Oersted A/S

SWB:D2G

Earnings Call Transcript 2022-Q1

[Operator]

Welcome to the Ørsted interim report for the first quarter of 2022. [Operator Instructions] Today, I am pleased to present Mads Nipper, CEO; and Daniel Lerup, CFO. Please begin your meeting.

[Mads Nipper, executive]

Thank you very much, and good morning, good afternoon, everyone. Welcome to our earnings call for the first quarter of the year. Next to me, I have our newly appointed Group CFO, Daniel Lerup, who most of you likely already know from when he headed Investor Relations team a couple of years ago. Daniel will present the Q1 financials before we open for questions.

Before we head into the strategic highlights for the first quarter, let me start by addressing the terrible situation we continue to witness in Ukraine. We and I are deeply disturbed by the situation, especially the human suffering. And the Russian aggression goes against everything Ørsted stands for, and as a consequence, we are taking every step possible to stop our cooperation with Russian companies, including having ceased all sourcing of biomass and coal from Russia for our power stations while still checking the security of energy supply in Denmark and Europe into consideration.

As you're probably aware, Ørsted has a long-term take-or-pay contract with Gazprom Export that expires in 2030. We have decided that we will only offtake minimum quantity, a yearly quantity volume of gas under this gas purchase contract. Furthermore, I can confirm that we have no intention in paying in rubles and that we are in close dialogue with other energy companies and the authorities regarding a common European response to Gazprom Export. Let me emphasize that gas isn't part of our core business, and we will not be extending the contract.

On that note, let me add a quick comment to our headline EBITDA for the first quarter. I'm very pleased with our financial start to the year as we reported an EBITDA of DKK 9.4 billion for the group, representing a DKK 4.6 billion increase compared to the same period of last year. Similar to what we experienced in the last quarter of 2021, the diversification effect between our assets in offshore and bioenergy has proven to be very useful in the continued high and volatile energy prices. During the quarter, we also benefited from wind speeds above the norm.

Turning to the strategic highlights. I'll start with 2 significant milestones within our offshore partnerships. In February, we completed the farm-down of 50% of the 900-megawatt German offshore wind farm, Borkum Riffgrund 3 to Glennmont Partners. We are proud that Ørsted once again has led the way by being the first developer to take final investment decision on a merchant offshore wind project. Subsequently, we have signed an agreement to divest 50% share of Hornsea 2 to a consortium comprising AXA and Crédit Agricole Assurances at a transaction value of GBP 3 billion.

The economics of the deal implies a healthy NPV retention and once again demonstrates the continued high interest from financial partners even in an environment of increasing interest rates. The transaction is expected to close in the second half of 2022 once the wind farm is fully commissioned and certain regulatory approvals are obtained.

In February, we and our 50-50 joint venture partner, Eversource, took FID on our first U.S. offshore wind project, South Fork. The 130-megawatt project would be New York's first operational offshore wind farm. Once completed at the end of 2023, the offshore wind farm will generate enough clean renewable power to power 70,000 homes and will help advance New York state's nation-leading clean electricity goals.

In Poland, we have, together with our partner, ZE PAK, submitted seabed lease applications in the Baltic Sea. We will know the outcome of the lease auction towards the end of this year. Together with our partner, we look forward to expanding our footprint in Poland and support the country's journey towards climate neutrality. Poland's first CfD auctions are planned for 2025 and 2027.

In Taiwan, our Greater Changhua 1 & 2a offshore wind farm successfully delivered first power earlier this month. This milestone is a big achievement for Ørsted and the industry as Greater Changhua 1 & 2a is the first large-scale offshore wind farm in Taiwan. The wind farm has a capacity of 900 MW, and once completed, it will significantly support Taiwan's fast-track build-out of renewables and provide the green energy much needed by export industries and by Taiwan to achieve its net-zero goal.

In relation to the cable protection issues, which we discovered and reported as part of our Q1 2021 results, we have now reassessed the expected costs of reinstating the integrity of the cables. And based on thorough investigations, analysis and fast reactions, we have been able to place additional engineered rock berms around the cable protection system, which have significantly lowered the expected costs relating to the issue. Daniel will address the details around the financial consequences of this.

Turning to -- the focus to our efforts within floating offshore wind. We have 2 significant strategic milestones to start the year, covering Scotland and Spain. In Scotland, we acquired a majority stake in the floating wind development project, Salamander, where we will enter a joint venture with Simply Blue Group and Subsea 7. We see this 100-megawatt development project as a stepping stone designed to provide the Scottish supply chain with an early capacity development opportunity before the larger ScotWind projects kick off. This includes our 1-gigawatt [ Stroma ] project, together with Falck Renewables and BlueFloat Energy. The project is intended to be progressed through the innovation track of Crown Estate Scotland's forthcoming innovation and targeted oil and gas leasing round later this year. It will deploy innovative and cutting-edge floating offshore wind technologies to support the cost reduction and learning journey needed for the commercial deployment of floating offshore wind.

Furthermore, I want to highlight our entry into the Spanish market for floating offshore wind. I'm pleased that we've been able to move into one of the key growth markets for renewables in Europe. And together with Repsol, we want to explore and jointly develop floating offshore wind projects with the ambition of becoming a leading developer of Spanish offshore wind. After several years of concept development and for small-scale testing, floating offshore wind is now on the brink of commercialization, and the global offshore wind market is expected to reach 21 GW of installed capacity by 2035, according to estimates from Bloomberg New Energy Finance.

Spain targets 3-Gw floating offshore wind by 2030, and the Spanish supply chain is well prepared to enter floating offshore wind on the back of decades of experience from supplying to Spain's massive fleet of onshore wind farms. We look very much forward to working with Repsol, the country's leading energy provider, to help accelerate Spain's transition to renewable energy while creating local jobs and investing in the Spanish supply chain.

Continuing to onshore. We commissioned the onshore wind farm, Haystack, in Nebraska during the first quarter. Haystack is our second operational project in Nebraska and the third operational project in the SPP market. With the addition of the 298 MW, we now have more than 3 GW of onshore wind and solar capacity in operation in the U.S., a significant ramp-up on the 1-GW operational capacity this time last year.

Just yesterday, we took FID on Sunflower Energy Center, a 201-MW onshore wind project located in Kansas. The project was acquired together with Lincoln Land Wind last year. And since the acquisition, critical development activities have been completed and the project has been optimized to deliver a strong business case. The project is expected to reach commercial operation in the second half of 2023 and will bring our capacity in the SPP market to 832 MW.

Moving on. The global hydrogen and e-fuels landscape is changing rapidly. And as a consequence, we have decided to further strengthen our hydrogen organization and have rebranded it to Ørsted PtX or Power-to-X. We continue to see strong momentum within renewable hydrogen worldwide, and since the publication of our annual report for 2021, we've continued to make significant progress in our renewable hydrogen and green fuels pipeline.

In March, we signed a landmark letter of intent with Maersk, where Ørsted will develop a 770 -- a 675-MW e-methanol facility that will produce approximately 300,000 tonnes of e-methanol per year, which Maersk will offtake for its newly ordered fleet of 12 methanol-powered vessels. The facility will be powered by approximately 1.2 GW of renewable energy from new U.S.-based onshore wind and solar PV farms. And we have commenced development works of the project which is targeted to be commissioned in the second half of 2025, making it one of the most ambitious projects globally producing e-methanol at scale, and a driving force in the decarbonization journey of the maritime sector.

Lastly, we have decided to accelerate part of our green fuels for Denmark project and investigate production of green jet fuel for 2025, following the increased Danish ambition to establish green aviation opportunities in Denmark as early as 2025. Together with our partners, we have decided to accelerate 100 MW of the original planned Phase 2 electrolyzer by 2 years and to begin capturing sustainable CO2 both by the end of 2025. This 100 MW can produce more than 50,000 tonnes of sustainable fuels by 2025. While the produced e-methanol will mainly be dedicated to shipping, the partnership will also examine whether a portion can be used for green aviation fuels as well.

Turning to Slide 4 and a focus on the European energy crisis. Europe has already been long on its journey on addressing the climate change with its renewable energy targets and incentives, world-leading value chain for renewable energy and millions of jobs it has created in the industry. Europe still has quite a way to go from reaching its renewable ambitions as we are not yet as efficient as possible when it comes to permitting and issuing seabed leases, and we still have vast dependency on fossil fuel-based energy sources. The situation has now been intensified by Russia's unwarranted and terrible invasion of Ukraine. Moscow's propensity to use energy for geopolitical leverage only underscores how dependency on imported fossil fuels can neither deliver the security of supply that Europe needs nor help address climate change.

The solutions to the 2 problems of energy dependency and climate change are the same. We need to replace fossil fuels with renewables, directly and indirectly electrify energy use, improve interconnection and mitigate the issue of intermittency and use energy as efficiently as possible. We are already doing this, but the Ukraine crisis shows the need for an even greater speed. Ørsted has found that up to 30 GW of additional European offshore capacity can realistically be in place by 2030 and 60 GW by 2035 on top of the current build-out targets. This additional capacity is not an easy feat. It will require a whole new approach to offshore wind and Power-to-X development and delivery. From today's incremental build-out focusing on cost reductions, Europe must move to a sustainable accelerated build-out, focusing on societal value and scale.

To accomplish such a feat, the authorities in each country will need to accelerate the deployment of -- by fast-tracking existing projects and streamlining permitting processes. Secondly, space needs to be allocated to enable large-scale build-out towards and beyond 2030. The authorities must avoid the mistake of monetizing offshore wind and instead deliver society a win, where they are reaping the socioeconomic benefits of a rapid build-out. When developers pay substantial fees to secure seabed rights from lease auctions, these costs will eventually end up being reshuffled from taxpayers to electricity payers. And furthermore, this race to cut costs risks blunting the industry's ability to effectively deliver on European policy objectives. And at the same time, it exerts further pressure on the European supply chain and its ability to invest in ramping up capacity, which is pressed in the face of rising inflation and rising commodity prices.

Thirdly, the industry needs to be activated to help solve the challenges around an expedited build-out by matching large offtakers demand for renewable power, renewable hydrogen and e-fuels with supply, along with mitigating potential negative environmental and social sustainability impacts of new infrastructure. And lastly, a clear role for hydrogen and e-fuels needs to be appointed to unlock investments into a future renewable hydrogen economy, along with finalizing and fast-tracking ongoing regulatory and designing strong framework to ensure a further supply push and stronger demand pull.

Over the recent months, we have seen several countries move in the right direction by upgrading their renewables targets and adding new renewable initiatives, which is very much in line with our view on how to accelerate the build-out of renewables. Germany's recent Easter Package increased their offshore wind target by 10 GW to a total of 30 GW by 2030. Moreover, renewable projects can override public interest and would be given priority over other concerns until greenhouse gas neutrality is met. The U.K. has presented a plan to boost energy security and increased their offshore target by 10 GW to a total of 50 GW by 2030. The U.K. will also introduce new planning reforms to cut the approval times for new offshore wind farms to 1 year and an overall streamlining, which will radically reduce the time it takes for new projects to reach construction stages.

The Netherlands will significantly ramp up the build-out of offshore wind in the coming years by doubling the planned capacity by 2030; and in Belgium, the Minister of Energy called to raise the offshore wind target to 8 GW by 2030 as well. And finally and most recently, Denmark announced an ambition to add an additional 1 to 4 GW of offshore wind on top of the already agreed 7.2 GW towards 2030.

We welcome the EU's focus to stop this dependence on Russian oil and gas and speed up the green transformation of the energy sector, as outlined in the recent REPowerEU policy. And we at Ørsted are ready to help drive the accelerated build-out.

Turning to Slide 5, where I'll give you an update on our construction projects and pipeline, starting out with projects under construction. We are constructing 2 of the largest offshore wind farms in the world, Hornsea 2 and Greater Changhua 1 & 2a, both of which are expected to be commissioned later this year. At Hornsea 2, we have installed all foundations, array cables and turbines. We are currently electrifying and waiting for all turbines to pass the final tests. However, the commissioning of the individual turbines has been progressing slower, and the ramp-up profile has been delayed compared to our expectations at year-end due to very strong wind in February, which is obviously great for our operational earnings but resulted in very few days to do commissioning work.

In addition, we have seen slow progress of commissioning during March and April, owing to supply chain quality issues, which have required a significant amount of time troubleshooting. We continuously work with the supplier to ensure we take away all the relevant learnings so that we don't experience similar issues on other wind parks. And as a consequence, we now expect to commission Hornsea 2 during summer.

In April, we achieved first power at Greater Changhua 1 & 2a, and we've successfully installed 40 jacket foundations out of 111. We continue to make good progress in all areas of construction, and we expect to commission the wind farm during second half of this year. As previously mentioned, we continue to monitor Taiwan's COVID-19 restrictions, which can potentially still affect the construction schedule and eventually lead to possible delays.

Turning to our onshore renewable projects under construction, where we are currently constructing just north of 1 GW. In Europe, our 3 onshore wind construction projects, Kennoxhead 1, Lisheen 3 and Ballykeel are progressing as planned. As for solar in the U.S., we are currently constructing the solar PV wind farm -- or solar PV farm, Old 300, and our first combined onshore wind and solar PV project, Helena Energy Center. The wind part of Helena Energy Center is progressing according to plan, expected to be commissioned during 2022; whereas the commissioning of Old 300 and the solar part of Helena Energy Center will expectedly be pushed into first half 2023 and 2023, respectively, due to the continued challenges in the solar panel supply chain relating to the forced labor allegations in China and potential U.S. tariffs on Chinese goods.

However, I would like to highlight that we have executed a framework agreement with First Solar to provide a total 1.7 GW of modules to support various late-stage development projects in 2023 and 2024, to ensure that we can progress our pipeline of development projects.

For our U.S. offshore development projects, development is ongoing, and we are constructively managing the challenges we face, and we remain confident for our overall commissioning dates for the U.S. projects. That said, it is clear that the global supply chain and the project developers have faced bottlenecks and inflationary pressure due to the vast increase in demand from COVID stimulus packages, the physical constraints of COVID restrictions and, most recently, the Russian invasion of Ukraine. For the portfolio of our projects where we have taken final investment decision and started construction, all contracts are secured. And at our early-stage awarded projects -- development projects being Revolution Wind, Sunrise Wind and Ocean Wind 1, we have less than 20% of total contracted CapEx outstanding and are continuously working to lock in the remaining minor part of total construction costs.

As mentioned in the Q4 earnings call, the situation remains that we are not seeing the value creation we had aimed for, but we would note that the projects are still NPV-positive. As is normal business practice, we continue to look for levers to help improve the business case and we constantly have a process running to find opportunities, act on them and follow-up on the progressing, meaning there is a program for continuous improvement.

Today, the key largest lever continues to be the regulatory angle. And as such, we continue to support the clean energy legislation of the original big -- Build Back Better bill, which will ensure the continuous momentum of the offshore industry in the U.S. Other levers are still in the works as well, such as continuing to find efficiencies and synergies at both the project and portfolio levels as well as optimizing commissioning to achieve earlier energization.

Another aspect of inflation risk is the impact towards revenue. For the next 10 years, 55% of the total revenue from our operating assets, assets under construction and our awarded projects have an inflation indexation, and merchant exposure constitutes 10%. The remaining 35% of the exposure is fixed nominal cash flows, and we actively mitigate this exposure through a combination of duration match debt and hybrids as well as derivatives so that our total net inflation risks sits at just 20%. Having such a high degree of assets which are currently inflation index, is very valuable in the current inflationary environment.

Let's move on to Slide 6 and a brief update on upcoming offshore wind auctions and tenders. We continue to see a significant number of auctions and tenders globally to take place in our core markets during 2022 and 2023. In addition, we see numerous other markets which are not our core markets for the time being, like France and Greece, where several auctions are being launched in the coming years. And we're excited for the opportunities ahead of us, and we'll continue to leverage our industry-leading pipeline and capabilities to ensure we fulfill our strategic ambitions of adding an average of around 3 GW of value-creating offshore wind capacity per year.

And with this, let me hand over the word to our CFO, Daniel.

[Daniel Lerup, executive]

Thank you, Mads, and good afternoon, everyone. I'm very excited to be part of our earnings call for the first time. I will continue to support our strong focus on value creation and financial discipline, and I look forward to engaging with all of you going forward.

Let me start with Slide 7 and the EBITDA for the first quarter of 2022. For the group, we realized a total EBITDA, including the effect from new partnerships of DKK 9.4 billion, an increase of 94% on last year. EBITDA, excluding new partnerships, totaled DKK 7.8 billion, representing a 61% increase on last year. The earnings in our offshore business increased 50% and amounted to DKK 5.9 billion. During Q1 2022, wind speeds amounted to a portfolio average of 11.3 meters per second, which was higher than last year as well as the normal wind speeds expected in the first quarter of 10.9 meters per second. The higher wind speeds contributed with around DKK 500 million, and we also had ramp-up generation from Hornsea 2. This was partly offset by lower earnings from Borssele 1 & 2, following the 50% farm-down in May 2021 and higher transmission tariffs following the divestment of the offshore transmission asset at Hornsea 1 in March 2021 and generally higher TNUoS and BSUoS tariffs across our U.K. sites.

Due to the later-than-expected commissioning of turbines at Hornsea 2, combined with very high and volatile power prices, we realized a negative impact from being overhedged of DKK 1.6 billion during Q1 2022. The negative impact also reflects the inefficient hedges in the remaining months up until commissioning. And of the DKK 1.6 billion, 50% relates to the exposures for Q1 2022, whereas the other 50% relates to exposures in future periods up until commissioning. In hindsight, we should not have hedged such a large part of the ramp-up production on Hornsea 2, but our good construction progress and elevated power price levels at that point in time were key drivers for the decision.

In relation to the issues with several of our cable protection systems, which we discovered in Q1 2021, our initial assessment pointed to a total financial impact of around DKK 3 billion. Since then, we have conducted thorough investigations and analysis of the issue, and we have reacted swiftly to reinstate the integrity of the cable protection systems, which have led us to reassess the expected costs significantly downwards. We now expect that the total cost will amount to approximately DKK 1.3 billion, of which DKK 0.3 billion covers provisions towards our partners and DKK 1 billion will be capitalized. As a result, we have reversed DKK 0.5 billion of the initial DKK 0.8 billion warranty provision towards our partners. Within our existing partnerships, we also reported earnings from finalized projects and construction work for partners at Greater Changhua 1 during Q1 2022.

Earnings in our onshore business almost quadrupled and amounted to DKK 850 million, driven by the significant ramp-up in generation capacity as well as a benefit from higher power prices for our European assets. In bioenergy and others, earnings increased by DKK 1.9 billion, significantly increased, driven by the exceptional performance by our CHP plants due to the higher -- high power prices and higher sale of ancillary services.

We only hedged the power we cogenerated with heat and therefore, fully benefited from the higher power prices on our condensed power generation during the quarter. In addition, earnings from our gas markets and infrastructure benefited from a temporary positive effect from revaluating our gas at storage at a higher price level. Furthermore, we were able to lock in gains from optimizing the offtake flexibility in some of our sourcing contracts in Northwestern Europe.

In contrast, our decision to unwind gas hedges related to the Gazprom contract to balance our risk if gas supplies from Russia are ceased, have led to a net loss on the Gazprom sourcing contract for the quarter.

These effects bring our EBITDA, excluding new partnerships, to DKK 7.8 billion. Adding the DKK 1.6 billion farm-down gain from the 50% divestment of Borkum Riffgrund 3, we realized a group EBITDA including new partnerships of DKK 9.4 billion. We continue to see very high-power prices across the markets where we operate, which have had a significant impact on our financial performance across our offshore and bioenergy businesses.

On a portfolio level, roughly 90% of our earnings are regulated and long-term contracted, while we hedge the majority of the remaining 10% of our exposure in the first few upcoming years. As we described at our Q4 earnings call, we had fully hedged our merchant exposure within our offshore business, including the expected ramp-up of production at Hornsea 2. While in bioenergy, we had only hedged the power we cogenerated with heat. As described, we realized a negative impact from the delayed ramp-up of Hornsea 2, while we fully benefited from the high-power prices on our condensing power generation at our CHP plants.

At the group level, these effects have, to a large degree, offset each other. And I'm happy to see the portfolio effect as it demonstrates the benefit of diversification between our different types of assets.

Let's continue to Slide 8, covering our net profit, net debt and credit metric. Net profit for the period totaled DKK 5.7 billion, significantly ahead of last year, driven by the higher EBITDA in the quarter and only partly offset by higher depreciation following more assets in operation. Our net debt amounted to DKK 30 billion, an increase of DKK 5.7 billion during the quarter. Our cash flow from operating activities reflects the EBITDA being offset by a net cash outflow from work in progress, combined with initial margin payments to clearinghouses and margin payments on unrealized hedges totaling DKK 4.8 billion due to the increasing and volatile power and gas prices. These margin payments only impact our liquidity temporarily. Our gross investments totaled DKK 6.8 billion, driven by our continued investment in offshore and onshore wind and solar PV farms, while the divestment proceeds related to the 50% farm-down of the Borkum Riffgrund 3 project.

Our key credit metric, FFO to adjusted net debt, stood at 25% for the 12-month period ending in March 2022, which is in line with our credit metric target. And I will note that we expect the metric to increase towards the end of the year. The decrease compared to last year was mainly driven by lower funds from operation due to the margin payments and by a higher net interest-bearing debt, as I just described.

Let's turn to Slide 9 and our financial and nonfinancial ratios. Our return on capital employed, ROCE, came in at 19% with the increase compared to last year being driven by a higher EBIT over the 12-month period due to the farm-down gains of Greater Changhua 1 and Borkum Riffgrund 3. In Q1 2022, our taxonomy-aligned share of revenue was 68%, our share of OpEx was 79%, our EBITDA was 87% and the share of gross investments was 98%.

The noneligible part of our revenue primarily relate to our long-term gas legacy activities and noneligible power sales. It is our expectation that the share of taxonomy-eligible revenue will increase in the coming years. Green share of energy came in at 92% in Q1 2022 compared to 87% in the same period last year. The development was primarily due to more wind and solar farms in operation, higher wind speeds and warmer weather, leading to lower CHP generation from coal.

Turning to safety. We have had an encouraging start to the year with the number of injuries decreasing 47% on last year. This decrease, combined with a 23% increase in hours -- in work hours led to a total recordable injury rate of 1.3 in Q1 2022.

Finally, let's turn to Slide 10 and our outlook for 2022. We reiterate our full year 2022 EBITDA guidance of DKK 19 billion to DKK 21 billion as well as our gross investments of DKK 38 billion to DKK 42 billion. We have changed the directional guidance for the bioenergy and other business to lower from previously, significantly lower, mainly due to higher earnings from our CHP plants due to the high-power prices. The increased earnings in gas markets and infrastructure have, to a large extent, been driven by temporary positive effects from revaluation of our gas and storage due to the higher gas prices and is suspected to partly reverse later in 2022. The directional guidance for the offshore and onshore businesses remains unchanged. We remain comfortable with our long-term financial targets, including EBITDA growth, ROCE and contracted share of profits.

With that, we will now open for questions. Operator, please?

[Operator]

[Operator Instructions] Our first question comes from the line of Deepa Venkateswaran of Bernstein.

[Deepa Venkateswaran, analyst]

I had a couple of questions. One is on the Gazprom contract. Is it fair to assume that you've unwound the -- I mean, maybe you've had a quarterly hedge exposure, you unwound that. And at this minute, if Gazprom were to stop supplying, there wouldn't really be any financial implications? So could you just confirm that? And presumably, you said that you don't intend to open those ruble accounts. So perhaps they can stop supply like they've done in Poland.

And the second question on the e-methanol project that you've mentioned with Maersk. Would that come from some existing portfolio of wind and solar farms? Or would the renewable leg of that be separate projects that you'll identify? So how should we think of that adding to your targets?

[Mads Nipper, executive]

Thank you very much. I will give that -- those sort of perspectives. So on the Gazprom contract, it is -- we have worked quite intensely to balance our risk profile and really unwind the hedges we have. This is, as mentioned, a take-and-pay contract, which I'm sure you're fully aware, and our total annual volume is around 20 terawatt hours.

We have now unwound hedges so that we are well below 1 terawatt hour, meaning a very limited exposure for the year in case of a complete stop. And in case that happens, depending on what will play out, then obviously, there would be implications for power prices in general. So we expect that exposure net-net to be very limited.

On the e-methanol project in the U.S., this is where -- this is clearly planned to be with new assets. So we are planning to construct the approximately 1.2 GW from assets that are going to be built, so not existing assets.

[Operator]

And our next question comes from the line of Casper Blom at Danske Bank.

[Casper Blom, analyst]

A question regarding, say, CapEx and also offtake prices within offshore wind. We've been in a period where it's been sort of the normal that costs relating to offshore wind has just been declining year after year after year at rapid speed. And now we see that input costs are starting to come up and inflation is everywhere. Are the sort of relevant regulators around the world realizing this? I mean is it possible to start seeing increasing offtake prices from offshore wind projects on the back of this? Or do governments still have a mindset where prices just have to decline year after year? If you can talk a little bit about that situation there.

[Mads Nipper, executive]

We certainly can, Casper. And that is also why we chose even in this call to spend a little bit of your time sort of highlighting our guide, not -- surely not just to our investors, but not least the message we are passing on to regulators around the world. We are seeing this. Generally, there is still a relatively high focus on continuing to try and drive prices down. But we are very encouraged to see that there are also clear examples of regulators getting it to introduce broader societal value creation in the criteria for awarding projects.

And I'll also -- so Holland is a good example of that. And I'll also mention the example of allocation of seabed. What we saw in ScotWind was a very sort of very, very large allocation of seabed with a clear and absolutely acceptable price cap, which meant that this is something that actually takes some of the pressure off that price, only focus. But to be honest, it is something which is in a movement because you're perfectly right, that it -- for the industry as such and our ability to continue to fuel the green transformation and especially also in offshore with increasing inflation, then a continued sort of push to wanting to have lower and lower prices, it is not something that will stimulate the necessary investments if that continues. So we are leaning in, as a clear industry leader also with our white paper, which we call Need for Speed. We are making that available. We made that point very clear at WindEurope's event in Bilbao. And we will continue to push that. But some are getting it and some are, if I put it positively, in the process of getting that, we need to focus broader.

[Daniel Lerup, executive]

And maybe I can add that in the corporate PPA market, we are also seeing that prices are going up, both across offshore and onshore. And that has actually been one of the key drivers for enabling the FID on the Sunflower project that we have ID-ed yesterday.

[Casper Blom, analyst]

Interesting. To sort of take this to another step, we've talked a lot about increased competition in the past and the classic talks about oil majors stepping into the industry. Are they also sort of -- I'm sure they understand that the input costs are coming up and it's becoming more expensive to construct. But have you seen any changes to the, sort of, competitive behavior following this inflation?

[Mads Nipper, executive]

It -- there has not been any awards this year, sort of, offshore awards. But what we did see was it was interesting to see that some of the industry players that have previously been very aggressive on price in our industry, some of those did not have any seabed awards in the New York Bight auction. Like we also chose to step out to ensure that if we had a win, we could ensure financial value creation. But it was encouraging to see that some previously quite aggressive players also chose to either not attend or step out, which we see as a sign that there is clearly an increasing focus on value creation, which is very natural in light of the developments we see on inflation.

[Casper Blom, analyst]

Excellent. And then just my last thing here. Mads, you talked about the sort of additional potential for build-out in Europe as European leaders are calling out for an alternative to Russian energy. How quickly do you think we can see that materialize into actual auctions and projects being ramped up?

[Mads Nipper, executive]

Well, I can say that the -- in offshore, if we stay with that, then these -- the targets that are out there remarkably actually are not 2050 targets or 2035 targets. They are increasing short-term targets, so 2030 targets. So we clearly do expect that those targets are going to -- are actually going to be backed up by very tangible actions within the next sort of the near future. We are hoping for that to be a combination of CfD-backed auctions, but hopefully also to be a significant increase in open door opportunities. Like, for example, Germany seems to be moving in that direction, and we expect that to happen relatively short term. So within the next year to 18 months to be -- to have a much higher visibility of those opportunities.

[Operator]

[Operator Instructions] Our next question comes from the line of Vincent Ayral of JPMorgan.

[Vincent Ayral, analyst]

So if it's only one question, I'll just ask for a further clarification regarding the Gazprom contract. We can see you've taken the net loss in Q1 on the Gazprom contract. So is it 100% clear for us, for everyone here that actually you do have included all the costs in your guidance and you upgraded guidance on bioenergy end markets, which is -- has been increased from significantly below to -- lower. So it's all accounted for basically. Is it how we should look at it?

[Mads Nipper, executive]

It is -- it was super hard to hear the question. Would you mind repeating it, so we're entirely sure we answer it? It was not clear whether you were talking specifically about Gazprom and gas only or whether you were talking about markets and -- or bioenergy and others in its entirety.

[Vincent Ayral, analyst]

I'm moving to the speaker. I hope -- can you hear me better now?

[Mads Nipper, executive]

That's better.

[Vincent Ayral, analyst]

Okay. Let's do it this way. Sorry. So one question. So I'll go back on the Gazprom contract to be 100% clear on that. So you've taken a net loss on your Gazprom contract in Q1 for the unwinding of the hedges. So my understanding here is that if Gazprom stops delivering at the next -- following the next payment date, as you don't pay ruble, you have a zero extra cost. And what we've seen today, which was a slight upgrade of the bioenergy division, already includes this.

[Mads Nipper, executive]

Yes. I think there is -- I'll just say that overall, as I mentioned before, our total exposure is -- volume is that -- our hedge volume is now less, well less than 1 terawatt hour, so a limited exposure. We cannot say that there is no risk, but it's a very limited one. And it's -- and the expectations sort of for what is most likely to happen is included in the guidance that we have for the year.

[Daniel Lerup, executive]

And the full cost of buying back the hedges that we've bought back so far to bring it down below the 1 terawatt hours is all included in Q1.

[Operator]

And our next question comes from the line of Robert Pulleyn at Morgan Stanley.

[Robert Pulleyn, analyst]

May I shift gears to Hornsea 2, which was touched on, but could we ask for a little bit more color? So obviously, you've had an additional delay and also some more buyback. Could we just assess the risk of further delays from here? The slide still says 1H '22 and the risk of further hedging losses. Or do you think we now put this issue behind us?

[Daniel Lerup, executive]

Yes. So our expectation right now is that we will COD over the summer. So it's not in H1. And we have included all the cost of that delay from buying back hedges into Q1.

And when it comes to the risk on the COD timing, we've put in our best view on expected COD, but there is, of course, always uncertainties on big construction projects like this.

[Mads Nipper, executive]

Yes. And if I can just supplement, Daniel. I think we -- as of today, we actually have 69 turbines that are fully operational and producing. So that means that also now, we are getting into a period where the winds are lower, we are getting experience with our partner of how to fix the challenges that we ran into. So we are -- without being able to guarantee anything, obviously, we are confident that the latest estimate of the schedule is something we can keep.

[Robert Pulleyn, analyst]

If I can just ask a follow-up and be a bit cheeky. You mentioned the Poland seabed auction. Would you be willing to give a quantum of how expensive the seabed or how the bids in seabed for Poland compared to what we've been seeing in the U.K. and the U.S. broadly? I'm sure, of course, but that would be most helpful.

[Daniel Lerup, executive]

Yes. So there is no significant cost associated with the seabed applications in Poland. So it's a matter of qualitative criteria as we are used to see in other markets.

[Operator]

Our next question comes from the line of Dominic Nash with Barclays.

[Dominic Nash, analyst]

The question for me, please, is a clarity question on the scope for further upgrades of European offshore wind by sort of 2030, 2035. I think on your slide, you said there's 30 GW upgrade. When I saw just how big it was to the countries listed, I think it's about 35. So if you could sort of disclose to which countries target upgrades are in that 30 GW already, which ones are out. But the real question is if you have decided to go to more -- almost like a war footing to get energy security of supply, and France and Germany actually decide to really go for it, what do you think? And when do we start to get the dates coming out for what we could get on the increasing GW of offshore wind in order to sort of wean off sort of gas generation?

[Mads Nipper, executive]

Yes. It's -- I honestly -- the clarifying question, I don't know if we can say, we are -- yes, these 30 GW that we have for 2030 and the additional for between 2030 and 2035 is our view. So what we referenced with the 2030 targets is actually what has already been confirmed. And we actually believe that those 30 plus 30 that you see on Slide 4 is additional for Europe on top of that. So just to clarify, so those numbers do not reconcile if you try to add up that additional. Sorry if that created a confusion.

So essentially, the answer to your second question is that we believe that the green parts, so the 30 plus 30, is what can be additional, additionally realized if the government really want to go for this in terms of seabed allocation and consenting processes. So that, I guess, sort of merges your clarifying question with what we believe could actually be achieved.

[Dominic Nash, analyst]

If I may just comment here. It doesn't feel that ambitious. I mean if ScotWind itself can come up with 25 GW, what stops France from saying actually we're going to build another 25 GW with Germany? It doesn't really feel these numbers are going to really move the dial on energy substitution.

[Mads Nipper, executive]

No. It is obviously -- and that's also why it's a good -- we actually think that this will be very ambitious, to be honest, compared to the traction we have right now. We would love to see even more speed. But we think this is an ambitious, very ambitious target and is something that would take significant on-top volume compared to the official targets. And I'm sure governments around Europe sit and say that especially the 2030 targets are now very ambitious.

So I would say I fully agree with you that ScotWind is very encouraging. But it's also very clear that, by far, the majority, if not all of that, is only going to be COD-ed after 2030. So we believe that we would still uphold the perspective that if we take the 170 plus or the current targets plus the 30 additional that we think are possible, that would be something which would be great for the industry and great for the transformation. But we would love to see more, but that we think would probably not be realistic.

[Operator]

And our next question comes from the line of Alberto Gandolfi of Goldman Sachs.

[Alberto Gandolfi, analyst]

I'll try to push it to 1.5 questions, if you don't mind. The first one is on guidance. Is there a particular reason why you've not made a bit of more of a narrower, let's say, a more granular comments on your full year guidance? I don't know, being closer to the top end or upside risk to it, because you've already delivered DKK 9.4 billion, and you've already taken quite a lot -- I mean, I know there was a reversal in provision. But you had like unwinding of hedges on Hornsea 2, the renegotiation of potentially -- well, interruption impacts from Gazprom procurement. So I wonder what could be further contingencies for the rest of the year other than perhaps wind speed or load factors?

You're going to get Hornsea 2. So you've been delivering DKK 11 billion to DKK 12 billion of EBITDA in 2Q, 3Q, 4Q both in 2020, '21 before gains. So shouldn't we be comfortably breathing through your guidance on the back of that? Or what am I missing? What could go wrong that prevented you from revising it?

The harder question is something you've already been asked before. But can you maybe give us a comment here on why you chose 20% for potential flexibility to raise capital and not 10% like most of the other companies do in the industry? Why did you choose to deviate and to have a much higher flexibility? Is there something on your mind? Or is it pure flexibility, period?

[Daniel Lerup, executive]

Yes. Thank you. I'll cover the first question, and then Mads can cover the second question. On the guidance, remember that excluding new partnerships, so the number for Q1 is DKK 7.8 billion. And our thinking here is that we have already, going into 2022, extended our guided range from an interval of DKK 1 billion to DKK 2 billion. And we are still early in the year.

When it comes to some of the uncertainty, it is, of course, the fact that we are delivering 2 big projects in 2022, so both Greater Changhua 1 & 2a and also Hornsea 2. So I think there, you, of course, have some uncertainty. And then, of course, the Gazprom situation and the volatile power and gas prices.

[Mads Nipper, executive]

Yes. And then I will just comment on the 20% ABB that we decided to ask for and got approved by the AGM. This is not driven, Alberto, by any specific opportunity. But we are seeing, referencing also the question from Dominic before, is that there are just significant opportunities. And also with an emerging Power-to-X market now, really, we believe, really starting to take shape, it is simply to have the ability and the agility to pursue, sort of, any opportunities that might come up, whether that is further European or global offshore acceleration, whether it's Power-to-X or potential further expansion of onshore in Europe as well.

So it's simply to have the firepower to be able to do that. So 20 years -- or 20% over 5 years, we believe, is right with what we could imagine without having any specific plan for the time being.

[Operator]

And our next question comes from the line of Jenny Ping at Citi.

[Jenny Ping, analyst]

Two questions, please. Firstly, one for Mads. Just going back to the input cost comments you made. You talked about 20% outstanding for the U.S. Can you just give us a sense of what of that 20% is still remaining? Is it vessel costs mostly? Is it steel? What aspects of the CapEx?

And I guess linked to that is, what is the percentage you've hedged effectively for the Taiwan and the Poland projects as well?

And then one for Daniel. You talked about the magnitude of starting to see some sense of corporate PPA prices going up. Can you give us a sense of the magnitude of the increases? EDPR have said sort of EUR 3 to EUR 5 per MW hour increments. Can you give us a sense in equivalent terms?

[Mads Nipper, executive]

Yes. Thanks, Jenny. I will say that we -- at our last earnings call, we said that around 80% were locked on the Northeast program and on Ocean Wind, so our nearer-term U.S. projects. That is now above 80%. So we have progressed further. And I mean, I can't go into details of it, but it is -- of what is still outstanding, it is still, to a large extent, within transport and installation that we are missing. We have locked some, but that is still the primary outstanding and less so on commodities.

And on Taiwan and Poland, so some of the next ones in line, we are -- they are further out. And generally, we are not very locked in on those, very little. So that is something which we are working on for the time that we will have available to ensure that we start locking those contracts when that is right.

[Daniel Lerup, executive]

Yes. And on the corporate PPAs, I can't get too specific here, but I would say it's very much in line with the Iberdrola comment, and we're also seeing PPA price increases above that level. And then another data point we've also given was that on the German projects that we have ID-ed late last year, we saw cost increases from the inflationary pressure on CapEx of roughly 5% and we were able to cover that with increased PPA prices.

[Jenny Ping, analyst]

Sorry. Just to be clear, what was the Iberdrola comment?

[Daniel Lerup, executive]

The EUR 3 to EUR 4 per MW.

[Jenny Ping, analyst]

Oh, I see. Okay, got it. Yes, got it. Yes, the EDP, I said that, yes.

[Daniel Lerup, executive]

Sorry, yes.

[Operator]

And our next question comes from the line of Kristian Johansen of SEB.

[Kristian Tornøe Johansen, analyst]

Just getting back to the Hornsea 2 delay. You mentioned supply chain quality issues playing, installation or commissioning in March and April. Does that relate to turbines then? Or can you elaborate on the root cause of that?

[Mads Nipper, executive]

Yes. I can do that, Kristian. It's -- I mean, essentially, it's the Hornsea 2. This is the latest that is challenged. We have run into a few challenges. First, we saw sort of an engine breakdown of a vessel transporting our substation from Asia, which meant that -- that meant a delay for that to arrive in Europe. Then we had the Omicron outbreak around Christmas, which meant it was very difficult to man the vessels. Then we had a very positive sort of -- something which is very positive for our business, a record February with very high wind speeds which was great for our operational earnings, but that meant we only had 4 working days to be able to commission.

And then latest, we had these challenges. And yes, it is on the turbines. It's an inverter module that needs to be retrofitted, which takes longer time. So that's the sort of the full story on what's happening. But the good thing is we are really picking up speed and we are going into -- just to generally to smoother water, and we know how to fix the issue. So that's -- as I mentioned, we remain reasonably confident that our latest estimate on schedule would hold.

[Operator]

And our next question comes from the line of Sam Arie of UBS.

[Samuel Arie, analyst]

So I'm kind of like way down the order here on questions, so I'm going to disappoint you by kind of coming back to a topic that you're probably tired of after the last 12 months. But can I ask another inflation question? And you made some very helpful comments here on the sort of indexation that you have on the existing assets. But what I think I want to ask, I just want to try to ask you a question in a different way. Could you say with reference to the existing asset portfolio, so I'm not talking about new projects, just existing assets, if you think at the bottom line, you are actually short or possibly long inflation overall?

And the reason I ask is that, I mean, everybody seems to think that you're actually a little bit short inflation and it's a big negative. But I'm thinking if you have like a 7% inflation level coming into revenue, even if it's only for the sort of 60% of assets which are mechanically indexed, actually, if your own inflation level, in your own kind of operating cost is less than 60% of what inflation is in the rest of the economy, then you might actually be long inflation on the existing assets.

So I'd just love to hear your comments around that and whether that's actually something a bit better than people expected in this topic.

[Mads Nipper, executive]

Okay. I'm sure Daniel is better at quick math in his head than I am, but I'll comment on it saying that at least the inflation index revenue that we have, so the 55% of our existing fleet, that is -- that -- if you put it roughly sort of 2 percentage points inflation gives sort of between DKK 200 million to DKK 300 million of additional revenue a year. So this is something that sustains.

You can sort of make the calculation saying what other operational inflation do we have to have been able to neutralize that. But generally, I would say that this is something that we've not talked that much about previously. But in an inflationary environment where we have it right now, it's significant and something that we would -- that certainly counts, especially if it's sustained for a longer period of time. But I don't know if you have any further comments to the operational inflation, Daniel?

[Daniel Lerup, executive]

Yes. I just -- it helps quite a bit to have these inflation-linked contracts in the U.K., and that gives us a good exposure on the existing projects. So that's, of course, a long position. But it is, of course, difficult to say how is the cost side on CapEx going to look like in the future. We don't know that yet. But on the existing project, the operational projects, it's a positive.

[Samuel Arie, analyst]

So you think you continue to have...

[Mads Nipper, executive]

And we would see...

[Samuel Arie, analyst]

Sorry, go ahead.

[Mads Nipper, executive]

No. Sam, maybe if I understood your question, otherwise shut us up. But if I understood your question is that if we purely look at our operational fleet, so will the additional revenue actually make us long on inflation, on the -- for example, on the cost inflation on salaries and fuel for the operation of the wind farms, was that your question?

[Samuel Arie, analyst]

Yes, exactly. So the full inflation indexation on the part of the fleet might be worth more to you than the actual inflation you're getting on all of your activities, in all of your existing asset activities.

[Mads Nipper, executive]

Yes. I think a good guess of that, we haven't calculated, but a good guess on that will probably be above neutral because we would typically see that salary inflation sort of has a lag behind. So that if there's high inflation, the net salary increases in most places would actually be below that, whereas it's the opposite with the other way around. But given the 55% coverage, I think we would refrain from saying whether we'd be a little bit long or short on inflation. But it's not a massive impact if you only look at our existing fleet would be sort of a high-level estimate. But it's a good question. We should pressure test it.

[Operator]

And our next question comes from the line of Ruisi Liu of Crédit Suisse.

[Ruisi Liu, analyst]

Just a quick follow-up to the cost inflation question that was asked earlier. Are you able to say what you're seeing in your latest negotiation with suppliers in terms of cost cutting through? And are you seeing any unexpected cost in the pipeline?

And I guess, if I can, just a quick clarification. Did you say that for all the Hornsea 2 delays, there will be no further financial impact down the road in the quarters to come for this year?

[Mads Nipper, executive]

Yes. I don't think we can comment specifically on the pass-through. But I would say that what has been -- I mean, what we previously said has been locked in, we don't expect any pass-throughs on any of those contracts. So our exposure still sits in what is still being -- what is still open and what is not signed contracts. It's very mixed for some categories that it's a high inflation, for others, it's lower. But on -- again, on [ T&I ], we are still in tough negotiations and I can't reference the specific inflation levels. I don't think -- I'm looking also at you, Daniel. I don't think we've seen any cost increases due to the Hornsea 2 delay.

[Daniel Lerup, executive]

No. So all of that has been locked in. So that's more of the upside on the CfDs.

[Operator]

And our next question comes from the line of Peter Bisztyga of Bank of America.

[Peter Bisztyga, analyst]

So I just wanted to come back on those 2030 targets, please. We've got 7.5 years really to go, which actually seems quite tight given historic lead times. So can you talk to us a little bit about when the first of this new batch of projects could realistically come on? I mean are we talking 2027, are we talking December 2029?

And what are the key sort of bottlenecks? What are the sort of biggest things that really need to be overcome to try and get those over the line? Is it about policy and planning? Or is it actually about supply chain and vessel availability? So any further color would be much appreciated.

[Mads Nipper, executive]

Yes. I think on the timing, Peter -- and we agree that it is actually quite ambitious. You're saying that it's 7.5 years and it takes time to build. And for -- even though many countries are saying they want to speed up the consenting process, that also takes time.

So I wouldn't say that it's more towards 2027 and 2029. But I think we will see a gradual acceleration and a hockey stick towards end of the decade. But we are, as I mentioned to a previous question, we are relatively convinced that the visibility of the additional opportunities will be -- will clearly be there in the next 12 to 18 months, which would -- at which time, we would get much greater clarity.

Key bottlenecks, and I'm sorry if I'm repeating something we said in previous calls as well, it is to make affordable seabed available and to have predictable and swift consenting processes. There is no doubt that there are other -- there are also potential supply chain bottlenecks. But we actually think that the biggest bottleneck that needs to be overcome is seabed and consenting and affordable seabed, not least.

[Peter Bisztyga, analyst]

Okay. And if I could also be cheeky and ask a quick follow-up question. Any more details on that turbine, Anholt, sort of fell off? Is that definitely just a specific problem with that turbine? Or is there any kind of risk of a [ type here ]?

[Mads Nipper, executive]

Yes. Thank you. Trust me, we talked a lot about that. And I'm happy to say that because we got full availability of the entire data set, operational data set from the entire fleet and turbines, of similar turbines, this is the 3.6-megawatt, sort of, workhorse turbine. And initially, we actually made a no-sail zone around all of them to ensure that there was sort of not a systemic fault. But we were able literally in days to make sort of a very, very detailed and advanced analysis of the high-resolution data we got, and we were able to detect a very clear anomaly from this particular turbine. And we see no similar signs from anyone else. So we lifted the no-sail zone. And we believe that this was a manufacturing mistake at this individual turbine at the -- from when we -- at the shaft, so it was -- or the rotor, so it was made. And we don't have any reason to believe this is a systemic mistake.

[Operator]

Our next question comes from the line of David Paz at Wolfe Research.

[David Paz, analyst]

Great. I just had a question on your comment you made about the Northeast -- I think it was the U.S. Northeast projects, so maybe it was just U.S. offshore wind projects generally. But you said that you still see them value creating. I just wanted to get a sense of has that shifted since your last update in terms of have you seen incremental cost pressures that have made it less value -- I understand still value creation, but less of value creating than before? And if so, what are those costs? What specifically are the rising costs that you're seeing?

[Mads Nipper, executive]

No. Thanks, David. I know it's -- the picture is the same as we referenced last time. So we're saying that even though there's an inflationary pressure, we still see these as NPV-positive projects, so the entirety of the U.S. near-term projects. And the reason why that is still the case is because we -- when we made that assessment, we already put in sort of a relatively -- I wouldn't say conservative, but at least a quite aggressive picture on the inflation.

So we are seeing the same picture as we talked about last time. Also because a large share of steel has already been locked in, and steel is a commodity that has grown the very most due to the Russian inflation -- of the Russian invasion of Ukraine. And that means that we are roughly still on the expectations we had when we assessed the value creation last time we talked about this topic.

[David Paz, analyst]

Okay. And that includes the U.S. Northeast as well as Ocean Wind? Or is that -- are you specifically speaking about the Northeast part?

[Mads Nipper, executive]

Yes. Sorry about that. I was including both. For South Fork, we FID-ed that, so that's fully locked in. So when I was mentioning these, I was referencing both Revolution, Sunrise and Ocean Wind 1.

[David Paz, analyst]

Got it. Great. And if I can sneak in just one quick question on the solar -- U.S. solar outlook given the DOC investigation. How is that impacting your strategic outlook? I know over your target, your longer-term target, you were tilting more towards solar at CMD last year than wind. Is that still the case? Is the split still the same? Are you now weighing maybe more wind than solar?

[Mads Nipper, executive]

Yes. We are still assessing the same split. And the reason for that is because we were very happy even before this latest case come up to be able to lock this frame agreement with First Solar, which does not use polysilicon and, therefore, have none of these human rights issues. And that means that for the next few years, at which time we are hopeful and believe that the other challenges have been solved, we have 1.7 GW of capacity that we are certain that we can continue to push on the solar projects on.

So at this stage, we estimate that the only impact we are going to see from these issues that we currently see is the delay that we're anticipating on Old 300 and the solar part of Helena Energy Center. Otherwise, we feel in good shape to keep traction on our solar ambitions.

[Operator]

And our next question comes from the line of Vincent Ayral of JPMorgan. It seems Vincent has disconnected, so the next person in the queue is Sam Arie from UBS.

[Samuel Arie, analyst]

I had a second question, which I just want to take the opportunity to ask. And Mads, this is probably one for you. And stepping back now away from your own results and just thinking about the bigger energy market situation that we're in. Across Europe, obviously, we've got concern about rising prices and bills for power users.

There's obviously a theme about building more renewables to bring prices down over time, but that's going to take a long time, my hope over 5 or 10 years, but not over 5 or 6 months. So I'm just wondering if you could share with us what your perspective is in general on the European energy affordability process. And what kind of short-run measures Ørsted would be supportive of for managing bill impacts this year rather than further out?

[Mads Nipper, executive]

Yes. So if you're talking specifically, Sam, about the power prices, then obviously, we are looking at quite extreme pricing right now. We don't think that sort of -- this is sort of going to something that will be -- that will sustain long term, but we are seeing the elevated power prices. And we actually think that the LCOE is short to midterm is going to go up as well.

Long term, we still believe that, that curve will go down because we don't think that the cost pressure will sustain at this level long term. And we also think that there is plenty of technological opportunity to continue to push to long term break that curve. But I think the short term, what we can do is to continue to leverage scale, leverage capability.

And then to a question that was asked before as well, when we talk about the regulatory regimes, to ensure that whatever happens is financially sustainable as well, even short term. Because with the pressures we see, not just on power but in general, it is necessary that those prices are also reflected into the PPAs, not just with corporates but also with governments. I'm unsure if I'm getting the gist of your question. Otherwise, try to ask it in different ways.

[Samuel Arie, analyst]

Yes. Can I try again? Because I guess what I'm saying is a lot of governments are wrestling with the fact that people's bills are going up and cost of companies are going up. And of course, you guys have the key to a long-term solution in terms of building more low-cost renewables.

I'm just wondering what you would do if you were the Minister of Energy in a major European country right now and you needed to do something fast and quick to help people get through these short-term impacts. And of course, I'd love to talk about windfall taxes, about caps as the Iberdrola and Enel and EDF letter, which argues for a cap on gas prices as the kind of development in Spain and Portugal on gas price. I'm just wondering what you guys would advocate. What would you support for a short-term measure?

[Mads Nipper, executive]

Yes. At least one of the last things we would advocate would be to have a windfall tax. And that is not because we, as a company, would be particularly exposed to that. But fundamentally, we think that a windfall tax on energy generation would be something that would risk halting investments into a necessary green transformation. So that would be clearly something we would not be recommending. I think the path that several governments are going down is to have some kind of support bill for the energy consumers, which also Denmark has ensured. There is some kind of support short term to cover those quite extreme energy bills. So I would say, I mean, a price cap on gas is certainly an opportunity. But again, the strong stand we would take, it would not to go down the route of a windfall tax.

[Samuel Arie, analyst]

Okay. That's interesting. So you would be supportive of the sort of Spanish gas cap if it was proposed to expand that to the rest of Europe?

[Mads Nipper, executive]

I would not be that specific. But I think I would -- I think it is not a bad idea to institutionalize measures that ensures that the short-term extreme pricing is somehow manageable for consumers. And we don't think that the way to do it is to tax anyone. It would be better to potentially control prices.

[Operator]

And our final question comes from the line of Vincent Ayral of JPMorgan.

[Vincent Ayral, analyst]

Apologies. I did drop the line a few minutes ago. So actually, a quick follow-up on the one before, but not looking short term but rather long term. How do you look at European power market design with a highly volatile merit order and the consequences we are having, potentially having to manage if I quote you, "short-term extreme pricing"? Would it be better to have a market design more along the lines of what you're doing in offshore on the CfDs and et cetera, something which is, I would say, almost a bit more regulated?

And the second one was basically on the gas storage. I was thinking about that a bit earlier regarding the uncertainties for the rest of the year. You have booked in Q1 probably a fair amount on the gas storage revaluation. How much was it? And is this one of the areas where actually you'd rather be cautious in why you did not increase the guidance?

[Mads Nipper, executive]

Yes. It's -- they are -- the first one is a really, really big question. And I think, generally, the current power market design, we are, like the rest of the members of Eurelectric, we are generally advocating that fundamentally that design, market design is not bad. So even though, obviously there will be a time to reevaluate sort of what is the fundamental market design, we actually -- our opinion has been and we have been sort of solidaric with the views of Eurelectric is it is more important to continue to implement that design across Europe than it would be to make a fundamental redesign of that market dynamic. That is what we generally think is the healthiest for the power market.

Can that change over the years? Yes, it likely can as we will be less dependent on fossil fuels. But sort of midterm, we still think that is a good design. I simply don't have a perspective on -- Daniel, do we have a perspective on the gas storage?

[Daniel Lerup, executive]

Yes. Yes. So the gas markets and infrastructure is up with a little more than DKK 700 million here in Q1 compared to last year. And a large part of that is driven by the revaluation of gas in storage. So this is where we have a more temporary effect that can go down.

[Operator]

And as there are no further questions at this time, I'll hand the floor back to our speakers for the closing comments.

[Mads Nipper, executive]

Yes. And we will just once again thank you very much for your great questions. Appreciate that. And should you have any further questions, as always, our IR team, us and the team, are happy to answer them. So thank you very much. Stay safe, and have a great day.