Welcome to this Ørsted 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 Poulsen, and the CFO, Marianne Wiinholt. 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 second quarter, with results in line with expectations, and quite notably, also the award of two major U.S. offshore wind projects. Our EBITDA for the second quarter of the year amounted to DKK 3.6 billion, which is an increase of DKK 500 million 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 Riffgrund 2 in Germany and Walney Extension and Hornsea 1 in the U.K. 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 350 GWh on a year-to-date basis, equivalent to roughly DKK 400 million 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 third quarter of this year. On the positive side, we've seen higher earnings from partnerships than originally expected, which Marianne will come back to.
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 second quarter, up from 80% in second quarter last year. As you know by now, in June, we were selected as the preferred bidder for New Jersey's first offshore wind farm with our 1,100 MW project Ocean Wind. In July, we were selected as one of the two preferred bidders in the New York solicitation with the 880 MW 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 Renewables, Enbridge joint venture and Vattenfall respectively. At the end of July, we commissioned the Lockett Wind Farm in Texas well ahead of schedule. The 184 MW onshore wind farm in the ERCOT region has performed as expected since the commissioning, and we are quite pleased with the onshore team's strong EPC performance on Lockett. In May, we completed the largest green bond offering to date when we successfully secured a funding of GBP 900 million. 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 exposure.
In June, we signed a guaranteed five-year syndicated green revolving loan facility of TWD 25 billion 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 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 Ørsted in the case concerning the use of the Ørsted name with a clear vote of five to zero. We are satisfied that this judgment upholds our claim that we have the right to use the Ørsted 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 & Bioenergy. The decision was taken as a natural consequence of the two existing business units being reduced in size. The downsizing is driven by the planned 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 Ørsted. The financial consolidation of the two business units into one will be reflected in our interim financial report for the first nine months of 2019.
Morten Buchgreitz, who was previously EVP of Customer Solutions, has been appointed EVP of Markets & Bioenergy. Within Markets & Bioenergy, we continue to prepare our power distribution residential customer and City Light businesses for separation and subsequent divestment. We still believe signing of a 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, we will of course, be actively pursuing the divestments during second half of this year. Turning to slide four, where I will focus on the outcome of the solicitations in New Jersey and New York. As mentioned in June, the New Jersey Board of Public Utilities selected Ørsted as the preferred bidder for New Jersey's first 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 GW 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 MWh from 2024 with a 2% annual escalator corresponding to a levelized 2013 price of $86.40 per MWh . Subject to final investment decision, the 1,100 MW 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. 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 GW. The other award went to Equinor's project Empire Wind. We will now negotiate a 25-year offshore wind renewable energy certificate for the 880 MW project, which will contribute significantly to achieving Governor Cuomo's ambitious goal for New York's transition to renewable energy. Sunrise Wind is a 50/50 joint venture with Eversource. 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 GW to be built between 2022 and 2024. Less than a year ago, we created the leading U.S. offshore wind platform by merging the asset portfolios and competencies of Deepwater Wind and Ørsted 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 GW, we have secured an offshore wind build-out portfolio on the U.S. East Coast of approximately 2.9 GW to be completed between 2022 and 2024. 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 GW 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, and we are well on track to reach our ambition of 15 GW offshore wind capacity by 2025 as we continue to innovate and pioneer the global offshore wind industry. Turning to slide five, 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 fourth quarter this year. At our Borssele 1 and 2 wind farm, the construction of the O&M building in Vlissingen 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 second quarter next year. We now expect to complete the two-turbine 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 Changhua 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 first large-scale offshore wind farm in Asia by 2022. At the same time, we've seen good progress at the 120 MW 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. Turning to slide six and an update on the construction projects outside offshore. In our onshore business, we continue to see good progress on our construction projects. In July, we commissioned the Lockett 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 MW wind farm in the Texas ERCOT region to be commissioned by first quarter next year. In June, we acquired the 103 MW construction-ready onshore project, Willow Creek.
The project is located in South Dakota, 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, we expect the wind farm to be commissioned by the end of 2020. In bioenergy, the bioconversion of the Avedøre Power Station is progressing according to plan. The first shipment of wood chips has arrived, 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 Esbjerg 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. 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. We are currently awaiting the final ruling from the authorities. The reconfiguration of our Renescience plant in the U.K. has been completed. 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, 976,000 smart meters had been installed and taken into use.
We expect to install the last smart meters during the third quarter this year, 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 seven, eight, and nine and take a look at the latest market development and offshore wind opportunities across the regions. Starting in Massachusetts, where the state's second offshore wind solicitation has been launched. Bidders will have to submit their bids by 23rd of August this year, with expected selection of projects for negotiation in November this year. Bidders can submit proposals ranging between 200 MW and 800 MW. As part of the updated framework in Massachusetts, the price cap for the second solicitation has been removed. Recently, Massachusetts passed a new bill with an ambition of 3.2 GW offshore wind by 2030, five years ahead of the previous target.
With the total award of 1.7 GW to Sunrise Wind and Empire Wind, New York has taken a significant step towards their 2035 target of 9 GW offshore wind. We expect that the next auction will take place in the second half of 2020. We expect the federal agency BOEM to release two New York offshore lease areas of at least 800 MW each in early 2020, with a lease auction likely to take place later in 2020. In New Jersey, the recent 1.1 GW award was the first step towards the state's 2030 target of 3.5 GW of offshore wind. New Jersey is expected to have subsequent auctions of 1.2 GW of offshore wind in both 2020 and 2022.
Moving to Connecticut, where the state approved the legislation for the procurement of an additional 2 GW of offshore wind. The next procurement is expected to be for 400 MW-800 MW of offshore wind, with a bid deadline on September 30th this year, and an expected outcome announced in November. In Rhode Island, the 400 MW PPA for our Revolution Wind Project has been approved by regulators. We continue the development of the full Revolution Wind Project. National Grid has made a conditional selection of the preferred bidders in the 2018 Zero-Carbon RFP. Selected bidders have been notified. 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.
Maryland has confirmed the state's target of approximately 1.6 GW of offshore wind capacity by 2030, an increase of 1.2 GW compared to the previous bill. Maryland is expected to have auctions of at least 400 MW 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 eight and the recent market developments in Europe. In the U.K., the third 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 forward to the subsequent auctions, which will be held every second year.
In Germany, the German Federal Ministry for Economic Affairs has recently suggested to increase the current 15 GW target for 2030 to 20 GW. We expect Germany to launch the first centralized tender in 2021, with the aim of having 800 MW constructed annually from 2026 onwards. Moving to the Netherlands, where the fourth offshore wind tender was concluded in the beginning of July. Even though we're not successful in the tender, we're 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 GW of offshore wind by 2030, and we expect the next tender of up to 760 MW to take place early next year.
In France, the third 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 GW to 10 GW by 2028 in connection with the outcome of the third auction. Finally, turning to slide nine and the market development in Asia Pacific. In Taiwan, auctions for an additional 4.5 GW 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 third round development will be announced during the fourth quarter of 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.
Four 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 Ørsted, with the aim to jointly develop the project within this zone. The Ministry of Economy, Trade and Industry in Japan is pursuing a targeted timeline 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 Lockett Wind Farm, our operating portfolio of onshore wind farms reached 1 GW .
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. Moving to slide 11. Over the past decade, we have, at Ørsted, 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 2019, 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. Today we announce a new target that covers the indirect carbon emissions related to our business. By 2032, 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. 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 DKK 3.6 billion, a year-on-year increase of DKK 0.5 billion, 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 Riffgrund 2, Walney Extension, and Hornsea 1. Wind speeds in Q2 2019 were above last year. In Q2 2019, 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 Rev 1 in October 2018, converter station outages at Borkum Riffgrund 2, an array cable repair campaign at London Array, as well as various array cable and export system outages at Race Bank, West of Duddon Sands, and Burbo Bank. We had higher than expected curtailments at our German wind farms, where we are partly compensated by the German grid operator, TenneT. These outages have resulted in an availability of 87% for the quarter. 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 DKK 167 million 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 LNG assets in Europe, as well as strong underlying margins from our gas portfolio. This was partly offset by lower earnings related to our gas at storages. Finally, EBITDA in Q2 2019 was positively affected by DKK 149 million from the implementation of the new IFRS 16 accounting standard regarding leasing. Net profit totaled DKK 1.1 billion, an increase of DKK 0.2 billion in the second quarter of 2019. The increase was driven by higher EBITDA. 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 DKK 4.1 billion, a DKK 4 billion improvement year-over-year.
In Q2 2019, we had a high 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 DKK 3.4 billion, of which DKK 2.7 billion related to the build-out of our offshore and onshore wind farms. We turn to slide 13, and our net interest-bearing debt and financial ratios. Our net debt at the end of Q2 amounted to DKK 5 billion. The DKK 4.1 billion 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 2019 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 Borkum Riffgrund 2. If we move to the results from the business units, we start with Offshore on slide 14. Power generation increased by 0.4 TWh compared to Q2 last year, primarily due to the ramp-up of generation from Borkum Riffgrund 2, Walney Extension, and Hornsea 1, which in total amounted to 0.3 TWh . As I described earlier, we had lower than expected generation from the underlying portfolio in Q2 2019 due to these curtailments and outages. The wind speeds for the quarter was 8 m/s, up 0.1 m/s compared to last year.
This was slightly below the normal wind speed for the quarter of 8.2 m/s . 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 first six months of 2019, the wind speeds were in line with the normal year wind speed of 9.2 m/s for the total portfolio. EBITDA for the quarter amounted to DKK 3.3 billion, up DKK 0.2 billion on Q2 2018. Earnings from wind farms in operations increased by DKK 0.5 billion due to the higher generation. Earnings from partnerships in the quarter amounted to DKK 1.6 billion, 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 Walney Extension and Race Bank, whereas last year's earnings related to Walney Extension and Borkum Riffgrund 2. In Q2 2019, 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 cost for the quarter amounted to DKK 0.6 billion, mainly relating to the development activities in the U.S. and Taiwan. The total project development cost for 2019 is expected to amount to roughly DKK 2.5 billion, of which approximately DKK 1.8 billion is expected to be expensed, and the remaining DKK 0.7 billion will be capitalized.
This increase, compared to what we have 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 Changhua 1 and 2 in Taiwan has, to some extent, increased project development costs.
The free cash flow totaled DKK 5.9 billion 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 turn to the results for onshore on slide 15. The onshore power generation amounted to 0.8 TWh in Q2. The wind speed averaged 7.7 m/s , which was below a normal wind speed, which is 8.4 m/s for the quarter, while we had a very high availability of 97% across the portfolio. EBITDA came in at DKK 167 million for the quarter, with earnings from operational wind farms and production credit contributing with DKK 220 million. This was partly offset by project development and other costs.
The free cash flow amounted to a DKK -1.2 billion, primarily related to the construction of Sage Draw and Lockett, as well as the acquisition of the Willow Creek project and the development activities of Coronal Energy. Turning to slide 16, covering the results in Bioenergy. EBITDA came in at a DKK -159 million. 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 DKK 0.3 billion compared to last year, and this increase was driven by lower gross investments related to the bioconversion of the Asnæs Power Station, which is now close to being completed, as well as higher trade and VAT payables due to higher generation in Q2 2019.
To the last business unit on slide 17, Customer Solutions, t he EBITDA for Q2 2019 totals DKK 0.3 billion, an increase of DKK 0.2 billion 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 storage within Markets & Bioenergy. The substantial decrease in gas prices during Q2 2019 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 2019 or 2020, as we have hedged most of our gas margin.
The free cash flow for the quarter amounted to DKK -0.6 billion, 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 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 2018, we still expect EBITDA excluding new partnerships agreement to be between DKK 15.5 billion and DKK 16.5 billion. The unchanged outlook covers some underlying and offsetting changes across the business 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 Walney Extension, Borkum Riffgrund 2, and Hornsea 1.
However, the increase will be lower than our original expectation due to the curtailments and operational issues I've talked about, which we have experienced during the first half of 2019 and which we expect to persist into the third quarter 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 DKK 3.7 billion 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. Lastly, the positive effects from the ongoing divestments of the offshore transmission assets have also been included in the first half of 2019. 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 our energy exposures in the first half of 2019 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 2018. Furthermore, gross investments guidance of DKK 21 billion-DKK 23 billion is also unchanged. With that, we now open up for Q&A. Operator, please.
Ladies and gentlemen, if you have a question for the speakers, please press 01 on your telephone keypad. Please hold for the first question. The question comes from the line of Kristian Johansen of Danske Bank. Please go ahead. Your line is open.
Yes, thank you. First question is on your guidance. If you can help me a bit with the math on these changes to the directional guidance. You're saying lower earnings from operating offshore wind farms is balanced by higher earnings from partnership and Customer Solutions. If I look at what you communicated when you made the Hornsea 1 farm down, you said that roughly DKK 2.6 billion-DKK 2.7 billion would be booked in 2019. Now you expect DKK 3.7 billion for this segment. To me, it sounds like you're upgrading by roughly DKK 1 billion. On top of that, the upgrade in Customer Solutions. What you quantify in terms of lower than expected earnings for the operating wind farms is sort of in the magnitude of DKK 200 million-DKK 300 million. Can you just help me a bit on what I'm missing here?
I think it's a fair question, Kristian. I'm not going to sort of argue with the individual items here that you refer to. I would just say that we still obviously have half a year to go. There is still a fair amount of uncertainty related to the next six months in terms of everything from production volume to prices. We are in the process of finalizing the world's largest offshore wind farm, which obviously also comes with uncertainty on the exact timing, et cetera. 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. Am I correct in assuming that the original guidance for partnerships were in line with what you guided for Hornsea 1, i.e., DKK 2.6 billion-DKK 2.7 billion?
That's correct, yes.
All right. Thank you. My other question is regarding Ocean Wind and this option that PSEG has. You're probably not going to give us exact details. 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, Kristian. There is an agreement with PSEG as to how they can buy into Ocean Wind up to 50% equity. There is a good ongoing dialogue with PSEG 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 timeline? When do you expect this to sort of be completed?
The dialogue is well in progress. It should be a matter of months. Certainly, sometime during the autumn.
All right. That's clear. My last question is on these outages and curtailment, which you described. Are there anything structural in this? 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 second 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 second quarter. We will see quarters where we have very high availability, quarters where we have slightly lower availability. These different types of operational issues, they will come and go, and I would consider it sort of a natural statistical fluctuation. As we have pointed out today, during first half, we've seen more than we have seen in previous years. 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 350 GWh . Normaly, we would be looking at a normalized level, which is well below half of that. When you look at the DKK 400 million that we point to as the EBITDA impact, that impact would normally probably be closer to DKK 100 million-DKK 200 million. 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.
All right. Very clear. Thank you.
Our next question comes from the line of Alberto Gandolfi. Sorry, Alberto Gandolfi of Goldman Sachs. Please go ahead.
Thank you. 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 GW of auctions or probably in the next couple of years, up to 8 GW of auctions. 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 GW and soon enough to 20 GW. I was wondering, what stops you from upgrading the tenders, the auctions you are going to attend to? Is it stretching too thin the organization? Is there any constraints? What are the bottlenecks? Can you actually continue to expand your development team and be able to keep participating to more auctions?
What I'm trying to say here is, if we go to a 20 GW a year global offshore market, should you be able to perhaps be adding way more than 1 GW a year? Could we move to a 2 GW 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 2050 strategy, which suggests by 2050, about 350 GW of offshore just in Europe. Now the new president is talking about moving towards net zero emissions. I was curious to see if you have carried out any feasibility study. Can Europe become maybe a 400 GW market in a net zero emission scenario? If that is the case, are we talking about a global offshore market of 1,000 GW by 2050?
Is this a type of top-down? I know it's 30 years away, but like 15 years ago, many people were underestimating handset sales of the iPhone or Amazon. I'm just trying to figure this out. The last one is on permitting and bottlenecks more in general. One of your competitors has apparently been facing some delays. I was reading that just on the East Coast, you need something like 23 permits, and even when you get awarded, you don't have all the permits. 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. Thank you.
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. Clearly, demand has been accelerating. We are currently looking at estimates of 150+ GW by 2030. Of course, there is a scenario where we could go beyond that number, no doubt. 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 2050 would allow for a 350 GW or 400 GW market, obviously very difficult for me to predict. It's not something that we've been doing any specific work on.
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, et cetera. Over time, also a more independent national energy system. 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 what 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 de-bottlenecking 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. Market development is one area where we are clearly expanding. We are now developing markets in three 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. We're going to be running essentially three regional EPC capabilities, which is a massive expansion of our total capacity. At the same time, of course, at the end of the day, we need the capital also.
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. 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. I don't know if it answers the question, Alberto, but we are, on a continued basis, de-bottlenecking all parts of the business system to allow for more annual build-out 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 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. This includes federal agencies, it's stakeholders at state level. It's fishing communities. It's local coastal communities, et cetera. It can be a complex stakeholder environment, where everybody's sort of trying to get fully up to speed. That's where we are in the U.S. at the moment. 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.
Thank you.
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. I was just wondering if there's some sort of type fault here or if it's just coincidence. 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 sort of trends that you're seeing in turbine costs as you're going through your various tenders.
Finally, noticed the U.S. is planning a bill to extend ITCs for offshore wind for a few years, I was just 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. It's not like it's one particular issue that cuts across. We don't see any systemic effects here. 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 third quarter. 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. 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.
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. 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. Doing all of that while still retaining a value creation margin for ourselves. 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. 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 significant long-term growth opportunity in offshore wind.
On your ITC question, I could say that yes, we are benefiting from the ITC in our New York and New Jersey recent wins. This extension of the ITC period, it's not something we are counting on yet. Of course, it would be very positive if that could also be a benefit to the future potential wins. We are not giving the exact qualification year 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.
Sorry, just to clarify, if the ITC was extended, would it be extended for the New Jersey and Rhode Island projects as well, or just for future projects?
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. Just 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? Second question is, you've been-
There is 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. I'll go straight. I'll just summarize that. 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. 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? 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. I'm sorry, but we're not going to be able to provide that.
Can you then maybe at least clarify the impact in the next two quarters from any outages that are continuing?
We have today set the 350 GWh and the DKK 400 million impact from the first half. We said that a number of these issues are going to persist into the third quarter. 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.
Okay.
When it comes to the U.S. auction wins, 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. At the same time, I think they also place value on the investments that we're going to make into the local areas. Of course, no doubt, I'm sure our prices have also been competitive. It's not my impression that we have been winning on price alone. In New Jersey, I think it was even made public that we did not even have the lowest price. 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 Elicio. 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 EUR 44, as you know, and that was well below our bid price. 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 the project up front. 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 spend 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. We'll try to extract as much learning as we can. 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. We consider still Europe a core market and a significant long-term growth opportunity. 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.
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. 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. 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 from me. The first is, are the two recent U.S. wins comparable to the 7.5%-8.5% through cycle IRR guidance for competitively secure processes that you gave at the CMD last year? A small follow-on to that. Given you are delivering assets at lower capital spend as exhibited through the gains this year, is there potential positive upside risk to that 7.5%-8.5% guidance? Finally, on farm downs, I know that you're only so far communicating about potentially doing one in Taiwan. 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%-8.5%. We had the Revolution Wind project in that portfolio. Sorry, Timothy, I'm just getting some additional comments on the side here. Yeah. Okay. Sorry, I'm getting a little bit of side advice here from my CFO. 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, therefore, they're not in that guidance mix or in that portfolio. As I said earlier, we're not going to be providing any standalone 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.
Yes, sure.
When it comes to lower CapEx, yes, it's true. We have had some upsides, as Marianne alluded to. Hornsea 1 is progressing quite well relative to our original CapEx estimate. We also managed to close down some of the projects completely last year, where we still had some provisions for what we call snagging. We managed to do that slightly below expected capital spend. I would not extrapolate that into a broader upside to the 7.5% to the 8.5% IRR. We have many moving parts in our business cases across this portfolio projects across regions. 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 I-
Yeah. Just regarding farm downs. My understanding is the only other farm down you're planning explicitly is in Taiwan. Given lower yields, we know that the huge amount of capacity opportunity in future that capital recycling could provide the additional capital for. Could you see that view changing?
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 DKK 200 billion 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. If we do, if we believe there's a value creation opportunity in doing that, yes, it is still something we're open to.
Got it. Thank you.
Our next question comes from the line of Marcus Bellander of Nordea. Please go ahead.
Thank you. Two questions. First, regarding the outages, it seems many of them are related to the cables or the transmission infrastructure. 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 OFTO assets because you built those transmission assets.
Thank you, Marcus. 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. 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. We obviously also, in these cases, going back to our suppliers to make sure that they pay what they are obliged to, according to contracts. 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. Thank you. My second question concerns the latest five or six 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 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. I don't think we can win on non-price factors while being downright uncompetitive on price. I would certainly not jump to that conclusion. I think that would be quite a mistake.
Okay. Thank you.
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 guess Hornsea 1 will be mostly done by the end of this year. 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. If you could talk about Hornsea 2 and Brexit, that'd be one.
Then my second question, I apologize, it's a bit of a theoretical one, I really want to take advantage to get your view. With rates and yields where they are at the minute, we get tons of questions now on cost of capital, and obviously, you know you don't want to tell us what you think the cost of capital is, and I'm not asking. Can you help on a couple of questions as follows? The first part is on page 34 of your slides today, you give us an average funding cost for the organization of, I think, 3 point something percent, maybe a bit higher if you include the hybrids. 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 do 1% not long ago.
When you're bidding for a new project, can you tell us, do you tend to think about your average debt cost, which might be 3% or 4%, or your marginal debt costs, which might be 1% or 2%? I suppose the flip side to that is when we value the existing projects that you have, I think we'll tend to do a cash flow forecast and use a discount rate. Some people are marking that discount rate to market when the cost of capital, when rates and bond yields fall. 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?
Do you tend to think that you should sort of mark the market that WACC as yields move around in the market? I am sorry if they are two sides of the same coin and a bit of a theoretical question, I think there is 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. That has given us a good level of comfort that we will be able to complete not only Hornsea 1, but also Hornsea 2, without any major disruptions from Brexit.
Yes, on the other question on the cost of capital, it's a very good and very valid question. As we have talked about before, both the WACC and the CapEx is the most sensitive information when it comes to the competitive auctions and tenders. 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. Unfortunately, I cannot share it with you, Sam.
No discussion even in principle?
No, not really, because if I do that, I'll actually give you the answer. That's the problem.
Okay. Well, at least I've put the question on paper. Perhaps just a very quick follow-up on Hornsea 2 then, if you don't mind. I think your answer was you don't expect any disruption. Should we expect that your build cost will increase significantly if we go out of the EU?
Beyond?
You'll be factoring in a higher CapEx, in other words.
For Hornsea 2 or beyond Hornsea 2?
For Hornsea 2 in particular. 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, but costs could now go up.
We do not expect any material impact on Hornsea 2. That is, by and large, fully locked in by now. 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 CfD round in 2021. There, of course, we'd have to take account of any potential increases in our sourcing for the U.K. projects.
Yeah. For Hornsea also, the currency part of it is also locked in due to the hedging policy we have. 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 three. 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 competitors that's already formed JVs and entered that market with 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 what the utilization, what the take-up of that 28 days has 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. Lastly, a question for Marianne on the accounting aspect. It looks like you've had a provision release from the farm down of 50% of your Walney Extension Ofgem assets. Do you expect future provision releases to come through, especially given rates have fallen on for assets such as the Hornsea 1, Hornsea 2, which are obviously quite sizable? If you can comment on that would be helpful as well. Thanks.
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 timeline either. 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. Out of the 11, four have been selected to be the first movers. 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 Choshi zone, in collaboration with TEPCO, where we signed the MoU earlier this year. We are now in a joint process with TEPCO in developing an offshore wind project in the Choshi zone. Hopefully, we should be able to 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 build-out. We are closely monitoring the market and looking at any potential opportunities that may come up for us there. 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. For the time being, we are not actively pursuing any floating projects. When it comes to the German non-compensated 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. 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.
The 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, to your question on the OFTO release of provision. Yes, you are right. We released provisions related to both Race Bank and Walney Extension in this quarter. The remaining OFTO we have is Hornsea 1 and Hornsea 2, and Hornsea 1 we expect to divest in 2021, and Hornsea 2 even later. It is too early to say, in a way, how the interest rate environment and everything will be then. In a way, we don't know, and we keep things unchanged for those assets.
Okay, 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. I just had two relatively minor ones. The first is just on some of the operational issues that you've had this year that have impacted production, 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, whether you're spending a significant amount of CapEx or whether it was all just coming through as OpEx. 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 bond. I'm just curious what your funding cost was in local currency in Taiwan. Thanks.
Thank you. We have limited CapEx spent on these outages traditionally, as they are mostly picked up by our suppliers. We will have some spent on the London Array cable repair campaign. Broadly speaking, this is typically spent 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 DKK 400 million EBITDA impact that I alluded to earlier. It's a relatively small part of that number. The vast majority of the DKK 400 million are lost revenues.
Yes, to the question on the green bond in Taiwan, we expect to approach the market this autumn. For now, in a way, we don't know where we will end on the interest rate for the Taiwanese bond. We see a lot of interest, and we think that we will be able to make an attractive financing package there.
Okay, great. Thank you.
Our next question comes from the line of Mark Freshney of Credit Suisse. Please go ahead.
Hi, thanks for taking my questions. On the DKK 200 billion CapEx plan or outlook through to 2025. On my numbers, onshore is mostly you've got projects to take up the share there, but there seems to be an amount still of DKK 20 billion-DKK 30 billion uncommitted of scope for investments. I think on your slide, Henrik, at your CMD last November, you flagged the potential for the acquisition of a European onshore wind platform. How do you feel about that? 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 billion benefit through EBITDA from partnership profits.
Is it fair to say, Marianne, that there's an extra DKK 1 billion 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? Thank you.
Thanks, Mark. On the DKK 200 billion towards 2025, you're right. We don't have fully committed that entire spend by now. In terms of where it's going to be spent, the remaining part, we're obviously only going to spend the money if we can find profitable opportunities. 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 1-2 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.
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. If anything, we could potentially continue to further expand that business, which currently is generating quite good value opportunities for us.
Yes, on your DKK 1 billion additional partnership gains, there are three components to this approximately DKK 1 billion. It is the lower spend on Hornsea 1. It is this one-year extension and this leftover from the project we completed in 2018. You have these OFTO divestments. The two first of them, yes, that's right. From a cash flow perspective, you can double them, but not the OFTO part. Because for our own share, the OFTO is, even if we get more cash flow up front, we pay it through higher tenures or the opposite. If we get lower cash flow up front, we pay it through higher tenures. That's a zero game on the OFTO, but on the two others, you are right.
Okay, thank you.
Thank you. Our last question comes from the line of Iain Turner of Exane BNP Paribas. Please go ahead.
Last, hopefully not least. Can I just ask you about when you expect to take FID on those two 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 BOEM, and that's going to take a while. It's a relatively comprehensive permitting, consenting process that we're going to go through. Once we have that and we have a mature supply chain concept, we're going to be putting the business cases in front of the board for a final investment decision. At this point, I cannot give you an exact timing, but it's going to take us a while to get the FIDs done.
Thank you.
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. .