Welcome to this Ørsted Q4 2022 earnings call. For the first part of this call, all participants will be in a listen only mode, and afterwards there'll be a question-and-answer session. Today's speakers are Group President and CEO, Mads Nipper, and CFO, Daniel Lerup. Speakers, please begin.
Thank you very much. Welcome to this call. As you may have seen from our pre-released earnings two weeks ago, we achieved a record high operating profit in 2022, despite the unusual and very volatile market conditions. Our financial performance is supported by a fleet of assets continuously operating at excellent availability rates and contributing to the security of energy supply across all markets in which we operate. This shows the benefit of our strong operational portfolio and the diversification of our asset base. Based on the financial results, the Board of Directors will recommend to the Annual General Meeting that a dividend of 13.5 Danish kroner per share is paid for 2022. This equates to an 8% increase in line with our dividend policy.
On that note, let me dive into the strategic progress we achieved during 2022, starting with our offshore business. In August, we commissioned the world's largest offshore wind farm, the 1.3 GW Hornsea Two project in the U.K. This is a very significant milestone, and I'm very proud of the entire team who under very challenging conditions with COVID-19 delivered this project. Furthermore, we progressed the construction of the Greater Changhua One and TwoA project, which is our first large-scale offshore wind farm in the Asia-Pacific region. We achieved 1st power in the 1st quarter of 2022 and expect to fully commission the project in 2nd half of 2023. In the U.S., we took Final Investment Decision on our South Fork project, and we are well on track to meet commissioning in 2023.
In addition to progressing with our construction portfolio, we made significant progress within our development and opportunity pipeline. We were awarded a Contract for Difference for the 2.9 GW Hornsea Three in the UK, which will be the world's single largest offshore wind project. In addition, we formed a partnership with Copenhagen Infrastructure Partners to develop up to 5.2 GW of offshore wind in Denmark across four open-door projects. We applied for permits to build four additional large-scale offshore wind farms in Sweden, bringing our Swedish portfolio to a potential total capacity of 18 GW. We also took tangible steps into floating offshore wind with our 100 MW floating project, Salamander, in Scotland, and our partnership with Repsol to explore the joint development of floating offshore in Iberia.
Additionally, we are part of the joint venture behind the Scottish project Stromar, which in 2022 was awarded a site for approximately 1 GW of floating offshore wind on the northeast coast of Scotland. As a testament to the value of our current project portfolio, our farm-down strategy once again proved its attractiveness with the completion of the farm down of Hornsea 2 and Borkum Riffgrund 3. On top of our firm pipeline, which is defined as our installed, decided, and awarded capacity, comes a number of pipeline opportunities within bottom-fixed and floating offshore wind, as well as Power-to-X.
In our Onshore business, we continued our strong growth trajectory as we commissioned 0.8 GWs and advanced seven projects with a combined capacity of 1.4 GWs to Final Investment Decision, including the 600 megawatt solar and storage project Eleven Mile and the 471 megawatt solar project Mockingbird, both in the U.S. In addition, we expanded our growth platform in Europe with the acquisition of the French-German developer Ostwind and four partnerships in Spain to pursue early-stage solar PV and Onshore wind projects, which gives us a strong presence across key renewable growth markets in Europe. In combination, these efforts increased our firm capacity in Onshore with more than 30% during the year. Furthermore, we closed our first ever Onshore farm- down by agreeing to divest 50% of a portfolio of four Onshore projects in the U.S.
Similar to our strong farm-down track record in offshore, the transaction secured an attractive Net Present Value retention and provided proceeds which we can reinvest into value-creating growth. Within our Power-to-X business, we achieved several key milestones throughout the past year. We acquired the remaining 55% of the Flagship One project and took the Final Investment Decision. The facility will have an electrolyzer capacity of 70 MW and will be the largest e-methanol facility in Europe. Furthermore, we signed a landmark green fuels agreement with A.P. Moller - Maersk to partner for a project delivering 300,000 tons of e-methanol per year in the U.S. It is also worth highlighting that both our Green Fuels for Denmark project and our Haddock project in the Netherlands received IPCEI funding in 2022. IPCEI standing for International Project of Common European Interest.
The strategic progress meant that our firm capacity increased with 4.5 GW during 2022 to 30.7 GW. In addition, our substantiated pipeline across offshore and Onshore projects and opportunity pipeline in offshore increased with more than 25% to roughly 85 GW. There is no doubt that green energy is the most impactful solution we have for fighting global warming, and we need to speed up the build-out of renewable energy. It is also becoming evident that to succeed with the green transformation, we must create positive impact on nature and people to ensure we solve key environmental and societal challenges and maintain public support for the green build-out.
Ørsted has set industry-leading sustainability commitments. As part of reaching our science-based target of having Net-Zero emissions in Scope 1 through 3, we became a founding member of First Movers Coalition's Near Zero Concrete Commitment and entered into a partnership with World Wide Fund for Nature to improve ocean biodiversity. The world is facing a climate crisis. It is indisputable that a transition to a sustainable energy system is needed. We continue to be part of this much-needed renewable energy build-out. With the significant strategic results across our business, we remain confident in our long-term financial targets and growth ambitions. Let's turn to Slide 4. Throughout 2022, the renewables industry has been challenged by continued supply chain bottlenecks, cost inflation, and slow permitting of new projects.
Despite all these challenges, renewable energy continues to be significantly cheaper than any fossil fuel alternative, even with challenged supply chains, and it is furthermore likely to be the best possible insurance policy to avoid future energy price increases like those seen last year. Action must be taken to increase the pace of the necessary investments in renewable energy, and we need to push regulatory and political barriers to focus on fast and streamlined permitting processes, which today continue to represent a major bottleneck within our industry. In light of this challenging backdrop, we are pleased to see that the political attention and support towards the renewable build-out has been significantly positive development during the past year. In Europe, we have seen different political initiatives, such as the adoption of several Fit for 55 files, a REPowerEU, the Esbjerg Declaration, and the Marienborg Declaration.
More recently, the European Commission announced the planning of a Green Deal Industrial Plan, which will be aligned with the 2050 climate targets and provide significant opportunities for the renewable energy sector. Included in the Green Deal Industrial Plan is the Net-Zero Industry Act, which is focusing on regulation to scale development of green energy supply chains and raw materials. Additionally, the plan is focusing on changes to state aid rules to counter relocation of industries' investments in skills and workers, and lastly, international trade with focus on protection against China. Such initiatives would be incremental positive for the renewable industry within Europe, which would benefit from the increased EU support and as well as easier access to national funding made available through relaxation of EU state aid rules, which should of course be done in a way that preserves fair competition.
In the U.S., an important step has been initiated by passing the U.S. Inflation Reduction Act, providing $385 billion in funding for renewable energy generation, green hydrogen production, and climate risks over the next 10 years. The Inflation Reduction Act is one of the most important climate initiatives since the Paris Agreement and will make a tremendous difference for the green transition in the U.S. with historic investments into clean energy, especially in light of the current environment where offshore projects are challenged. In Asia Pacific, we also see good progress with firm offshore wind capacity built out targets in Taiwan and a Green New Deal in Japan. Australia has announced regulatory changes to progress offshore wind power with political momentum for renewable energy solutions.
We fully recognize Australia's strong offshore wind potential. Backed by supportive policies and momentum for green energy, Australia has all the ingredients for a thriving offshore wind market. Looking across our portfolio, we are well-positioned to tap into the political support due to our significant presence within Onshore, offshore wind, solar PV, hydrogen, and storage. Through our 30-plus years in the industry, we have established a strong global presence with trustworthy stakeholder relations across the supply chain, local communities, unions, governments, and policymakers. We have strong competence within development, construction, operations, and maintenance. I have more than 8,000 dedicated colleagues who go to work every day to bring us one step closer to a world that runs entirely on green energy. Moving to Slide 5 and the outlook for offshore wind auctions in 2023.
Throughout 2023, we expect to see numerous auctions and tenders across all three regions where we are present. More than 25 GW is set to be auctioned during 2023, which underlines the strong growth outlook for offshore wind. On top of this build-out, we continue to see a significant increase of open-door opportunities across European countries, which greatly increases the addressable market for the build-out of offshore wind. We expect to see continued growth in the long term with an expected global offshore wind build-out of more than 20 GW yearly towards 2030 and more than 30 GW yearly between 2030 and 2035. With an annual growth rate in installed capacity of 20% over the next decade, we see ample opportunities to fulfill our ambition of adding around 3 GW of offshore capacity to our portfolio yearly.
Exactly like we did in 2021, with additional 4.5 GW capacity and 2.9 GW in 2022. I will reiterate a word of caution being that in light of the supply chain bottlenecks, cost inflation, and increasing cost of capital, it is essential that we see the contracted prices in auctions and tenders reflect the realities of the current inflationary environment. Otherwise, the necessary investments in renewable energy are at risk of slowing down and cause a devastating loss of momentum for the green transformation.
On that note, we are encouraged to see that Massachusetts removed its price cap and that improved framework conditions for the ORECs have been launched in New York, Rhode Island, and New Jersey as inflation index mechanisms are being implemented to counter some of the adverse impacts from the unprecedented increase in interest rates and cost inflation. In a response to New York State's 3rd round of offshore wind solicitations, we have submitted a proposal which include multiple bids with different configurations. We applaud the high number of auctions and tenders, both near term and long term. As a direct consequence of the unprecedented cost inflation and rapidly increasing interest rates that the industry faced in 2022, we had to incur an impairment of our U.S. development project, Sunrise Wind.
As the project is the last project in our execution pipeline towards 2025, the project faced specific challenges compared to the rest of the portfolio. The project experienced acute cost increases, specifically driven by the prices for installation vessels and the associated services. On a portfolio level, we have locked in around 90% of the cost of the projects towards 2025. Moreover, all pre-2025 COD projects have a positive forward-looking Net Present Value on an individual basis, and we currently assess that this portfolio has a positive life cycle Net Present Value, assuming 40% ITC. As we have previously noted, we continue to explore all options to improve the business cases, including ways to have more robust top lines. Notwithstanding the Sunrise Wind impairment, I want to emphasize our continued commitment to Sunrise Wind and the rest of our U.S. offshore wind portfolio.
We are developing the largest portfolio of U.S. of projects offshore in the U.S. with seabed leases secured many years ago at very low costs, which we will leverage for future offshore wind solicitations in the U.S., like the very recent New York 3 auction. With our unique global presence, we will assess the opportunities across technologies in existing and new markets to make sure we efficiently prioritize our capital allocation. We will continue our strong focus on value creation and financial discipline when bidding into auctions and tenders. With this, let me hand over the financials to you, Daniel.
Thank you, Mads, and good afternoon, everyone. Let me start with Slide six and an overview of our full-year EBITDA for 2022. As we did release our operating earnings two weeks ago and today confirmed these numbers, I will not go into many details on the EBITDA. For the group, we realized a total EBITDA of 32.1 billion DKK, including new partnerships. This is a record high EBITDA, and the achievement should be considered in light of macroeconomic headwinds, high volatility within the energy markets, as well as adverse impacts from our hedging program. Excluding new partnerships, our EBITDA amounted to 21.1 billion DKK, which exceeds our initial expectations for the year. In fact, this number includes a negative effect of 1.3 billion DKK from IFRS 9-related ineffective hedges, which will improve EBITDA in future periods.
When excluding these temporary IFRS 9 adjustment, we achieved a group EBITDA excluding new partnerships of DKK 22.4 billion, which is an increase of more than 40% compared to last year. As highlighted during the conference call a few weeks ago, our earnings composition for 2022 was considerably different from our initial expectations. This was primarily driven by the high volatility and increase in power prices, as well as adverse hedging impacts. However, the developments within 2022 have demonstrated the earnings robustness of our diversified asset portfolio. The financial outperformance of initial expectations is driven by a strong performance within Onshore as well as our Bioenergy & Other segment.
Our Onshore division have operated at high availability rates throughout the year, increased generation capacity, and managed to secure favorable prices during the ramp-up phase of assets under construction in the U.S., as well as benefiting from upside-sharing mechanism within some of our PPAs. Within our Bioenergy & Other segment, we have secured attractive earnings within our gas activities and benefited from the high power price levels. Finally, we remain confident in our long-term EBITDA growth towards 2027, where the combination of our operating assets and projects to be installed will secure a high degree of earnings visibility. Let's continue to Slide 7. For Q4 2022, net profit totaled a negative DKK 0.3 billion.
Contrary to Q4 2021, we did not complete any farm downs, and in addition to this, the impairment related to Sunrise Wind reduced the net profit for the quarter. Adjusting for these effects, net profit for the period was significantly higher than last year, driven by a higher EBITDA. Our Return on Capital Employed came in at 16.8%, which was an increase of 2 percentage points compared to last year, driven by a higher EBIT over the 12-month period and significantly ahead of our long-term target. Throughout the fourth quarter of 2022, we saw a significant increase in our equity, which ended the year at 95.5 billion DKK. The increase is driven by hedges going into delivery and the lower power prices. The hedge reserve decreased with more than 50% during the quarter.
The remaining negative hedge reserve will be matched by higher future revenue from the underlying assets when the contracts fall into delivery. Around 30% of this hedge reserve will materialize before end of 2023 and thereby gradually increase our equity. Let's turn to Slide 8. At the end of 2022, our net debt amounted to DKK 30.6 billion, a decrease of DKK 15.1 billion since end of the third quarter. Our cash flow from operating activities was significantly impacted by a net cash inflow from collateral postings amounting to DKK 17.4 billion, which is driven by the reduction in forward power prices. By the end of December, we had posted a total of DKK 14 billion in collateral payments, where the majority will unwind over the next 2 to 3 years.
During the quarter, our gross investments totaled DKK 9.8 billion, primarily driven by our investments into construction of offshore and Onshore projects. We received a payment from a partner related to project development, and lastly, saw a positive effect from issuance of hybrid capital and an exchange rate adjustment due to decreased pound sterling. Our key credit metric, FFO to adjusted net debt, stood at 43% for the full year of 2022. The level was above last year, primarily driven by higher EBITDA. Let's turn to the next Slide. For the full year 2022, our taxonomy-aligned and eligible share of revenue was 73%. Our share of OpEx was 80% and EBITDA was 85%. The share of gross investments was 99%.
The non-eligible part of our revenue primarily relates to our long-term gas legacy activities and non-eligible power sales. Green share of energy came in at 91%, compared to 90% last year. The development was primarily due to more wind and solar farms in operation, as well as higher wind speeds. As we've been ordered by the Danish authorities to prolong the operation of the Esbjerg Power Station beyond Q1 2023 and resume operation of the coal-fueled unit at Studstrup and the oil-fueled Kyndby peak load plant, this will expectedly have a negative impact on our green share of energy and our taxonomy-aligned KPIs in 2023 and 2024. The order requires that we operate the units until June 2024, and we therefore maintain our commitment to become carbon neutral by 2025.
Turning to safety, we regrettably do not see a performance which is up, which is up to our expected standards, as our Total Recordable Injury Rate is at 3.1 for 2022. We have seen more recordable injuries with our contractors, partly offset by a minor reduction in recordable injuries for our own employees. We continuously work to improve and promote a safety culture. Especially in light of the latest trend, we've implemented several initiatives such as increased leadership involvement, safety stand-downs, and targeted safety campaigns on specific issues. Let's turn to Slide 10. Throughout 2022, we've seen material unintended and adverse impacts to our financials due to our previous hedging framework. These impacts have related to over-hedging, temporary IFRS 9 adjustments, as well as inflation-indexed power purchase agreements.
We have learned the hard way that our previous risk management framework was designed for very different market conditions and had ended up being too complex. Our updated hedging framework will significantly reduce the risk of adverse hedging impacts in the volatile market conditions we are seeing, and instead support the high predictability of earnings that our portfolio of renewable energy assets is capable of delivering. Historically, our hedging framework has served us well, as it has provided us stability and visibility of earnings.
However, it was designed for risk management and earnings optimization under fundamentally different market conditions than what have prevailed recently, illustrated by the extreme increase and volatility of power prices over the past few years. To adapt to the unprecedented market conditions with high volatility and significant increase in power prices, while also better reflecting our current business composition, we decided to cease all new hedging activities end of 2021 and conducted an extensive revision of our hedging framework. The design criteria were based on some of the key learnings that we have made over the past year. First, it has been crucial to reduce our hedge level, so we significantly reduced the risk of having to buy back hedged volumes. Second, we have seen a significant increase in the amount of the collateral that we have had to post related to our hedge portfolio.
We have experienced a significant drag on our liquidity. Throughout the year, we took several proactive steps to ensure a sufficient level of liquidity to meet the collateral requirements while also supporting our ongoing build-out and operations. It has been a key condition for our new framework that we significantly reduce the risk of having to post collateral to a similar extent in the future. Finally, our previous framework was highly systematic and methodical in the sense that we would strictly follow our hedging staircase by meeting fixed hedge levels at given time horizons. However, we've come to learn that we must introduce more flexibility into the framework, such that we can maximize value and support commercial initiatives, for instance, by locking in power prices above the levels that are assumed in the business case.
If we turn to the next Slide, where I will cover the updated framework based on these design criteria. Even with the significantly increase in power prices, we continue to have a very high share of EBITDA coming from long-term regulated and contracted activities. Going forward, we will hedge no more than 70% of the remaining limited merchant exposure from our offshore and Onshore assets within the current and the following calendar year. With this approach, we will significantly reduce the risk of unintended adverse hedging impacts in the future, including lowered risk of over-hedging, lower collateral postings, as well as a reduced impact from temporary IFRS 9 effects.
Based on historical wind and production data, we can conclude that our former very high hedge requirements resulted in over-hedged volumes in 1 of 3 months, while a hedge level at 70% would lead to over-hedged volumes in 1 out of 20 months. This is a much more comfortable probability, especially given current market volatility, elevated power prices, and increased renewable penetration. Our renewable portfolio contains a natural risk-reducing mechanism, given the negative relation between production and price. In a high wind scenario, the merchant price will be relatively lower, yet this will be offset by higher generation from the subsidized assets. On the contrary, in a low wind scenario, the merchant prices will be relatively higher, and the high price level on the merchant generation will counterbalance the lower generation from the subsidized assets. This provides a natural offsetting portfolio effect from our renewable assets.
The negative relationship between production and price is expected to grow even stronger in the future as renewables will make up an increasingly larger share of the energy supply. In designing our new framework, we have considered this offsetting effect between power generation and price volatility. As such, the extent to which we will hedge our merchant generation depends on the portfolio composition of subsidized and merchant exposure, as well as the prevailing market prices. The graph on the right-hand side illustrates two portfolio compositions which hold different shares of merchant exposure. The portfolio with a 100% share of merchant exposure indicates that increasing the hedge level for the portfolio will increase the revenue uncertainty due to removal of the natural portfolio effects, as well as increasing the risk of over-hedging.
On the contrary, for a portfolio that holds a merchant exposure share of around 40%, increasing the hedge level will reduce the revenue uncertainty, but only to a certain extent. Hedging the merchant generation at a too high level will remove the natural portfolio effects and introduce risk of over-hedging. This implies that for a portfolio with a low share of merchant exposure, holding a high hedge level increases the risk of over-hedging, which is the adverse impact that we have seen in our portfolio over the past years. The decision to lower the hedge level and duration will result in a lower risk within our portfolio going forward, as the combination of a high share of regulated and contracted earnings and the portfolio effect I just described will support revenue certainty going forward.
With our new framework, we will decide on our year-to-year hedge level based on the overall portfolio composition and thereby avoid situations where hedging is risk-increasing rather than risk-reducing. We are moving away from our systematic and methodical hedge approach to a more flexible and dynamic framework that provides the needed flexibility to ensure we strike an optimal balance between regulated and merchant earnings. It's important to highlight that we are still implementing this framework as our previous hedging framework have locked in a relatively high hedge level within offshore for 2023 as well. However, we have taken proactive steps in reducing the extent to which we may be negatively impacted by our hedge level.
As an example, we have opportunistically bought back forward sold volumes at favorable prices to reduce the risk of over-hedging and as a result of this, we are heading into 2023 with an offshore hedge level of around 85%, which is meaningfully lower compared to the close to fully hedged level in 2022. On a group level, we hold a hedge level of around 70% for 2023. Finally, let's turn to Slide 12 and our outlook for 2023. As highlighted during our conference call a few weeks ago, we guide our full year 2023 EBITDA in the range of DKK 20 billion-DKK 23 billion. I will not go through the underlying assumptions behind our guidance now as we covered it back then.
However, I will note 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, which is a key growth and value-creating part of our business. For our gross investments, we expect to be in the range of DKK 50 billion-DKK 54 billion. This is driven by timing effects of investments that have been postponed from 2022 into 2023, as well as an overall increase in the investment level given the build-out of our pipeline within offshore and Onshore. At our latest Capital Markets Day, we presented four key financial estimates that supports our growth plan of approximately 50 GW installed renewable capacity by 2030.
As a consequence of the supply chain disruptions in the wake of the COVID-19 pandemic, cost inflation, and the prolonged permitting processes, especially in the US, our gross investments for, from 2020 to 2027 that will enable our 50 GW build-out are currently trending higher than the approximately DKK 350 billion we had planned for. However, if the inflation and energy price levels remain at elevated levels, these factors will positively impact our EBITDA CAGR and ROCE over the period and lead to an increase in the relative share of EBITDA that is merchant. Notwithstanding the higher trend in CapEx, we remain committed to our current CMD plan.
On that note, I'm also really excited to announce that we will host a Capital Markets Day on June eighth, where we will present a progress update on our long-term strategy. Please save that date. With that, we'll now open for questions. Operator, please.
Thank you. This concludes the presentation, and we will now open up for questions. This call will have to end no later than 3:30 P.M. Please respect only one question per participant, and then you can reenter the queue for a second question. To ask a question, please press 5 star on your telephone keypad. To withdraw your question, please press 5 star again. We'll have a brief pause while the questions are being registered. The first question will be from the line of Kristian Johansen from SEB. Please go ahead. Your line will now be unmuted.
Yes, thank you. My question is regarding your 50 GW target. Looking at these pipeline figures you give, combining your firm capacity and substantiated pipeline, it's now at 59 GWs. Going back to your CMD in 2021, it was 48. Obviously, as you also illustrate, this number is going up fairly significantly. To me, it sort of signals that the probability that you can beat your 50 GW target is also going up. Can you just share some thoughts on how likely that will be and then also what will it take for you to actually go out and change this target?
Yes. Thank you very much, Kristian. I'd be happy to comment on that. You're right that the substantiated pipeline and firm capacity has gone up substantially, which we're really happy to see. That, you cannot take as sort of as an automatic indication that this will of course go up, because right now, due to the industry conditions we're describing, it's very important for us to ensure that we focus on the most value-creating investment opportunities, which is why it's a great privilege to have a quite wide substantiated pipeline to pick from. Bear in mind that as we progress our work, the opportunity pipeline will continue to feed down into the substantiated pipeline as well.
I'll say absolutely, yes, this makes it even more likely to get to the approximately 50 GWs that we have set, but also that it is also necessary to have a wide pipeline of substantiated projects or project opportunities that make value creation even more likely.
Understood. Thank you.
The next question will be from the line of Deepa Venkateswaran from Bernstein. Please go ahead. Your line will now be unmuted.
Thank you. That's Deepa Venkateswaran from Bernstein. My question is on the U.S. impairments. I think a lot of the investors are struggling to handicap maybe further downside or how much further issues there might be. I was wondering if you can give some disclosures, even if it's at the total project level for all your near-term U.S. projects, what's the total capex and how much have you spent? And, you know, what % inflation there's been, so we can also do the math on what might be the risk should there be further inflation. Thank you.
Yeah. Thank you. Thank you, Deepa. We won't be going out with an updated number on our full U.S. portfolio. I think the headline numbers you have are the DKK 350 million for our build-out towards 2027. But maybe a little bit more clarity on what we have spent so far in the U.S., I can give. We say that roughly a spend of roughly DKK 13 billion, mainly on the near-term development pipeline being the NEP project and Ocean Wind One. It's...
it corresponds to roughly a low double-digit percentage of the totality of the near-term development pipeline in the U.S.
Okay. Thank you.
Thank you, Deepa. The next question will be from the line of Alberto Gandolfi from Goldman Sachs. Please go ahead. Your line will now be unmuted.
Yeah, good afternoon. Thank you for taking my question. I wanted to ask about debt leverage and a little bit more. If I look at Bloomberg consensus for 2023, net debt expectations are DKK 66 billion, and you have just reported DKK 30. If you look at some operating cash flow, if you look at your gross CapEx and your typical approach of rotating assets, I know you normally don't provide any guidance, but can you help us understand this figure? I mean, are we grossly overestimating net debt for 2023? How much of the DKK 11 billion working capital influence Q4 is going to reverse?
If consensus is incorrect, I mean, isn't the FFO to net debt much better than we were thinking because of the margin calls, the absorption, this working capital inflows, so how much of that reverses again to be seen? Does it also mean we're a little bit too worried about the timing of an equity raise? You know, you kept saying the equity raise would be potentially for funding a deal or perhaps if your win rate is much better, you know, if your substantiated pipeline gets converted faster. Should we think it in those terms, you know, based on the current plan of what you have won so far, you don't really need equity? If you can comment to this relationship, debt equity would be fantastic. Thank you so much.
Yes. I'll try to do that, Alberto. When we look at our capital structure projections, both our internal numbers and also for the rating agencies, we of course believe that we will be able to live up to the thresholds that are set out in those capital structure metrics. That is basically what we have solved for in order to deliver on the roughly 50 GW in 2030. That's our starting point. You will of course see that there's fluctuations in net debt and the FFO to net debt year-over-year. But we of course believe that we can live up to those thresholds.
When it comes to collateral, we have DKK 14 billion tied up roughly right now in collateral. We do expect that a fair share of that will be coming back in 2023. I don't know whether that can kind of close some of the gap. I'm not completely into the details of the average Bloomberg number, but that could potentially explain some of it. When it comes to the ABB, as we've said before, it is not our plan to use it to close a gap in our capital structure.
It's a financial flexibility we have that we will use in a situation where we see that the combined probability of all of the options that we have to grow above 50 GW becomes large enough for us to say, "Okay, now it makes sense to issue more equity in order to fund further growth beyond the 50 GW.
Thank you.
Thank you, Alberto. The next question will be from the line of Rob Pulleyn from Morgan Stanley. Please go ahead. Your line will now be unmuted.
Hi, good afternoon. Thank you very much for taking my question. There is only one, and hopefully you can share some color. Yeah, there's been a lot of discussion around these U.S. projects, which I think, we should all remember were signed by the previous management team. And I was wondering whether you'd be willing to share your thoughts on what the key lessons learned over the last two years were, and how that experience may shape the future and are, shall we say, risking, value creation and the outlook for Ørsted. Thank you very much.
Yes, I'll be happy. Thank you very much, Rob. Be happy to give that a shot and invite Daniel to supplement as well. No doubt one of the key learnings is that, we're happy to see that being also apparently implemented across several states, inflation indexing on the revenue line is something that's really important. We have worked quite intensely with the regulators to ensure that that is something that happens because in a situation where the cost of capital and also the CapEx inflation is going up, then having this fixed re-revenue line with a fixed annual escalator is just obviously challenging.
Working with the regulators to ensure that we de-risk that from a developer point of view, and therefore that the risk sits with those who can best handle it rather than forcing developers to build in risk premium is one key learning. The other key learning is of course, and that is not too different from our long-term strategy, is to ensure that the more CapEx certainty we can get soon, the better. Because I mean, the variability we have seen also in scopes that were previously sort of not that unpredictable is something we have learned can change as the bottlenecks in the industry change. Having the foresight as to...
Also structural and systematic foresight into where are the most likely bottlenecks, where can they happen, and ensure that we tie up really both the capacity but also having the fixed price agreements as we are doing, as we speak, so we are not just sitting on those learnings. We are implementing them by ensuring that we do frame agreements that are not just capacity assuring, ensuring, but also some that are locking in significant parts of that volatility that we otherwise face. Those are two examples of learnings that we are both taking and are already in the midst of implementing.
Thank you very much. I'll turn it over.
Thank you, Rob. The next question will be from the line of Casper Blom from Danske Bank. Please go ahead. Your line will all be unmuted.
Thank you very much. A question relating to the U.S. projects also. Mads, you mentioned that one of the cost items where you've had seen a lot of inflations were within vessels to do the installation, especially within the Sunrise Wind projects. I assume this, that it's not a market with hundreds of vessels and that, you know, relatively few vessels could quickly change things. What are you seeing sort of here in terms of, you know, the pipeline on vessels going forward? Do you see any upside from potentially other projects being delayed, postponed, maybe not even built, that could actually make things easier even sort of in the near term for you? Thank you.
I, yes. Thank you. Thank you very much, Casper. We have very little doubt that there will be a structural, overall positive sort of capacity expansion. In a tight market, obviously the vessel owners are seeing significant opportunities. That is not just in the US, that is globally. We are seeing FIDs on heavy lift vessels that are happening as we speak. That's a good thing, and that is something that will clearly add to the capacity.
We continue to push that because as you can see from one of the Slides we showed today, the capacity expansion of what needs to be built out, we need to ensure that we also encourage both in the market predictions but also in the commitments we give, that we can secure more, even more capacity. Since it takes time to build these, the honest answer is, Casper, that the nearest term projects, so for example, the portfolio of U.S. projects we have towards 2025, those are unlikely to be impacted positively or negatively for that matter, of any capacity expansions that are happening. On the sort of towards 2030, there's no doubt that we are seeing this as an area that we are hoping and believing could be debottlenecked.
Okey-dokey. Thank you.
Thank you, Casper. The next question will be from the line of Harry Wyburd from Exane. Please go ahead. Your line will now be unmuted.
Hi, everyone. Thank you very much for taking my question. I'm really sorry to labor the point on the write-downs. Can I ask a slightly technical question? If we think about projects that are COD-ing after Sunrise, you know, I guess they don't have very big book value right now. What's the risk that as you progress through time and spend money on them, that you know, you then have to get to a point where they do have book value, and then you have to look at whether you need to write them down?
In other words, you know, what's the risk that the CapEx you spend over the next couple of years, CapEx and DevEx, you know, sort of value destructive and then, you know, we get to 2 years' time, you've then gotta write that down, but you don't have to do it right now 'cause the book value is basically zero on this project. Maybe if I could sneak in the vessel costs. Obviously, you've seen, you know, much higher vessel costs on Sunrise. Did you make the same assumptions for, you know, the other projects as well, or are you sort of implicitly assuming the vessel costs come down, like you said, to 2030?
Thank you.
I can take the last first and then hand over the first question to Daniel, Harry. I think as we also wrote in our text around the impairment of Sunrise Wind, the reason why that is the project we impair, whereas the others have a comfortable headroom under the current assumptions, is that we had locked in more of those scopes, including the vessels. Therefore, it's not because it's not because we have done something terribly wrong or have any sort of significant outstandings on the remaining projects. It's just because Sunrise was the last to lock in a market where prices on rates were going up significantly. That explains that. We are...
We do have, as we mentioned, sort of a 90% capex price lock-in for those 2023 to 2025 COD projects, which gives us a very high degree of certainty, whereas Sunrise was the last one. That was hit specifically by those steep increases.
Yeah. On your first question, on the later-dated development portfolio in the U.S., it is a fairly insignificant amount that we have booked on those projects. I don't see a big impairment risk on those projects. It's more back-end-dated spend. It's projects where we have some more flexibility because they are to be delivered later in the decade. We will of course make sure that when we take FID on those projects and also spend more on them, that we do it with the consideration to make sure that we have a meaningful value creation on those projects.
That's very clear. Thank you.
Thank you, Harry. The next question will be a written one from Sam Arie from UBS. When I listen to your presentation, I hear the following key points. Much more capital needs to be attracted to the sector. Much more government support is expected around the world. There's perhaps more risk in some projects than previously recognized, as highlighted by the events of last year. Higher bids are needed from developers. Taking these together, is it fair to think that in the coming years, returns in the sector have actually got up quite a bit, both in terms of the headline IRR you can achieve and also the spread above WACC, which that reflects? Thank you.
Yeah. Yes, it is definitely our expectation that the absolute returns will have to go up as we see more inflation, higher costs, higher interest rates. When it comes to the spread we want to get out of winning a project, it will of course be very project specific, depending on timing, whether there's inflation indexation, and whether we can lock in cost certainty at point of bid.
There's of course a lot of things playing into that, but we are of course, taking into consideration the increased uncertainty that we are seeing, and that should come through either a higher spread to WACC, but it could also come through a higher contingency if we are in doubt whether we'll be able to deliver on the CapEx that we are assuming in a bid case.
Thank you to you, Sam.
Yeah.
Go ahead, please. You can go ahead, speakers.
No, just go to the next. Sorry.
Okay, will do. The next question will be from the line of Mark Freshney from Credit Suisse. Please go ahead. Your line will all be unmuted.
Hey, thank you. Thank you for taking my question. On vessels, as I understand it, there's a bit of a, you know, chicken and egg scenario. Some of the builders or asset owners don't want to build these vessels until they've got firm commitments. You don't want to give them until you've got firm clarity as to when you need the vessels. In the past cycle, I mean, you yourselves were a joint vessel owner with Siemens. I'm just wondering why, and so were RWE and partially Centrica. I'm just wondering why, you know, you haven't, given the clarity you have in your business plan, why you're not going ahead and building your own vessel because you know you need it.
If I may be cheeky and ask a one-liner in addition, can I ask what the WACC you're using for the impairment testing of the North American projects is? Thank you.
Yeah. I can answer. Thanks a lot. I can answer the first question. You're right, we did go in as vessel owners. Fundamentally, we would much rather spend our capital on building out renewable energy. We think there are ways in which we can actually pass on, like you, like you say, we have a much greater pipeline and therefore build out certainty than any other in this business, which means that we are in a unique position to actually be able to make those commitments.
That is why we are. We'd much rather go into a dialogue with those who have operating vessels as their main business, give them the commitments and the firm outlook that would mean that they can make safer investment decisions rather than us spending our capital on being vessel owners. We are absolutely leveraging the strength of our predictability of portfolio. Again, we prefer not to make to be owners of vessels.
On the WACC point, I can't give you a specific number, but we are using a, you know, fairly market-conform way of applying WACCs in our impairments. It's the same WACCs we use for our investment decisions. It's with up-to-date, current rates. It's based on a classical capex approach with leverage assumption and betas for the market. I would say it's a fairly standard approach, and it is of course also being increased by the high interest rate environment that we are seeing right now.
Mark, if I can just-
Thank you.
If I can just add sort of maybe a second half to your first question about vessels. I think not relating to whether we own it or not, but one of the key considerations for vessel owners, whoever they are, is of course, how future proof is my investment? Given the ever-increasing size of turbines and the foundations, of course, this is one of the things that everybody's trying to predict, how big does my vessel need to be? Therefore, if the equipment grows too big, will there be a risk that my vessel will be outdated in too few years compared to my depreciation period?
That is also one of the reasons or one of the things we can contribute with as a customer is that we can actually we can decide what turbine and foundation size we want to use, and therefore also give that greater certainty if we want to go into those dialogues.
Perfect. Thank you very much, Mads and Daniel. Thank you.
Thank you, Mark. The next question will be from the line of Dan Togo Jensen from Carnegie. Please go ahead. Your line will now be unmuted.
Yes, hello, thank you. Just a question here to understand the flexibility in your capex and financial planning here. You have this 50 GW target and 30 GW for offshore. You expect to expand by these 3 GW per annum gain around that area per annum. You're a bit ahead now, I understand. What is the flexibility? Let's say you're here in 2023 and maybe even in 2024 gain 5 GWs in the offshore zone auctions and tenders. Will that necessarily trigger that you need to make a capital raise? Just to understand what are these, so to say, the step stones here, and what is the flexibility in your financial planning currently? Thanks.
I can kick it off, Dan. Thank you. If we have a year or two where we would gain sort of a firm capacity of 2 times 5 GWs, that would highly likely be something that would trigger a capital need, because that would be an acceleration of that. Essentially, that would mean that we'd be close to the full 2030 opportunity and therefore be a strong indication that growth beyond the 30 GWs offshore is possible.
I would though caution to say that that is probably not the most likely scenario, and we really want to, as we've said many times, we are not, we are not so hungry on the GWs that we won't have a special eye to ensure that we really go for the most value-creating opportunities. That is really important. With what we have seen, is that we work on the project opportunities, whether they are centralized tenders or open-door, where we feel most comfortable with the value creation potential. We'd rather go a little low to ensure that we're on the safer side on value creation than go really high just because the opportunities are there. That's a balance we of course need to strike.
We would likely raise capital in that scenario. Having 2 times 4 or 5 in the coming 2 years, I think is less likely to happen.
Okay. Thank you.
Thank you, Dan. The next question will be from the line of Jenny Ping from Citi. Please go ahead. Your line will now be unmuted.
Following up on...
Hi. Thank you. Mads, just following up on something you said earlier in terms of the projects in the U.S. as a portfolio shows a positive NPV, assuming a 40% ITC. Can you just factually tell us which one of your U.S. projects has the customer rebate clause in them included as part of the agreement that was originally signed? Thank you.
Yes, we can. That is, if I understand your question correctly, that is our Ocean Wind One project. That's New Jersey. Also for the later projects, it's New Jersey and Maryland that have these passback clauses, whereas Northeast programs, both South Fork, Revolution and Sunrise are all without a passback clause.
Can I just confirm, sorry, the clause talks about 4, 12%?
That is for, I mean, the original case, there was an ITC of 12%, and so it would be beyond that, right? Danny, I'm looking at you.
I'm not completely sure I understand the question. Could you repeat it, Jenny?
I understand some of the clauses talks about a rebate beyond a 12% ITC. You're obviously assuming a 40% ITC.
I think it was originally 18%.
Okay.
There's.
Thank you.
There's a passback mechanism above the 18% that was in there when we made the first bid in in New Jersey.
Okay, brilliant. Thank you very much.
Therefore to, Jenny, to state the obvious, obviously for Ocean Wind One, where the assumptions for ITC were lower, then obviously the potential upside for to get the full 40% is very significant and higher than for Ocean Wind Two.
Thanks very much.
Thank you, Jenny. The next question will be from the line of Ahmed Farman from Jefferies. Please go ahead. Your line will now be unmuted.
Yes, hi. Thank you for taking my question. I think in your comments you mentioned that, you know, the current CapEx trend is above what you viewed in the business plan when you guided to the 350 billion DKK. I was just wondering if you could give us some more specific color on that. How significant are you seeing the current trend above the business plan assumptions? If you can maybe provide some granularity on how CapEx trends in the U.S. compare with some of your key European markets. Thank you.
It's correct that we are expecting that the average 20 or the 2027 numbers we gave at CMD on the CapEx side will be going up due to the cost inflations and bottlenecks that we are seeing. We also expect that EBITDA and ROCE will go up to basically compensate for that. We won't be updating all of these numbers now. We can just say that we see it trending higher. Of course, at a CMD later this year, I think that's of course some of the key metrics that we will be giving you some more details on.
on the differences in the cost development across the regions, I think it's fair to say that in the U.S. being a more immature market, we are seeing costs trending up a bit faster than what we are seeing in Europe. You also have the constraints of, for example, the Jones Act, where it becomes a little bit more difficult to get the full suite of vessels for your construction projects. Higher increases in the more immature markets.
Thank you. Can I just clarify, or follow up just on the ROCE point. Does it just compensate it or is there some positive optionality here on the ROCE as well? I say that because you're obviously reporting above 16% this year, and your target is, you know, 11% to 12% over the period.
Yeah. You could argue that ROCE wouldn't go up if it didn't compensate for the higher CapEx. Our expectation is that ROCE will be trending higher as CapEx and EBITDA is also trending higher.
Thank you.
Thank you, Ahmed. The next question will be from the line of Stig Frederiksen from ABG. Please go ahead. Your line will be unmuted.
Thank you very much for taking my question. just a bit more technical question to your decommissioning provisions. They're going up by more than DKK 5 billion or nearly 60%. Of course, you have grown your portfolio and so, but you're also talking about the change to the methodologies and scope and how you do the decommissioning provisions and so. If you could elaborate a bit on what to expect and what's behind that quite significant increase. Thank you.
Yeah. It's of course an area where we have gained some more knowledge and have also been leaning a little up a bit up against some older assumptions. We're also seeing the vessel market becoming more expensive. There's partly an impact from higher vessel rates. Due to making sure that we don't disrupt the habitats of the offshore wind farms, we will, probably, this is going to be very far out, be cutting the monopiles instead of exploding them, which was one of the previous assumptions.
Then we've also found out that we would need to do the decommissioning in two trains instead of just one. There's a number of reasons for this as we've done a fairly big deep dive on making sure that the assumptions we use also make sense for future worlds, so to say.
Perfect. Thank you very much.
Thank you, Stig. The next question will be from the line of Peter Bisztyga from Bank of America. Please go ahead. Your line will be unmuted.
Yeah. Hi, thanks for taking my question. I just thought it'd be useful if you could set out the key milestones that need to be passed to actually make FID and actually start construction on your U.S. projects. You know, it's February 2023 now, and they're supposed to be operational in 2025. It strikes me you don't have a huge amount of time here if those things are gonna be contributing EBITDA at some point in the next couple of years. Can you also just clarify something for me? You said that you expect to be overall NPV positive, assuming 40% ITC.
I guess following up from Jenny's question, is that statement only true if you're able to renegotiate the customer rebate in New Jersey and Maryland? Thank you.
Yes. I can, I can certainly address those. Thanks a lot, Peter. The, so on the, on the milestones, what it is essentially getting the all scopes ready and having sufficient locked in debt, we are very close to. Also to ensure that we have, that we have a sufficiently strong value creation that we feel it is financially right and prudent to take those FIDs. It is a combination of, let me put it sort of in a vague way stakeholder dialogues concluding in a satisfactory way to ensure that our EPC, and especially our contracts, but also our EPC plan is mature. Those will essentially be the two things that are needed.
You're absolutely right that we are looking at hopefully near term FIDs, but we won't rush them until we have that full construction plan ready and until we have a satisfactory conclusion on getting the top lines that we need for the projects. Specifically on the passback, I'll say that we can't comment on the specific dialogues and unfortunately there we continue to be boring with that. We are, we do see a pathway to getting that portfolio. 2023-2025, we do firmly believe that that is one where we can get the life cycle NPV also to be positive and not just a forward-looking.
That is as close as I can get it.
Let me just clarify. As things stand today, it's not positive.
No. That's.
It's relying on the assumption that, the 40% ITC will be possible to get on the, on these projects. That is, of course, our expectation.
Okay. All right. Great. Thank you very much.
Thank you, Peter. The next question will be from the line of Lars Heindorff from Nordea. Please go ahead. Your line will be unmuted.
Thank you. Yeah, a question regarding the vessels, installation vessels. I don't know if you'd give a status on what goes on in Taiwan at the moment? We're still waiting for a new installation vessels, and to what extent that will have an impact or any material impact on your CapEx assumption of compared to what they originally were when you initiated the project? Thanks.
Yes, certainly we can comment on that. We are very far in having contracted vessels for our upcoming Taiwanese projects. That is not an outstanding concern, is the short answer, Lars.
All right. Thank you.
Thank you, Lars. The next question will be from the line of Alex Wheeler from RBC. Please go ahead. Your line will now be unmuted.
Hi. Thanks for the presentation and taking my question. You spoke about the large amount of capacity to be auctioned in 2023, and that it's essential to see the contract prices reflect in the current environment. With this in mind, are there specific geographies which you currently see as more attractive as you look to auctions in 2023 based on the current visibility and prospective auction structure? Thanks.
Yes. Thank you very much, Alex. The simple answer to that is obviously what is already in the public domain, namely that the New York 3, where we have chosen to bid in. It is actually not right now possible to say firmly where are those most attractive opportunities because, for example, Japan, which was very challenging in the first round, as I think every industry observer knows, we are still working on clarifying whether the revised upcoming auction framework is something that makes us believe that that could be attractive, which we believe it can. That would be an example.
Also, we are working heavily on getting under the skin of the recently announced German auction framework to evaluate whether we believe that framework will give opportunities for the strongest value creation. Obviously, we are not a big fan of auction frameworks where negative bidding becomes an option, which it seems it does. On the other hand, the ample capacity means that there could still be opportunities within that. We are... I'll say that we are closely following everything. What we know for a fact is that even though we unfortunately did not come out successful, then that the upcoming Dutch IJmuiden 4 GW auction is one that is very likely to also be attractive for us.
Otherwise, we are following all markets and do not rule out anything on this Slide except Ireland, where we don't have the seabed available.
Okay, that's clear. Thank you.
Thank you, Alex. The next question will be from the line of Vincent Ayral from JP Morgan. Please go ahead. Your line will be unmuted.
Yes. Thank you for taking the question. I'd like to come back on the hedging. You've made a few Slide on that. Clearly you've been hit by all the hedging in 2022. You were talking about hedging levels around 95% just 10, like 10 days ago. On the pre-release, we heard about 9%. Today you talk about 85 as a final number there for the hedging level on offshore wind in 2023. You probably bought back some volumes. The question I would have here is, it's probably cost money. Is it locked into the 2022 numbers, yes or no?
The second thing is, you talk on the same thing, your new strategy on the hedging, to reduce the other hedging and not go above 70% at a group level, which is fine. You also talk about IFRS 9, but IFRS 9 is a non-cash issue. It's a matter of presentation. You have been presenting on a non-adjusted basis. Why don't you move to an adjusted basis? If you don't, basically, how much do you expect to unwind exactly in 2023 if the power price were to stay where they are? Not doing anything with the current commodity prices would lay a lower IFRS 9 impact in 2023 quite clearly. Thank you for answering these questions.
When we had our conference call, two weeks ago, I said around 90%. The more precise number is the 85%. The call was not about that hedge percentage, so it was more of a, of a rough number. We have been buying back hedges both in late 2022, so there's a little bit of cost in there. Also some here in the beginning of 2023, and that's of course also reflected in the, in the guidance that we've given. On the IFRS 9 point, you are right. We want to make sure that we follow the IFRS 9 way of reporting our numbers, so that is what we are doing in our annual report.
We are also giving you the supplementary information so that you know how big the drag have been on our numbers. In 2022 it was DKK 1.3 billion. As it is a timing effect, and we expect it to be coming back, we have factored in a profile that matches the underlying hedges. Out of those 1.3, you have DKK 200 million coming back in 2023, which is also included in our guidance.
All right. Thank you very much.
Thank you, Vincent. The next question will be from the line of Louis Boujard from Oddo. Please go ahead. Your line will be unmuted.
Yes. Good afternoon. Thank you very much. Maybe one question regarding your flexibility in your pipeline. On the 11.2 GW of awarded and contracted renewable capacity, which has not yet been FID on the offshore wind project, do you have eventually some room if the discussion and if the negotiation does not come to an end in some of them to take the decision not to go ahead and not to take the FID and eventually to withdraw them? If yes, what could be the financial consequence for 1 or 2 of these projects if it had to happen?
Yes. Thank you very much. I would say that it is our clear ambition to make all of these projects, reality. You say that. In principle, I mean, you There's always a way out, but of course, that need to be factored in. What are the cost of that, both in terms of the commitments that we might have incurred and so on. In general, it is a much more likely scenario, and not likely, but more likely than walking away from the projects. We say we might buy ourselves time to work with our partners to make those projects better, because there can be some flexibility in the timing of it. That is much more where we are looking at.
Where does that timing flexibility, which we have in some of the projects, clearly, where does that actually play into being able to maybe, hit a period of time where there are less bottlenecks, where there's less strain on commodity costs and so on, and where it fits better into our construction train of different projects. We do have flexibility and it is not impossible to walk away from anything, but we do remain committed, and we're working, first within the existing timelines, but if absolutely needed, also with a possible extension to work, make the projects investable.
Okay. If I may just as a follow-up, shall I understand that it is possible eventually to have a CapEx which would be extended on a longer timeframe then?
Yeah. There's other opportunities of course come in. I would say that we are looking at, as we talked about before to a previous question, there are very significant opportunities, including both Onshore, offshore, centralized auctions, also open-door. Some of those.
Can also come relatively nearer term. We actually, we said that, for example, in the, in the up to 5.2 GW Danish open-door opportunities, those are some that could actually COD as early as potentially 2027. Also, if we'll go ahead and potentially extend to make the projects better from the already awarded list, there could be options. Not saying that that would happen, but there could be options to spend that CapEx on other projects. Please don't hear us saying that we are currently planning to extend or that we are planning to walk away, but also say that if that happens, it won't automatically mean a total sort of extension of the CapEx spend.
We would likely pursue other value-creating opportunities if they're there.
Thank you. Thank you very much.
Thank you, Louis. The next question will be from the line of Tancrede Fulop from Morningstar. Please go ahead. Your line will be unmuted.
Hello. Thank you for taking my question. I have two of them. The first one is on CapEx and your guidance for growth investment for 2023 of DKK 50 billion-54 billion. It is quite above the expectations of around DKK 32 billion. If you could help us to understand the sources of your upside, how much is due to phasing, maybe the delay in Greater Changhua, and how much is related to inflation? This will be my first question. The second question for the U.S. project. You said that most of them will be NPV positive if they are eligible to an ITC of 40%.
shall we understand that, okay, NPV positive, but, the spread IRR to WACC will be below your target range of 150, 300 basis points, meaning that you will proceed with projects which meet your returns result? Thank yo
Yes. I can give perspectives on that. The main boxes if for the CapEx spend in 2023, which is DKK 50 billion-DKK 54 billion, there's an approximate DKK 5 billion that would be a spillover from 2022 into 2023. On top of that, we are looking, as we talked about to a previous question, we are looking at a sort of, hopefully, and expectedly, a fairly sort of high number of FIDs being taken, which would obviously accelerate our CapEx spend. Also bear in mind that with the total CapEx that we announced at the last Capital Markets Day, if you divide that by the number of years, the average would be sort of approximately DKK 44 billion-DKK 45 billion.
Over the last three years, it would actually be around that level. It's not an abnormally high level, but due to the phasing between the two years and also hopefully an accelerated CapEx spend on projects that we have ID that we don't. We see this clearly within our plan. On the U.S. projects, the direct answer to your question is yes, in light of the new realities with the cost of capital and also the CapEx inflation, these projects will not be within our guided range of 150 to 300.
We clearly, obviously, when we bid in, they were well within that range at the time, but due to those circumstances, now they're not. The portfolio of the 23-25 is under the assumptions we discussed before. They are at the portfolio level, they are NPV positive, but not within the range.
Very clear. Thanks.
Thank you, Tancrede. The next question will be from the line of Dominic Nash from Barclays. Please go ahead. Your line will be unmuted.
Yes, good afternoon, everyone. Just one question from me is regarding your partner or your partners, I should say, in Eversource and PSEG. Could you give us an update on what's going on with the Eversource position as to are they still looking to sell, and what sort of timeframe are we looking for to get your news flow on that? Will you be looking at potentially buying back or getting the 50% Eversource sale and buying back similar to sort of PSEG? Thank you.
Yes. I can comment on it, but it won't be a very specific answer. Yes, the process is ongoing with Eversource in the sales process. We are highly unlikely to acquire the remaining 50% stake, despite us doing that at cost in Ocean Wind 1 with the 25%, which was due to, as we also explained in a previous call, not because Eversource is running away, but due to the fact that now it's ITC rather than PTC, and Eversource or sorry, PSEG, had difficulties monetizing that. That was the reason for that. With Eversource that is progressing. I don't think we're in a position to give a timeline on that.
That needs to be Eversource who gives an answer to that. As previously commented, if anything, it would be a dialogue that between us and Eversource about potentially acquiring the seabed, but not the 50% stake on the Northeast program.
Okay. Thank you.
Thank you, Dominic. As we are running out of time, I will now hand it back to Mads for any closing remarks.
Yes. I would simply like to thank you very much for joining, and appreciate all the great questions, as always. Should you have more questions, you know that our IR team are more than happy to answer them. Thank you very much. Stay safe and have a great day.