Welcome to this Oresend Q2 2019 Earnings Call. For the first part of this call, all participants will be in listen only mode and afterwards, there will be a question and answer session. Today's speakers are the CEO, Henrik Fulson and the CFO, Marianne Windholt. Speakers, please begin.
Thank you, and good afternoon, everyone, and welcome to this first half earnings call. Our company continued its strong performance in the Q2, with results in line with expectations and quite notably, also the award of 2 major U. S. Offshore wind projects. Our EBITDA for the Q2 of the year amounted to DKK3.6 billion, which is an increase of DKK0.5 billion compared to last year.
The increase in EBITDA was mainly driven by our offshore wind farms in operation, where we saw a year on year increase of 29%, driven by ramp up in generation from Borkum Refgren 2 in Germany and Wolnew extension and Hornsea 1 in the UK. We're quite satisfied with our financial performance, which puts us well on track to deliver on our full year guidance. Relative to our expectations at the beginning of the year, we have, as always, seen some underlying ups and downs. On the negative side, we are, despite the very significant growth, not fully satisfied with our production in the first half year, where the number of outages and curtailments across the offshore wind portfolio has been higher than normal. We estimate that these issues in total have resulted in an uncompensated production shortfall of roughly 3 50 gigawatt hours on a year to date basis, equivalent to roughly DKK400 1,000,000 in operating profits.
We would, under normal circumstances, expect the uncompensated production loss to be less than half of that. We expect these issues to persist into the Q3 of this year. On the positive side, we've seen higher earnings from partnerships than originally expected, which Mariano will come back to. And we have also seen stronger than expected earnings from trading related to hedging of our energy exposures and also strong margins in our gas portfolio. With the continued ramp up in our offshore and onshore wind capacity, our green share of heat and power generation increased to 85% in the 2nd quarter, up from 80% in Q2 last year.
As you know by now, in June, we were selected as the preferred bidder for New Jersey's 1st offshore wind farm with our 1100 Megawatt Ocean Wind. And in July, we were selected as 1 of the 2 preferred bidders in the New York solicitation with the 8 80 Megawatt Sunrise Wind Project, which we own in a joint venture with Eversource. We are obviously very pleased with these awards, which I will discuss in more detail in a few moments. During the quarter, we also received the outcome of offshore wind tenders in France and the Netherlands. These tenders were awarded to an EDF Energy Enbridge joint venture and Wattenfall, respectively.
At the end of July, we commissioned the Locket Onshore Wind Farm in Texas well ahead of schedule. The 184 Megawatt Onshore Wind Farm in the Urquhart region has performed as expected since the commissioning, and we are quite pleased with the Onshore team's strong EPC performance on Locket. In May, we completed the largest green bond offering to date when we successfully secured a funding of €900,000,000 The proceeds from the green bonds are earmarked for offshore wind activities in the U. K. And will also provide a natural hedge towards our significant pound sterling NT25 billion for our offshore wind $25,000,000,000 for our offshore wind projects in Taiwan.
We're also very pleased with the commitment from 15 banks on this transaction, including the domestic Taiwanese banks. We are proud of this being the first ever green loan facility in Taiwan, and we will now start preparations for a potential green bond issuance in the local Taiwanese market towards the end of this year. In May, the Copenhagen Maritime and Commercial Court ruled in favor of Orsted in the case concerning the use of the Orsted name, with a clear vote of 5 to 0. We are satisfied that this judgment upholds our claim that we have the right to use the name. In June, the plaintiffs decided to appeal the case, and it is currently being assessed whether the appeal will be heard at the High Court or whether it will go directly to the Supreme Court.
In June, we decided to consolidate the business units, Customer Solutions and Bioenergy into a new business unit named Markets and Bioenergy. The decision was taken as a natural consequence of the 2 existing business units being reduced in size. The downsizing is driven by the plant divestment of our Danish power distribution, residential customer and city light businesses and also divestments of our oil and gas infrastructure assets as well as activities that have been either discontinued or transferred to other parts of Orsted. The financial consolidation of the 2 business units into 1 will be reflected in our interim financial report for the 1st 9 months of 2019. Morten Buchreits, who was previously EVP of Customer Solutions, has been appointed EVP of Markets and Bioenergy.
Within Markets and Bioenergy, we continue to prepare our power distribution, residential cost and city light businesses for separation and subsequent divestment. We still believe signing our combined transaction or separate transactions can be achieved before the end of the year. At this point, we cannot provide further details on the process, but we will, of course, be actively pursuing the divestments during second half of this year. Turning to Slide 4, where I will focus on the outcome of the solicitations in New Jersey and New York. As mentioned in June, the New York sorry, the New Jersey Board of Public Utilities as the preferred bidder for New Jersey's 1st offshore wind farm.
We are very excited with the award and look forward to delivering the first offshore wind farm in the U. S. Above the 1 gigawatt mark, as well as contributing to meet Governor Murphy's ambitious renewable energy goals. We will now negotiate the final terms of the 20 year offshore wind renewable energy certificate. The project will receive $98.1 per megawatt hour from 2024, with a 2% annual escalator corresponding to a levelized 2013 price of $86.4 per megawatt hour.
Subject to final investment decision, the 1100 Megawatt wind farm is expected to be completed by 2024. We will work with the non utility affiliates of PSEG, who will provide energy management services and potential lease of land for use in the project development and execution phase. Furthermore, PSEG has an option to become an equity investor of up to 50%. We are proceeding with plans to establish an operation and maintenance base in Atlantic City that will provide permanent high skilled jobs during the lifespan of the project. In July, the New York State Energy Research and Development Authority, NYSERDA, selected the Project Sunrise Wind as one of the preferred bidders in the offshore wind procurement of 1.7 gigawatt.
The other award went to Equinor's Project Empire Wind. We will now negotiate a 25 year offshore wind renewable energy certificate for the 8 80 Megawatt project, which will contribute significantly to achieving Governor Cuomo's ambitious goal for New York's transition to renewable energy. Sunrise Wind is a fifty-fifty joint venture with Eversource, and the project is exploring transmission partnerships with the New York Power Authority and the leading New York utility, Con Edison. We will apply a cluster approach to our Northeast projects, comprising South Fork, Sunrise Wind and Revolution Wind. The cluster will have a total capacity of 1.7 gigawatt to be built between 2022 2024.
Less than a year ago, we created the leading U. S. Offshore wind platform by merging the asset portfolios and competences of Deepwater Wind and Orsted U. S. Our recent significant project wins in New Jersey and New York are proof of the strength and quality of the combined organization.
With the recent allocation of almost 2 gigawatt, we have secured an offshore wind build out portfolio on the U. S. East Coast of approximately 2.9 gigawatt to be completed between 'twenty two and 'twenty four. The significant pipeline will enable us to optimize EPC and operations across the portfolio as well as inside the clusters. In addition to the awarded capacity, we have around 5 gigawatt of lease rights on the U.
S. East Coast, which can be developed for the many upcoming auctions. The awards have significantly reinforced our leadership position in U. S. Offshore wind, we are well on track to reach our ambition of 15 gigawatt offshore wind capacity by 2025 as we continue to innovate and pioneer the global offshore wind industry.
Turning to Slide 5, where I'll give an update on the key offshore construction projects in progress. At Hornsea 1, the construction progress is well on track. We have installed all foundations and array cables as well as 131 out of the 174 turbines. With the current progress, we expect the wind farm to be fully operational in Q4 this year. At our Borsalei 1 and 2 wind farm, the construction of the O and M building in Flissingen is progressing according to plan.
We still expect the Dutch wind farm to be completed in late 2020 or early 2021. The Virginia EPC demo project is also well in progress. The onshore construction has commenced, while the offshore construction work is scheduled to begin in Q2 next year. We now expect to complete the 2 pilot project by the end of 2020. At the Hornsea 2 project, we have signed all key supplier and installation contracts, and we continue the onshore construction work on the substation and export cable.
The project is scheduled for completion in the first half of 2022. At our Greater Changwa 1 and 2A project in Taiwan, we continue our efforts to sign the remaining supply and installation contracts. We have started the onshore construction work and remain on schedule to complete our 1st large scale offshore wind farm in Asia by 2022. At the same time, we've seen good progress at the 120 Megawatt Formosa 1 Phase 2 joint venture project. The onshore construction work is progressing according to plan, and in May, the offshore installation work commenced.
By the end of July, the first turbine was installed, and we expect the wind farm to be fully commissioned towards the end of this year. Now turning to Slide 6 and an update on the construction projects outside offshore. In our Onshore business, we continue to see good on our construction projects. In July, we commissioned the Locket Onshore Wind Farm in Texas well ahead of schedule. And in the subsequent period, we've seen very good performance from the wind farm.
In June, the construction work at Sage Draw commenced with road and foundation installation well underway. We expect the 338 Megawatt wind farm in the Texas Urquhart region to be commissioned by Q1 next year. In June, we acquired the 103 Megawatt construction ready onshore project Willow Creek. The project is located in South Dakota, and together with our Plum Creek development project in Nebraska, the acquisition further expands our operations into the Southwest Power Pool market. Construction of the wind farm commenced in the beginning of July, and we expect the wind farm to be commissioned by the end of 2020.
In Bioenergy, the bioconversion of the Astnus power station is progressing according to plan. The first shipment of wood chips has arrived, and the project team is currently preparing to fire up the boilers with wood chips for the first time. We still expect final commissioning towards the end of 2019. At our last remaining coal fired CHP, Espia Power Station, we have not been able to find a joint solution with the heat customers for a bioconversion project. Consequently, we informed the heat customers that we will close down operations by the end of 2022.
We applied to shut down the plant to the relevant authorities, and the Danish Energy Agency has issued a draft ruling granting us permission to close down the power station by the end of 2022. The draft ruling has been in consultation with the parties, and we are currently awaiting the final ruling from the authorities. The reconfiguration of our Renaissance plant in the UK has been completed, and we are now in the process of ramping up the waste throughput as well as production. We now expect to commission the plant at the end of this year. We continue the installation of smart meters within our power distribution network.
At the end of June, 900 and 76,000 smart meters had been installed and taken into use. We expect to install the last smart meters during Q3 this year and including the subsequent testing and period of commissioning, the project remains well on track to be finalized on schedule in 2020. Let's turn to Slides 7, 89 and take a look at the latest market development and offshore wind opportunities across the regions. Starting in Massachusetts, where the state's 2nd offshore wind solicitation has been launched. Bidders will have to submit their bids by 23rd August this year, with expected selection of projects for negotiation in November this year.
Bidders can submit proposals ranging between 208 100 Megawatt. As part of the updated framework in Massachusetts, the price cap for the 2nd solicitation has been removed. Recently, Massachusetts passed a new bill with an ambition of 3.2 gigawatt offshore wind by 2,030, 5 years ahead of the previous target. With the total award of 1.7 gigawatt to Sunrise Wind and Empire Wind, New York has taken a significant step towards their 2,035 target of 9 gigawatt offshore wind. We expect that the next auction will take place in second half of twenty twenty.
Furthermore, we expect the federal agency BOEM to release 2 New York Offshore Lease Areas of at least 800 Megawatt each in early 2020, with a lease auction likely to take place later in 2020. In New Jersey, the recent 1.1 gigawatt award was the first step towards the state's 2,030 target of 3.5 gigawatt of offshore wind. New Jersey is expected to have subsequent auctions of 1.2 gigawatt of offshore wind in both 20202022. Moving to Connecticut, where the state approved the legislation for the procurement of an additional 2 gigawatt of offshore wind. The next procurement is expected to be for 400 to 800 megawatt of offshore wind with a bid deadline on September 30 this year and an expected outcome announced in November.
In Rhode Island, the 400 Megawatt PPA for our Revolution Wind project has been approved by regulators, and we continue the development of the full Revolution Wind Project. National Grid has made a conditional selection of the preferred bidders in the 2018 0 Carbon RFP. Selected bidders have been notified and additional details will be updated upon successful contract negotiations. We can conclude that National Grid did not select any offshore wind projects for this procurement. Finally, Maryland has confirmed the state's target of approximately 1.6 gigawatt of offshore wind capacity by 2,030, an increase of 1.2 gigawatt compared to the previous bill.
Maryland is expected to have auctions of at least 400 megawatt of offshore wind in both 2020, 2021 and 2022. We continue to see a strong development within offshore wind on the U. S. East Coast, with several ongoing and upcoming solicitations, expected lease area auctions as well as increased commitments to the long term build out of offshore wind. Turning to Slide 8 and the recent market developments in Europe.
In the U. K, the 3rd CFD bid window is now closed, and an outcome is expected to be announced during September this year. As we did not participate in the auction, we're looking In Germany, the German Federal Ministry For Economic Affairs has recently suggested to increase the current 15 gigawatt target for 2,030 to 20 gigawatt. We expect Germany to launch the 1st centralized tender in 2021 with the aim of having 800 megawatt constructed annually from 2026 onwards. Moving to the Netherlands, where the 4th offshore wind tender was concluded in the beginning of July.
Even though we were not successful in the tender, we are still committed to contribute to the green transition through green hydrogen projects in the Netherlands and elsewhere, as we see offshore wind based hydrogen as a cornerstone in the continued decarbonization of our core markets. The Dutch government has set an ambitious target of 11.5 gigawatt of offshore wind by 2,030, and we expect the next tender of up to 7 60 megawatt to take place early next year. In France, the 3rd offshore wind tender was concluded in June. We were not successful in the tender, but we are pleased that the French government increased their offshore wind target from 5 gigawatt to 10 gigawatt by 2028 in connection with the outcome of the 3rd auction. Finally, turning to Slide 9 and the market development in Asia Pacific.
In Taiwan, auctions for an additional 4.5 gigawatt to be built post 2025 is being planned. The framework around these auctions are not yet in place, but we expect that the auction design for the 3rd round development will be announced during Q4 this year. In Japan, the government recently designated 11 areas as potentially suitable for the development of offshore wind farms. And these areas will progress to the preparatory stages for designation of future promotion. 4 of these 11 areas will immediately undergo preparations for wind and geological surveys.
One of those four areas is the Choshi Zone, which is currently being developed by TEPCO and is the subject of a memorandum of understanding with with the aim to jointly develop the project within this zone. The Ministry of Economy, Trade and Industry in Japan is pursuing a targeted time line for a first auction round to take place in summer 2020. In South Korea, we continue to closely monitor the regulatory development of offshore wind. This concludes the Offshore Market Development review. Now let's turn to Slide 10 and the progress of our U.
S. Onshore business. The U. S. Onshore business continues to expand its portfolio of operating and development projects.
With the recent commissioning of the Locket Wind Farm, our operating portfolio of onshore wind farms reached 1 gigawatt. Furthermore, the recent acquisition of Willow Creek expands the geographic footprint of our asset base and increases our portfolio projects towards 2022. The integration of the newly acquired solar and storage development activities of Coronal Energy into our U. S. Onshore organization is progressing according to plan, and we remain very satisfied with the development of our onshore business and the value creating growth opportunities it continues to offer.
We will continue to expand our development portfolio and capabilities to create a leading North American platform within onshore wind solar energy and energy storage. Now moving to Slide 11. Over the past decade, we have, at Orsted, undertaken one of the most ambitious green transformations in the global energy industry, guided by our vision of creating a world that runs entirely on green energy and our strong commitment to the Paris Agreement and the United Nations Sustainable Development Goals. By the end of first half twenty nineteen, we have reduced the carbon emission intensity from our own energy generation by 83% through the conversion of our CHP plants to sustainable biomass and the deployment of offshore and onshore wind. Our target, which we are fully on track to meet, is to reach a 98% reduction of the carbon emissions by 2025, making our energy generation essentially carbon free.
In addition to our comprehensive transformation from black to green energy, we're taking a number of carbon reduction initiatives in our own operations, including a new target to phase out fossil fuel cars from our company car fleet and fully convert to electric vehicles by 2025. With our energy generation and other in house operational activities well on track to become virtually carbon free, we now take the next major step in our decarbonization strategy. And today, we announced a new target that covers the indirect carbon emissions related to our business. By 2,032, we want to reduce our so called Scope 3 emissions by 50% compared to the 2018 baseline. These carbon emissions primarily relate to the sale of natural gas and fossil based power in our customer businesses and from the goods and services we source for construction of wind farms.
To meet the target, we will gradually reduce our natural gas sourcing portfolios, which today make up more than 80% of our total Scope 3 emissions. The gradual reduction in our gas sourcing and corresponding sales over the coming decade reflects our view that natural gas will continue to play an important role in the transition towards a society fully powered by green energy. But over time, it must be replaced by renewable energy sources. Furthermore, we will reinforce our ongoing engagement with our suppliers to reduce the emissions from the goods and services we source, in particular, related to the construction of our wind farms, which make up the largest emission source in our supply chain. On that note, I will now pass on the word to Marianne.
Thank you, Henrik, and good afternoon from me also. Let's start on Slide 12, where I will go through the group's financials for Q2 2019. In Q2, we realized an EBITDA of DKK3.6 billion, a year on year increase of DKK500,000,000 in line with our expectations. In Offshore, earnings from our operating wind farms increased by 29% due to the ramp up of generation from Borkum Rivkon II, Walnew Extension and Hornsea 1. Furthermore, wind speeds in Q2 2019 were above last year.
In Q2 'nineteen, we had lower than expected generation from the underlying portfolio due to curtailments and outages. These operational issues mainly related to a platform fire at Horns Reef 1 in October 2018, converter station outages at Borkum Rivkorn 2, an array cable repair campaign at London Array as well as various array cable and export system outages at Raesbank, West of Dutton Sands and Berberbank. In addition, we had higher than expected curtailments at our German wind farms, where we are partly compensated by the German grid operator tenant. These outages have resulted in an availability offshore, we had higher project development costs, which mainly related to activities in the U. S.
And Taiwan, while earnings from partnership agreements was in line with Q2 2018. Onshore contributed with €167,000,000 in the quarter, while Bioenergy was slightly below last year due to timing of maintenance costs. In customer solutions, we saw higher earnings from trading related to hedging of our energy exposures and optimization of our L and D assets in Europe as well as strong underlying margins from our gas portfolio. This partly offset by lower earnings related to our gas at storages. Finally, EBITDA in Q2 '19 was positively affected by €149,000,000 from the implementation of the new IFRS 16 accounting standard regarding leasing.
Net profit totaled €1,100,000,000 an increase of SEK 200,000,000 in the Q2 of 'nineteen. The increase was driven by higher EBITDA and partly offset by higher depreciation from more wind farms in operation. The effect from IFRS 16 was slightly negative on the net profit level. Free cash flow from continuing operations came in at €4,100,000,000 a €4,000,000,000 improvement year on year. In Q2 'nineteen, we had a higher release of funds tied up in work in progress due to the receipt of a milestone payment in connection with the construction of Hornsea 1 from our partner.
Our gross investments for the quarter totaled SEK 3,400,000,000 of which SEK 2,700,000,000 related to the buildout of our offshore and onshore wind farms. If we then turn to Slide 13 and our net interest bearing debt and financial ratios. Our net debt at the end of Q2 amounted to €5,000,000,000 The €4,100,000,000 decrease primarily reflected contribution from free cash flow, as I just described, as well as minor impacts from paid hybrid coupons and exchange rate adjustments. Our credit metric, FFO to adjusted net debt, stood at 58%, well above our target level of around 30%. Return on capital employed came in at 29%, a 6 percentage point increase compared to the same period last year.
Q2 'nineteen was significantly impacted by the farm down gains from Hornsea 1, whereas last year, it was impacted by the farm down gains from Walney Extension and Bokum Rivkund 2. If we then move to the results from the business units, we start with Offshore on Slide 14. Power generation increased by 0.4 terawatt hours compared to Q2 last year, primarily due to the ramp up of generation from Bougain Rivcon 2, 1 extension and Hornsea 1, which in total amounted to 0.3 terawatt hours. As I described earlier, we had lower than expected generation from the underlying portfolio in Q2 'nineteen due to these curtailments and outages. The wind speeds for the quarter was 8 meter per second, up 0.1 meters per second compared to last year.
This was slightly below the normal wind speed for the quarter of 8 0.2 meters per second. We did, however, have a notable difference between locations with high wind speeds in Denmark and Germany being offset by lower wind speeds in the U. K. For the 1st 6 months of 'nineteen, the wind speeds were in line with the normal year wind speed of 9.2 meters per second for the total portfolio. EBITDA for the quarter amounted to SEK 3,300,000,000 up SEK 200,000,000 on Q2 'eighteen.
Earnings from wind farms in operations increased by SEK 500,000,000 due to the higher generation. Earnings from partnerships in the quarter amounted to SEK 1,600,000,000, which was in line with last year. The construction agreements in this quarter primarily concerned Hornsea 1 as well as positive effects from the ongoing divestments of the offshore transmission assets at Walnew Extension and Raesbank, whereas last year's earnings related to Walney Extension and Borgom Rivkon II. In Q2 'nineteen, we also had a positive effect from construction projects finalized in 2018, where the final completion of various outstanding issues ended up with a lower spend than what we had provided for. Finally, the project development costs for the quarter amounted to SEK 600,000,000 mainly relating to the expected to be expensed and the remaining €700,000,000 will be capitalized.
This increase, compared to what we earlier guided, is mainly related to our U. S. Activities, where we capitalize costs in the U. S. When we have an irrevocable PPA contract and an investable project.
For our U. S. Project, we have higher costs before we take the final investment decision compared to what we see in other markets we currently operate in, partly due to the late timing of FID relative to commissioning of the wind farm because of the regulatory process and partly due to higher site investigation costs. In addition, the later than expected FID on Greater Changwa 1 and 2 in Taiwan has, to some extent, increased project development costs. The free cash flow totaled €5,900,000,000 in Q2, a significant increase on last year, mainly driven by a higher release of funds tied up in work in progress from the received milestone payments in connection with construction of Hornsea 1 for our partners and lower gross investments.
If we then turn to the results for onshore on Slide 15. The onshore power generation amounted to 0.8 terawatt hours in Q2. The wind speed averaged 7.7 meters per second, which was below a normal wind speed, which is 8.4% for the quarter, while we had a very high availability of 97% across the portfolio. EBITDA came in at €167,000,000 for the quarter, with earnings from operational wind farms and production credit contributing with CHF 220,000,000. This was partly offset by project development and other 1,200,000,000 primarily related to the construction of Sage Draw and Locket as well as the acquisition of the Willow Creek project and the development activities of Coronial Energy.
Turning to Slide 16, covering the results in Bioenergy. EBITDA came in at a negative €159,000,000 The lower EBITDA compared to last year was primarily related to timing of maintenance costs, while the underlying earnings were in line. The free cash flow increased by SEK 300,000,000 compared to last year, and this increase were driven by lower gross investments related to the bioconversion of the Asens power station, which is now close to being completed as well as higher trade and VAT payables due to higher generation in Q2 'nineteen. Then to the last business unit on Slide 17, Customer Solutions. The EBITDA for totaled €300,000,000 an increase of €200,000,000 on last year.
The higher earnings from trading related to hedging of our energy exposures as well as optimization of our LNG assets in Europe and strong underlying margins in our gas portfolio. The increase was partly offset by lower earnings related to our gas at storage within markets. The substantial decrease in gas prices during Q2 'nineteen led to a reduction in the accounting value of our gas inventories and consequently, a temporary negative impact on EBITDA in this quarter. This negative impact will be offset if gas prices increase or when we sell the gas later in 'nineteen or 2020 as we have hedged most of our gas margin. The free cash flow for the quarter amounted to a negative of €600,000,000 primarily from higher receivables, partly relating to factoring of renewables energy certificates as well as lower payables due to the lower sourcing of gas volumes.
We then turn to Slide 18, which shows our 2019 guidance and our long term financial estimates and policies. Our 2019 EBITDA guidance for the group is unchanged relative to our guidance in our annual report for 'eighteen. And we still expect EBITDA, excluding new partnership agreement, to be between €15,500,000,000 €16,500,000,000 However, the unchanged outlook covers some underlying and offsetting changes across the business unit units. Looking at offshore. We expect earnings from offshore wind farms in operation to increase as a result of the ramp up of generation from 1 extension, Bokom 2 and Hornsea 1.
However, the increase will be lower than our original expectation due to the containments and operational issues I've talked about, which we have experienced during the first half of 2019 and which we expect to persist into Q3 of 2019. The earnings from our existing partnership agreements are now expected to be in line with 2018, whereas we previously expected these earnings to decline. The earnings from partnership agreements amounted to SEK 3.7 €1,000,000,000 in 2018. The improvement is mainly due to higher than expected earnings from the construction of Hornsea 1 due to the good progress we have seen, including lower CapEx spend. We also had positive effects from construction projects finalized in 2018, where the final completion of these various outstanding issues ended with a lower spend than what we had provided for.
And lastly, the positive effects from the ongoing divestments of the offshore transmission assets have also been included in the first half of 'nineteen. For Customer Solutions, we now expect 2019 EBITDA to be in line with 2018, where we previously expected the EBITDA to be significantly lower. In markets, we have seen significantly higher earnings from trading related to hedging of our energy exposures in the first half of 'nineteen than what we had expected. In addition, we have had higher underlying earnings from our gas portfolio, mainly due to higher margins. Finally, we now expect a less negative accounting effect in our gas portfolio related to Gas at Storages relative to what we expected at the beginning of the year.
The accounting effect related to Gas at Storage is a timing effect and does not, as such, impact our earnings. The directional guidance for Onshore and Bioenergy is unchanged relative to the guidance in our annual report for 'eighteen. Furthermore, our gross investments guidance of 21,000,000,000 to €23,000,000,000 is also unchanged. And with that, we now open up for Q and A. Operator, please.
Please. And the question comes from the line of Christian Johansen of Danske Bank. Please go ahead. Your line is open.
Yes, thank you. First question is on your guidance and just if you can help me a bit with the math on these changes to the directional guidance. So you're saying lower earnings from operating offshore wind pharmacist balanced by hiring some partnership and customer solutions. If I look at what you communicated when you made the Hornsea 1 farm down, you said that roughly 2.6 to 2.7 would be booked in 2019 and now you expect SEK 3,700,000,000 for this segment. So to me, it sounds like you're upgrading by roughly SEK 1,000,000,000 and then on top of that, the upgrade in customer solutions.
But what you quantify in terms of lower than expected earnings for the operating wind farms is sort of in the magnitude of CHF200 1,000,000 to CHF300 1,000,000. So can you just help me a bit on what I'm missing here?
I think it's a fair question, Christian. I'm not going to sort of argue sort of with the individual items here that you referred to. I would just say that we still obviously have half a year to go, and there is still a fair amount of uncertainty related to the next 6 months in terms of everything from production volume to prices. And we are in the process of finalizing the world's largest offshore wind farm, which obviously also comes with uncertainty on the exact timing, etcetera. So I'm just saying there are a number of moving parts across the business during balance of year, which led us to conclude that it would be correct for us to maintain our guidance at this point.
Okay. But am I correct in assuming that the original guidance for partnerships were in line with what you guided for Hornsea One, I. E, those SEK 2,600,000,000 to SEK 2,700,000,000?
That's correct, yes.
All right. Thank you. Then my other question is regarding Ocean Wind and this option that PSEG has. I mean, you're probably not going to give us exact details, but obviously, what I would be quite interested to hear is that how we should think about this sort of compared to what we've seen in your farm down model. In other words, will you be able to have sort of full NPV retention if PSEG chooses to exercise this option?
I would not be able to go into any details on the topic, Christian. There is an agreement with PSEG as to how they can buy into Ocean Wind up to 50% equity. And there is a good ongoing dialogue with PSG at the moment. We're going to have to wait for that process to conclude before we can come out and give you any additional data points on a potential sell down.
Can you say anything about the time line? I mean, when do you sort of be completed?
I mean, it's the dialogue is well in progress, and it should be a matter of months, so certainly sometime during the autumn.
All right. That's clear. Then my last question is on these outages and curtailment, which you described. Are there anything structural in this? I mean, should we sort of expect you to increase the budget for these kind of costs going forward?
Or is it just bad luck in the quarter?
I would consider it more bad luck in the quarter. We've seen availability in 2nd quarter being down to 87%, which is quite unusual, which is also why we felt that we should come forward and provide you with more granularity on why the availability was that low in 2nd quarter. I mean, we will see quarters where we have very high availability, quarters where we have slightly low availability. These different types of operational issues, they will come and go, and I would consider it sort of a natural statistical fluctuation. But as we have pointed out today during first half, we have seen more than we have seen in previous years.
And again, I think it's more a matter of having had a little bit of a bad streak during first half. I wouldn't extrapolate above and beyond that. As I said earlier, we have been looking at an uncompensated production loss of 3 50 gigawatt hours. Normally, we would be looking at a normalized level, which is well below half of that. So when you look at the SEK400 1,000,000 that we point to as the EBITDA impact, that impact would normally probably be closer to CHF 100,000,000 to CHF 200,000,000.
So that sort of gives you the magnitude of what we would consider more of a normal impact and what was a little bit of a challenging first half this year.
Our next question comes from the line of Alberto Gandolfini sorry, Alberto Gandolfi of Goldman Sachs. Please go ahead.
Thank you and afternoon everyone. I have a few questions and thanks for taking them. The first one is, I think at the moment your run rate seems to be participating to about 6 gigawatt of auctions or probably in the next couple of years up to 8 gigawatt of auctions. But the offshore market globally is obviously expanding. We're moving to probably if you take all those targets you were showing, we're moving to 15 and soon enough to 20 gigawatts.
So I was wondering what stops you from upgrading the tenders, the auctions you are going to attend to? Is it stretching to thin the organization? Is it is there any constraints? What are the bottlenecks? Or can you actually continue to expand your development team and be able to keep participating to more options.
So what I'm trying to say here is if we go to a 20 gigawatt a year global offshore market, should you be able to perhaps be adding way more than 1 gigawatt a year because we move to a 2 gigawatt a year one day? The second question is, if you have any thoughts in terms of what we might call an end game. The European Union has a 2,050 strategy, which suggests by 2,050 about 3 50 gigawatts of offshore just in Europe. And now the new President is talking about moving towards net zero emissions. I was curious to see if you have done carried out any feasibility study.
Can Europe become maybe 400 gigawatt market in a net zero emission scenario? And if that is the case, are we type of top down? I know it's 30 years away, like 15 years ago, many people were underestimating handset sales of the iPhone or Amazon. So I'm just trying to figure this out. And the last one is on permitting and bottlenecks more in general.
1 of your competitors has apparently been facing some delays. I was reading that in just on the East Coast, you need something like 23 permits. And even when you get awarded, you don't have all the permits. So I was trying to understand how the top down policy will clashes against the bottom up permitting and if that could become a bit more of a recurring issue in such an expanding market.
Thanks, Alberto. When you look at the expansion of the global offshore wind market, it's been a trend in recent years that as the price of offshore wind has been going down quite rapidly,
We have
indeed seen the global market demand expanding, and it's been a little bit of a moving target. And clearly, demand has been accelerating. We are currently looking at estimates of 150 plus gigawatts by 2,030. And of course, there is a scenario where we could go beyond that number, no doubt. So it's hard to predict as it is indeed a market that is still very much evolving on a global scale.
Whether the EU net zero emission ambition for 2,050 would allow for a 3 50 or 400 gigawatt market, Obviously, very difficult for me to predict. It's not something that we've been doing any specific work on. But what we do see globally at the moment is that demand, if anything, is only accelerating for offshore wind. As more and more governments recognize that it has become a very cost effective technology, but also more and more governments begin to realize that it brings a number of significant additional benefits in the form of local investments, local job creation, etcetera, and over time, also a more independent national energy system. So I think the benefits of offshore wind are clearly being recognized at the moment.
Where it'll take us? I'm probably not the right person to start guesstimating, but we do see is an accelerating demand, no doubt. What are the constraints on our side? It's a good question and obviously one that we also spend quite a bit of time on. What we are doing at the moment is we are constantly debottlenecking our own business system to make sure that we can continue to expand the capacity that we can push through our system without losing quality.
And market development is one area where we are clearly expanding. We are now developing markets in 3 regions around the world where we used to be only in a couple of countries. The entire EPC capability is being built up both in Asia and the U. S. At the moment.
So we're going to be running essentially 3 regional EPC capabilities, which is a massive expansion of our total capacity. And at the same time, of course, at the end of the day, we need the capital also. So capital is also going to be a constraint given the massive amount of growth that is available to us when I look 10, 15 years into the future. So our task is to make sure that we move forward, expand at the right pace, maintaining full control of the company, but of course, at the same time, reaching out for the massive growth available to us, staying disciplined in our capital spend. So I don't know if he answers the question, Alberto, but we are, on a continued basis, debottlenecking all parts of the business system to allow for more annual buildout than what we have seen historically.
That's good and clear. Thank you.
On the U. S. Permitting, indeed, when you move into a new market like the U. S, where you have many, many stakeholders for whom offshore wind is a relatively new phenomenon, it is not unusual that there is quite a bit of education and learning to be done. Processes need to be established.
Different agencies, different stakeholders need to collaborate to find joint solutions. And this includes federal agencies, it recruits its stakeholders at state level, it's fishing communities, It's local coastal communities, etcetera. So it can be a complex stakeholder environment where everybody is sort of trying to get fully up to speed, and that's where we are in the U. S. At the moment.
So yes, there is clearly over the coming years a job to be done to continue to align and streamline U. S. Permitting processes, but I'm sure that we will get there. It is not unusual, and it's pretty much the same we've been through in other markets that we've been part of maturing over the years.
Our next question comes from the line of Peter Bisztyga of Bank of America Merrill Lynch. Please go ahead.
Yeah, good afternoon. A few questions, if I may. Firstly, just going back to this issue of your operational problems in Q2. You list a number of U. K.
Offshore wind projects where there are issues with the cables. And I was just wondering if there's some sort of tight fault here or if it's just coincidence. Then secondly, Siemens Gamesa sort of blew up recently, quoting that sort of competition was putting pressure on turbine prices. And I was wondering if you could just comment on the trends that you're seeing in turbine costs as you're going through your various tenders. And then finally, the U.
S. Is planning a bill to extend ITCs for offshore wind for a few years. And I was wondering whether you could elaborate whether any of your New Jersey or Rhode Island projects would benefit from this? Or is that just something that's going to help reduce the price for future tenders? Thank you.
Thank you. On the cable issues in the U. K, we do not see a systemic issue. The different issues that we are fixing at the moment are all different in nature from one asset to the other. So it's not like it's one particular issue that cuts across.
So we don't see any systemic effects here. And these are all issues, I should remind you, of course, that we can fix, and they are being fixed at the moment. We would expect many of them to be completed during Q3. When it comes to SGRE, I did notice that they quoted pressure and price pressure when they released their accounts. There's no doubt that competitive intensity in renewable energy is everywhere.
I mean, there's a tremendous amount of growth to be found globally in green energy. There are a number of players who want to be part of it. And when auctions are being used as the allocation mechanism, it will in itself drive quite a bit of competitive pressure on the developers who are bidding. And obviously, it's our task to pass that pressure on to the supply chain to make sure that they stay on their toes to innovate, to continue to take cost out, to make renewable energy as competitive as it can possibly be and doing all of that while still retaining a value creation margin for ourselves. So I think it's just a natural part of the evolution of the industry that we see this type of pressure on the developers, but also on all other supply chain participants.
But I'm sure that there will be value to be created not only by us as developers but also by the supply chain participants. The turbine manufacturers are all looking into a very, very significant long term growth opportunity in offshore wind.
And on your ITC question, I could say that, yes, we are benefiting from the ITC in our New York and New Jersey recent wins. But this extension of the ITC period, it's not something we are counting on yet. But of course, it would be very We are not giving the exact qualification here for each of our projects. That's not the level of detail we have been giving up until now, and we will not do that going forward.
And sorry, just to clarify. If the ITC was extended, would it be extended for the New Jersey and Great Island projects as well or just for future projects?
No, the project.
That would just be future projects.
Got it. Thank you very much.
Our next question comes from the line of Deepa Venkateswaran of Bernstein. Please go ahead.
Thank you. A few questions from me. So firstly, just on your guidance for the full year, would you be able to give a range of what you're expecting for offshore wind site guidance for the full year, given you're still expecting some outages for the rest of the year? 2nd question is, you've been
There's something on your line, which makes it very difficult for us to hear you clearly.
Sorry. Is this better?
Yes. Thank you.
Sorry for wasting everyone's time. So I'll go straight, I'll just summarize that. So I just wanted to know if you're happy to share a guidance range for just your EBITDA from offshore sites, given that you're still expecting some outages in Q3? And overall, your guidance for the full year looks on the lighter side, I would say. Secondly, looking at the recent auction wins in the U.
S. Where you've been probably more successful than what we expected, But in Europe, you've returned empty handed. What sort of explains this? Is it just the competitive dynamics? Or is there anything else at play?
And I think you mentioned also that you were still interested in doing something on green hydrogen in Netherlands. Would this be a separate merchant project? Or how are you sort of thinking about that? Or is that much more long term?
Thank you very much, Deepa. When it comes to guidance on the site EBITDA, we're not going to be providing that. We feel it simply becomes too granular for us to go down to guidance at that underlying level. So I'm sorry, but we're not going to be able to provide that. You can then
maybe at least clarify the impact in the next two quarters or from any outages that are continuing?
Well, I mean, we have today set the 3.50 gigawatt hour and the 400000000 impact from first half, and we said that a number of these issues are going to persist into Q3. So that's probably as close as we're going to get. At least, I think, it gives you an indication as to what we could expect. When it comes to the U. S.
Auction wins, again, obviously, incredibly encouraging for us, not least because it's our impression that these projects have not only been secured on the basis of price, but also with the evaluators clearly placing a lot of emphasis on our track record as a very experienced offshore wind developer and EPC company with a strong track record of delivering the projects that we commit. And at the same time, I think they also place value on the investments that we're going to make into the local areas. And of course, no doubt, I'm sure our prices have also been competitive, but it's not my impression that we have been winning on price alone. And in New Jersey, I think it was even made public that we did not even have the lowest price. So again, obviously, for us, that is quite a good outcome.
In the EU, clearly, in France, we were not successful in the Dunkirk tender. We had a very productive and good collaboration with Total and Elisio. But at the end of the day, the winning consortium came in with a price which was materially below ours, which is what it is. It was won at €44 as you know, and that was well below our bid price. So that's one of the tenders where you walk away.
Of course, we would have liked to win. On the other hand, we have no regrets with regard to our bidding strategy in France. The same can be said about the Netherlands. Clearly, we had hoped that the innovative proposal we'd put forward around green hydrogen that, that would be valued by the assessment panel and also the fact that we had given full certainty on the investment and financing by having our Board of Directors FIT ing the project upfront. But at the end of the day, those criteria did not give us enough points apparently to secure the award.
Of course, we always, both in France and the Netherlands and elsewhere, where we do not win, we spent a fair amount of time trying to understand exactly why we did not win and also understanding why the awardee what they did to win the project. So we'll try to extract as much learning as we can. But above and beyond that, I'm not overly concerned about it. There are many growth opportunities ahead of us in Europe. We'll have auction and tenders coming up in the U.
K, Germany, France, Netherlands and Denmark just over the next 24 months. So we consider still Europe a core market and a significant long term growth opportunity. And as part of that, we are still a big believer in green hydrogen as a key piece to the puzzle of building a world that runs entirely on green energy. And therefore, we want to support green hydrogen. Some of the markets where we're seeing things moving forward, as you also alluded to, Deepa, is in the Netherlands and in Germany, which is also why we are active in those markets.
And again, we will very much stay focused on green hydrogen to see if we can come up with future business models where we combine offshore wind and green hydrogen production. And thereby, I'm also saying that we don't see green hydrogen on a merchant basis. We see green hydrogen in some kind of combination over time at least in a combination with our offshore wind assets. We may be running pilots here and there where there will be some merchant exposure, but when you look at large scale deployment, we see it as an integral part of deploying offshore wind capacity.
Thank you.
Our next question comes from the line of Timothy Ho of Morgan Stanley. Please go ahead.
Hi, good afternoon. Three questions for me. The first is, are the 2 recent U. S. Wins comparable to the 7.5% to 8.5% through cycle IRR guidance for competitively secured processes that you gave at the CMD last year?
And a small follow on to that, given you are delivering assets at lower capital spend as exempted through the gain this year, is there potential positive upside risk to that 7 0.5% to 8.5% guidance? And finally, on farm downs, I know that you're only so far communicating about potentially doing 1 in Taiwan. But given the steep leg down in yields and the significant capacity growth opportunities that you have, could you see that view changing at all? Thank you very much.
Thank you, Timothy. On the IRR guidance, we are not going to be putting out a specific number for the U. S. Projects. They are included in the portfolio projects that we guided on at the Capital Markets Day, the 7.5% to 8.5%, we had the Revolution Wind Project in that portfolio.
Sorry, Timothy, I'm just getting some additional comments on the side here.
Yes.
So okay. Sorry, I'm getting a little bit of side advice here from my CFO. So just to be very clear, the Revolution Wind project is in what we guided on at the Capital Markets Day. Obviously, at that point, we didn't know about ocean wind and sunrise wind, and therefore, they're not in that guidance mix or in that portfolio. And as I said earlier, we're not going to be providing any stand alone guidance on those projects.
It simply becomes too granular for us to manage if we start providing any guidance at a project level, I hope for your understanding on that. When it comes to lower CapEx, yes, it's true. We have had some upside. As Marian alluded to, Hornsea 1 is progressing quite well relative to our original CapEx estimate, and we also managed to close down some of the projects completed last year where we still had some provisions for what we call snacking. We managed to do that slightly below expected capital spend.
I would not extrapolate that into sort of a broader upside to the 7.5% to the 8.5% IRR. We have many, many moving parts in our business cases across this portfolio of projects across regions. So I would not take one parameter and start extrapolating on that, that would be incorrect as I see it. Timothy, could I have you just repeat the third and final question about capacity expansion? I'm not sure.
Yes, yes. Just regarding farm downs. So my understanding is the only other farm down you're planning explicitly is in Taiwan. And given lower yields, we know that the huge amount of capacity opportunity in future that capital recycling could provide the additional capital for. Could Could you see that view changing?
Yes. No, it's an absolutely valid question, Timothy. And we do face, as we talked about, a tremendous amount of growth, and we have many opportunities. Of course, we still have quite a bit of capacity on our balance sheet to fund the growth over the coming years, the DKK200 1,000,000,000 estimate that we provided at the Capital Markets Day. If we're going to be in need of additional capital, if there's simply more value creating growth for us to reach out for, obviously, we do have an opportunity to go back and farm down in either operating assets or some of the projects currently under construction.
And if we do if we believe there's a value creation opportunity in doing that, yes, it is clearly still something we're open to.
Our next question comes from the line of Markus Belanda of Nordea.
Thank you. Two questions. First, regarding the outages, it seems many of them were related to cables or transmission infrastructure. And I'm just wondering if there's any chance you'll receive compensation from cable manufacturers or maybe on the contrary that you will have to compensate the buyers of the Offto assets because you built those transmission assets?
Thank you, Maxis. I mean the outages, some of them are cable related, both array cable and also partly related to the export systems. Other outages have been related to substations, converter stations. Some have also had a turbine component in them, even if that's the smaller part of it. So it does cut across different types of components.
We generally always use our contractual rights to the full extent towards our suppliers to make sure that they pay for repair campaigns. And we obviously also, in these cases, going back to our suppliers to make sure that they pay what they applied to according to contracts. And broadly speaking, they are obliged to standing by the quality of the components that they have delivered to us. When it comes to compensation of our partners in the projects, there is no compensation for these types of issues. They live with the operational risk that we have.
In that regard, it's a shared risk basis.
Okay. And my second question concerns the latest 5 or 6 auctions. It seems to me at least as if you have won the auctions where price was maybe not the most important factor. Does that concern you at all that you're essentially not competitive on price?
I don't think you can conclude from that, that we are not competitive on price. If we were not competitive on price, I don't think we would have won these auctions. I would actually turn it the other way around and rather than finding it to be a matter of concern, I find it very encouraging to see that we're able to win on non price factors as well. But I don't think we can win on non price factors while being downright uncompetitive on price. So I would certainly not jump to that conclusion.
I think that would be quite a mistake.
Our next question comes from the line of Sam Arie of UBS. Please go ahead.
Thank you very much. Good afternoon, everybody, and thank you as always for the presentation, very helpful. I got two questions. The first one is on Brexit. I don't think we really had a discussion of that today.
But I'm just wondering, now that so called hard Brexit starts to be rising in probability, whether you see any risk to I suppose it's the Hornsea 2 construction plan that would be affected. I Yes, Hornsea 1 will be mostly done by the end of this year. But it would be great if you could talk that through because I suppose the risk there is on a project where you've got the subsidy locked, but the construction costs haven't gone in yet. So if you could talk about HONDA 2 and Brexit, that'd be 1. And then my second question, and I apologize it's a bit of a theoretical one, but I really want to take advantage to get your views.
But with rates and yields, where they are at the minute, we get tons of questions now on cost of capital. And actually, you know you don't want to tell us what you think the cost of capital is, and I'm not asking. But can you help on a couple of questions as follows? So the first part is on Page 34 of your slide today, you give us an average funding cost for the organization of, I think, 3.something%, maybe a bit higher if you include the hybrids. But on the page after, you show a marginal cost of debt, which can be much lower, maybe some bonds at 1.5%.
We've seen other utilities through 1% not long ago. So when you're bidding for a new project, can you tell us, do you tend to think about your average debt costs, which might be 3% or 4% or your marginal debt costs, which might be 1% or 2%? And then I suppose the flip side to that is, when we value the existing projects that you have, I think we all tend to sort of do a cash flow forecast and use a discount rate. But some people are marking that discount rate to market when their cost of capital when rates and bond yields fall. But is that how you think about it for your existing assets?
Do you tend to think of your cost of capital for those projects as fixed because you've locked in the funding already? Or do you tend to think that you should sort of mark the market that wack as yields move around in the market? Sorry, it's 2 sides of the same coin and a bit of a theoretical question, but I think there's very great value if you can just share your thinking on those questions. Thank
you. Thank you for the questions, Sam. I'll start out on the Brexit question. We have been spending a lot of time working through the different Brexit scenarios, including a no deal Brexit and the supply chain implications it may have. It has mostly involved us actually going out to suppliers and talking to them about what their contingency plans are that would allow them to deliver all components for Hornsea 2 even in a no deal Brexit.
And that has given us a good level of comfort that we will be able to complete not only Hornsey 2 sorry, Hornsey 1, but also Hornsey 2 without any major disruptions from Brexit.
Yes. And on your other question on the cost of capital, WACC and the CapEx is the most sensitive information when it comes to the competitive auctions and tenders. So of course, we have a very clear methodology, which we use, but I will actually not share that with you because that is too sensitive for us. So unfortunately, I cannot share it with you, Sam.
So no discussion even in principle?
No, not really. Because if I do that, I'll actually give you the answer. So that's the problem.
Okay. Well, at least I've put the question on paper. Perhaps just a very quick follow-up on Hornsea, too, then, if you don't mind. I think your answer was you don't expect any disruption. But should we expect that your build cost will increase significantly if we go to out of the EU?
Are you factoring in a higher CapEx, in other words?
For Hornsea 2 or beyond Hornsea 2?
For Hornsea 2 in particular, I mean, I suppose future projects, you would bid based on what you expect the cost to be post Brexit, but here's one where you've got revenue locked in that cost could now go up.
We do not expect any material impact on Hornsea 2. That is, by and large, fully locked in by now. And when it comes to future projects, we will have a fair amount of visibility, I would assume at least, on the implications of Brexit once we participate expectedly, at least, participate in the next CFT round in 2021. And then, of course, we'd have to take account of any potential increases in our sourcing for the U. K.
Projects.
And for Hornsea also, the currency part of it is also locked in due to the hedging policy we have. So we'll not be hit there.
Of course. Okay. Very clear. Thank you.
Our next question comes from the line of Jenny Ping of Citi. Please go ahead.
Hi, thank you for taking my questions. I've got 3. Firstly, can you give us an update for especially the Japan and the South Korea auctions coming up in terms of where you are relative to some of the floating technology. Where you are on floating, what your latest thoughts on that would be helpful? Secondly, going back to the non compensated curtailment issues, specifically looking at Germany, it looks like basically you get or the TSO has a 28 days allowance of not paying you every year.
Can you firstly give us the run rate on how what the utilization, what the take up of that 28 days have been from the TSO and whether we should think about that being fully utilized going forward just because we have more and more renewables coming onto the system and they can essentially ask you to switch off if there's too much wind and solar? And then lastly, a question for Majana on the accounting aspect. It looks like you've released a had a provision release from the farm down of 50% of your warning extension off tow assets. Do you expect future provision releases to come through, especially given rates have fallen on for assets such as the Hornsea I, Hornsea II, which are obviously quite sizable. If you can comment on that, that would be helpful as well.
Thank you, Jenny. When it comes to Japan and South Korea, we see the Japanese government providing more and more visibility on sort of a regulatory framework for offshore wind build out. We still don't have the exact auction design. We don't have the exact time line either, but our current expectation would be that there will be the first auction in Japan during the summer of next year. They have designated these 11 zones that are suitable for offshore wind development.
And out of the 11, 4 have been selected to be the 1st movers. So we would expect those four areas clearly to be part of an initial auction presumably next year. In those four areas, we are actively focusing on the Chauchat zone in collaboration with TEPCO, where we signed the MoU earlier this year, and we are now in a joint process with TEPCO in developing an offshore wind project in the Chosho zone. Hopefully, we should be able to then join a Japanese auction next year. In South Korea, we do not yet have that same level of visibility.
There is a lot of work going on between government and some of the local players to basically establish a framework for offshore wind buildout. And we are closely monitoring the market and looking at any potential opportunities that may come up for us. So we're staying close to it. That is also the case for floating. We are closely observing all opportunities around the world for floating offshore wind and staying close to both the market development and the technological development in floating to make sure that if there is an opportunity where we should act, that we would be ready to do so.
But for the time being, we are not actively pursuing any floating projects. When it comes to the German noncompensated curtailment, what you alluded to relate to grid outages, where the grid operator have an annual cap of 18 days per year that they can spend on unplanned grid disruptions. And then they have another 10 days for planned grid maintenance, adding up to the 28 days that you alluded to. Whether they will be spending the full amount of planned and unplanned time every year is very difficult to predict. My impression is that in some years, they'll be maxing out more or less, but in other years, they will not be using the full cap on both planned and unplanned grid outages.
Yes. And then to your question on the off to release of provision. Yes, you are right. We released provisions related to both Raesbank and Waurney Extension in this quarter. We the remaining of 2 we have is Hornsea 1 and Hornsea 2.
And Hornsea 1, we expect to divest in 2021 and Hornsea 2 even later. So it is too early to say in a way how the interest rate environment and everything will be then. So therefore, in a way, we don't know, and we keep things unchanged for those assets.
Thank you.
Our next question comes from the line of James Brand of Deutsche Bank. Please go ahead.
Hi, good afternoon. Most of my questions have been answered, to be honest. So I just had a couple of kind of relatively minor ones. But the first is just on some of the operational issues that you've had this year that have impacted production. Whether we should be whether you are or have spent a significant amount of CapEx sorting out those problems.
I guess some of that, as you answered it to an earlier question, might be able to be compensated by your suppliers, but whether you're spending a significant amount of CapEx or whether it was all just coming through as OpEx? And the second one is, you mentioned the green bonds that you'd raised. I was wondering whether you could tell us the terms for the Taiwanese, green bonds. I was just curious what your funding cost was in local currency in Taiwan.
Thank you. We have limited CapEx spend on these outages traditionally as they are mostly picked up by our suppliers. We will have some spend on the London Array cable repair campaign. But broadly speaking, this is typically a spend that will be picked up by the suppliers of the malfunctioning components. When it comes to OpEx, it's a relatively minor item.
It's included in the CHF400 1,000,000 EBITDA impact that I alluded to earlier, but it's a relatively small part of that number. The vast majority of the CHF400 1,000,000 are lost revenues.
Yes. And then to the question on the green bond in Taiwan. We expect to approach the market this autumn. So for now, in a way, we don't know where we will end on the interest rate for the Taiwanese bond. But we see a lot of interest, and we think that we will be able to make an attractive financing package there.
Our next question comes from the line of Mark Threschne of Credit Suisse. Please go ahead.
Hi, thanks for taking my questions. Firstly, on the DKK 200,000,000,000 CapEx plan or outlook through to 2025. On my numbers, there's still onshore is mostly you've got projects to take up the share there. But there seems to be an amount still of DKK 20,000,000,000 to DKK 30,000,000,000 uncommitted of scope for investments. And I think on your slide, Henrik, your CMD last November, you flagged the potential for the acquisition of a European onshore wind platform.
How do you feel about that? And what are the other types of investment opportunities that you see? For example, would you consider investing more in North American onshore or maybe buying into projects in Europe and increasing the 2025 target? My second question is just on the benefit, if you like, the extra DKK 1,000,000,000 benefit through EBITDA from partnership profits. Is it fair to say, Mejana, that there's an extra €1,000,000,000 benefit to yourselves through lower CapEx, through not spending as much on your own share of the projects, I.
E, that impact should be doubled?
Thanks, Marc. On the €200,000,000,000 towards 2025, you're right. I mean, we don't have fully committed that entire spend by now. In terms of where it's going to be spent the remaining part, I mean, we obviously only going to spend the money if we can find profitable opportunities, but I do believe that we will be able to do so. Whether it's going to be in offshore or onshore and in what region, hard to predict.
A lot of it is going to come down to the outcome of auctions over the next 1 to 2 years. When it comes to onshore, in Europe, we do not have any active plans to make a European onshore acquisition. Again, I don't want to box ourselves in by ruling it out categorically and say it could never happen. I think that would be wrong, but I can say that we are not in the active processes to acquire a European onshore asset. We're extremely happy about the U.
S. Onshore business and its performance and the growth that we are able to find at the moment. And if anything, we could potentially continue to further expand that business, which currently is generating quite good value opportunities for us.
Yes. And then on your €1,000,000,000 additional partnership gains. There are 3 components to this approximately €1,000,000,000 It is the lower spend on Hornsea 1. It is this 1 year extension and this leftover from the project we completed in 'eighteen. And then you have these off tow divestments.
The 2 first of them, yes, that's right. From a cash flow perspective, off to part because for our own share, the off to is even if we get more cash flow upfront, we pay it through higher to news or the opposite. If we get lower cash flow upfront, we pay it through higher to news. So that's a 0 game on the Ofto. But on the 2 others, you are right.
Thank you. Our last question comes from the line of Ian Turner of Exane BNP Paribas. Please go ahead.
Last but hopefully not least, can I just ask you about when you expect to take FID on those 2 U? S. Projects that you've won and what you need to do between now and then to achieve that, please?
Yes. I cannot give you the exact FID timing. What we need is essentially, we need a construction and operations plan to be approved by Boeing, and that's going to take a while. It's a relatively comprehensive permitting consenting process that we're going to go through. And once we have that and we have a matured supply chain concept, we're going to be putting the business cases in front of the board for a final investment decision.
But at this point, I cannot give you an exact timing, but it's going to take us a while to get the FIDs done.
There are no further questions. Please go ahead, speakers.
All right. Thank you, everyone, so much for joining and thank you for all of the excellent questions. Much appreciated. Have a continued great day.