, returns coming down, issues with CAPEX and everything, what is the timeline for your discussion with local authorities on where you are fairly optimistic that some value-creating, some sort of solution will be found? Clearly, an idea on the timeline there in order to understand a bit the dynamic regarding these partnerships, and for example, what could happen with Eversource. Yeah, that is correct. We are in those dialogues right now with potential offtakers of tax credits. As you know, we have seen a massive increase in the tax credits available for these projects, and that does outpace the tax deficits and all the tax monetization available for PSEG and Eversource. So, it is more efficient if we find someone who can better utilize these ITC tax credits. We are in a dialogue, and of course, the IRA is expected to de-risk the monetization of these tax credits, as you now have the transferability where the offtaker will not have to take as much risk in the project as we are used to in the old onshore PTC days. So, we expect that it will be easier with the transferability to monetize the ITCs. With the dialogue with the stakeholders as well, those are relatively near term, but for good reasons, we cannot give any specific timelines. Also because, for example, the clarity of what it takes, for example, to qualify for the domestic content credit is also something that we expect to come out. We hope to come out in Q1 from the treasury in the U.S. But definitely first half, and before that, it would be impossible to be very specific about those upsides. Also, the dialogues are state by state, so therefore, there is not one timeline. But it is clearly something where we hope to be able to gain stronger visibility of any further upside during first half of this year. Thank you very much. Thank you, Vincent. The next question will be from the line of Mark Freshney from Credit Suisse. Please state only one question. Your line will now be unmuted. Thank you. Good morning, and thank you for making the time for me. It has been clear for a long time that costs in the U.S. are astronomical, right? Daniel, your predecessor, spoke about very high costs, I think, at a CMD about four years ago. The key thing is they have gone up, and it may appear that on PSEG, on the Ocean Wind, you have to do 100%. So when we look at your business plan and the CAPEX profile and the balance sheet envelope, it appears that there are some very big cash outflows before the EBITDA comes in from 2025 onwards. I guess my question is, Mads, you have been clear that the deal you negotiated with the Danish government to issue equity would only be to fund new additional growth. But given the CAPEX plan and the project plan that you've got, do you need equity to fund the existing plan? Thanks a lot, Mark. No, that is still not our expectation. But obviously, it is, you're right, also increasing the stake, and 100%, for example, in Ocean Wind 1 would mean that, for example, a farm-down discussion would be something that we potentially look to accelerate further in order to look at what are those. When we take on additional cost in building the projects, then whether that be from inflation or, in this case, from a greater ownership share, then that is where we would need to work with our balance sheet to ensure that we can generate those additional incomes from, for example, cash flows earlier in the construction or from farm-downs earlier in that process than we might otherwise do. That is not something we expect will have a negative impact, but something where we still have some flexibility because we have done both pre-FID and post-COD farm-downs. It is still our clear intention to state that a potential capital raise is for growth. Thank you. Thank you, Mark. The next question will be from the line of Harry Wyburd from Exane. Please state only one question. Your line will now be unmuted. Hi. Morning, everyone. I will keep to my allotted one question. I just wanted to follow up on Greater Changhua, which I think you mentioned earlier, if I caught it right. I think in your slide, you were saying about EUR 1.5 billion year-on-year impact. I just wanted to check what is the kind of weighted average COD date that that assumes? In other words, what would the impact or the year-on-year impact have been if you had started the project on January 1st? So what is the annualized EBITDA, and what would we consider as a year-on-year growth from that project going into 2024? Thank you. Yes. Thank you very much. It is a little bit hard to compare directly because if we were fully ready with a COD from January 1st of this year, then our ramp-up profile would also have been different during this year. So we would also have had greater earnings this year. But if you look at the actual result from this year, I would say that if we look at a year with full operations, then that would be sort of to the tune of, say, DKK 3.5 billion. Therefore, with what we are looking at now, it would be something where we are. I cannot give you a specific date, but it is going to be second half before we are fully done. But what really matters for the earnings into next year is the curve of the ramp-up, because right now, we have 15 producing turbines. That needs to go up to the 111, and that is where the more we can front-load that out of the now currently 80 installed turbines, the better we can do that. So in essence, the ramp-up profile from an earnings point of view is actually even more important than what is the final full commissioning date. But full-year earnings would be around DKK 3.5 billion, so you could put it in a way that we are looking at sort of a weighted average of around 50% of a full-year normal earning due to, with that ramp-up profile we have, if that answers your question. It does. Thank you. Thank you, Harry. The next question will be from the line of Dominic Nash from Barclays. Please go ahead. Your line will now be unmuted. Good morning. Again, just one question from me, clearly. In your EBITDA guidance for 2023, could you give us some sort of color as to whether there is any impact from the EGL tax levy, whether that will come through EBITDA or tax number, and also what you think your sort of view for the EGL level will be next year, please? Yes, thank you. We do not have anything significant in there from the EGL so far, as we have a very high hedge level in the U.K. There might be some in there going beyond 2023, but that will, of course, depend on where the power prices will be sitting at. But the very high hedge level means that we do not expect to pay anything under the EGL. Great. Thank you. Thank you, Dominic. The next question will be from the line of Tancrede Fulop from Morningstar. Please go ahead. Your line will be unmuted. Hi. Good morning. Thank you for taking my question. For the U.S. project, you have not taken an FID for any of them. Is it sensible to assume that you will not go through with some of the projects if you are not able to get the maximum benefits of the IRA? Thank you. No, you cannot assume, because it would depend on what is the current status of the project, what is the current sort of profitability of it. Obviously, if we can get the full benefit of the IRA, and also potentially a greater share of that in the states where we have a pass-back clause, then this is something where we would actually still be able to take an FID. So, we cannot make that connection, but of course, if we get that additional support with a full 40% ITC, which quite honestly we believe we are in an extremely good position to have, then that would obviously be a help. Just to, not to correct, but just to clarify, we actually have taken FID on South Fork, so the first of the three projects in the Northeast program. We have FID the first one, but the other ones are remaining, and hopefully the next one's not too far out into the future. Okay. Thanks. Thank you, Jean-Christophe. The next question will be a follow-up from the line of Jenny Ping from Citi. Please go ahead. Your line will be unmuted. Hi. Thanks very much again. Just coming back to the Taiwan project, you mentioned in the statement about the construction delay causing an issue for the 2022 numbers. Is that just a pure delay from 2022 into 2023, or is there an overall negative impact because of the construction delays, I.E., a financial penalty on the rollout? Thank you. Yeah. Going into 2022, we had hoped that we would have seen some production at the back end of the year, but we almost got no earnings from production in 2022. That is, of course, on the sites part. On the existing partnership part, as we said, we saw a negative impact as we have seen costs go up a little bit due to the delay, and that, of course, means that we realized a lower margin on our construction agreements with the partner on the project, even though we are, of course, still making money on that CA. Yeah. You could say that except that factor of the increasing cost and lower earnings on the CA, then it is a pure moving of that earnings into 2023. So, it is a delay that will mean that the ramp-up profile will now happen in 2023, and where the production. So, with an approximate, you could say, approximate six-month delay in total, which is now moved into 2023, and with an expected full-year production in 2024 instead of 2023. Sorry, that is included in the 1.5 guidance you have given? Yes, that is included. Now, we have taken a, I would not call it conservative, but what we definitely believe we can do in terms of the guidance that we have for 2023. Thank you, Jenny. The last question will be a follow-up from Rob Pulleyn from Morgan Stanley. Please go ahead. Your line will be unmuted. Yeah. Thank you, guys. Look, lots and lots of comments and lots of detail. Thank you for taking everyone's questions. I think the most important comment you made in the entire presentation and answers was that the U.S. projects were NPV positive. Could we just reaffirm that for the go-forward, and could we clarify, is that on the entire U.S. portfolio? Is it on the first phase portfolio of five projects, or can we take that to read that every one of the individual projects is NPV positive? Thank you. Yeah, you can say, I can kick it off, Rob. I mean, this is where also, when going through the impairment test with the assumptions that we have now, then this is clearly our belief and both our intent and belief that that is what can happen. There are, of course, I mean, if we continue to see interest rate, especially interest rate hikes, and depending on the outcome of the dialogues that we have, yes, we believe we can make NPV positive projects. But of course, the clarity of that is something that is significantly higher on the nearer term ones than it is for those that are backend loaded, especially, or i.e., for Ocean Wind 2 and for Skipjack, where that is so far out into the future that, of course, developments, both positive, but could, of course, also be adverse, can still impact that. But yes, that is our belief that the portfolio can be NPV positive. Yeah. Thank you. I will leave it there. Good. I believe, operator, that was the final question, or? That is correct. There are no more questions, so I will hand back to you. Yes. Thank you very much for your question, and sorry for getting you up early. Let me just spend 30 seconds wrapping up that thing. Whilst, as I am sure you can imagine, the composition of this year's result has ended differently, I just want to repeat that it is actually something that shows the strong portfolio and diversification of our asset base. Really, a key takeaway is, do not be concerned about the long-term earnings profile and cash flows, especially of our offshore business, which is where we have had these, hopefully, one-off impacts. Both our future cash flows, our underlying operations, but also for the future, the strength of our pipeline, which has been expanded significantly in the recent months, and our deep capabilities to navigate even very difficult circumstances operationally, is something that we believe continues to put us in a strong position. We strongly believe that both with the passing of the IRA and the policy actions that Europe is now taking, I met with Commission President von der Leyen and many of the staff from EU, there is no doubt that the European response to the Inflation Reduction Act is going to have something that can have a material positive impact for the entire industry, and not least for offshore and hydrogen production. Whilst this is not a 2022 finish that we had hoped for, we are and remain very confident for the future. Thank you very much again for your questions, and have a nice day.