Market consultation of the Federal Ministry for Economic Affairs and Energy on offshore wind energy. Statement — AquaVentus Förderverein e.V.
23 December 2025. Introduction. Offshore wind offers the greatest expansion potential among the renewable energies in Germany and Europe. Through cost-efficient, market-integrated and grid-friendly development — including coupling with offshore hydrogen production — offshore wind can contribute decisively to achieving the national and European climate targets and strengthen security of supply in the long term. The planned amendment of the Offshore Wind Energy Act (WindSeeG) sets central parameters for the future development of offshore wind, of hydrogen generation at sea and of the underlying offshore energy infrastructure. The statement of the AquaVentus Förderverein focuses on the legal preconditions necessary for a successful ramp-up of offshore hydrogen production in Germany. The statement underlines in particular: • the urgent necessity of permitting combined electricity and hydrogen connections in law (as called for in the coalition agreement), • the anchoring of a statutory expansion target for offshore electrolysers, • as well as the importance of integrated site planning, particularly with regard to the SEN-1 area and Zones 4 and 5 of the EEZ, and of technology-neutral tenders. Particular urgency arises from the Site Development Plan (FEP) being prepared by the Federal Maritime and Hydrographic Agency (BSH), which could leave central potential for combined connection concepts out of account unless the Offshore Wind Energy Act is amended in good time. Under the currently applicable version of the Act, combined connection concepts of electricity and hydrogen infrastructure are not yet provided for. The BSH is therefore urgently called upon to anticipate the forthcoming regulatory changes to the Offshore Wind Energy Act proactively and to integrate planning options for combined connection concepts in Zones 4 and 5. This requires a clear political signal or a formal instruction from the Federal Ministry, in order to ensure that the FEP planning in 2026 gives adequate consideration to this future infrastructure. Only in this way can a technology-neutral ramp-up including the offshore hydrogen industry be ensured. The AquaVentus statement is intended as a constructive contribution towards developing the regulation cost-efficiently in the spirit of a holistically conceived offshore energy transition, by means of the necessary degrees of freedom through an intelligently interlinked energy transport infrastructure.
Answers to the consultation questions. 1) Cost efficiency and synchronisation. 1.1 Optimisation. AquaVentus welcomes the fact that hydrogen production at sea is being discussed within the consultation as part of the future offshore energy system. At the same time we would like to point out emphatically that offshore electrolysis production in Zones 4 and 5 of the German EEZ — combined with a hydrogen transport network — is preferable to blanket overplanting. Already in our statement of March 2025 we set out that focusing exclusively on electricity feed-in without offshore hydrogen generation does not do justice to the long-term expansion pathway. The position paper of the Wasserstoffachter, as a sector-wide appeal of May 2025, underlined that combined (hybrid) integrated offshore electrolysis installations in combination with submarine cables and pipeline infrastructure are not only technologically feasible but also macroeconomically sensible, balanced and practicable. By contrast, a strategy of pure overplanting — that is, installing additional wind capacity beyond the cable capacity and without regard to hydrogen production — can lead to the following disadvantages: • revenue losses through peak shaving, • potential operational and macroeconomic risks as well as revenue losses that counteract the stated objective of cost savings, • delayed market introduction of the offshore hydrogen industry and thus missed economic successes and climate protection potential. Against this background, AquaVentus does not comment on the questions in passage 1.1 individually but repeats the fundamental demand that a forward-looking optimisation including offshore hydrogen is superior to an improvement of the purely sectoral electricity perspective by means of overplanting and the resulting peak shaving, because:
– Including offshore hydrogen production optimises site and network planning and lowers system costs, above all through reduced investment in the electricity grids. • It leads to greater use of offshore wind resources in areas far from the coast (less curtailment). • It increases the utilisation of the offshore electricity grid infrastructure. • It is a clear commitment to technology neutrality — hydrogen must not be treated as an option but must be provided for as an integral component. • Anchoring combined connection concepts (electricity + hydrogen) as the benchmark, as against overplanting alone, represents a market-integrated expansion of revenues for offshore wind farm developers and operators and thereby improves the business case. There is therefore a need to implement the following measures within the forthcoming reforms of the Offshore Wind Energy Act and the FEP: • funding and approval in 2026 of several pilot projects under development to demonstrate the technology in the territorial sea, • enabling combined connections of submarine cables and hydrogen pipelines in the Offshore Wind Energy Act and the FEP, at least for the SEN-1 area, • prompt tendering of the SEN-1 site under an amended Offshore Wind Energy Act from 2027, • preservation of degrees of freedom in the FEP and the Network Development Plan so that further sites in Zones 4 and 5 can be designated for offshore electrolysis in future, • technology-neutral tenders for offshore hydrogen production. In concrete terms, offshore hydrogen production can take place on platforms or on so-called offshore energy hubs or artificial islands.
1.2 Hydrogen. A. Technological aspects. 1. From when can electrolysers be deployed at sea on an industrial scale? The deployment of electrolysers at sea on an industrial scale depends substantially on the ramp-up pathway shaped by policy. Without a clear state framework — including targeted funding of demonstration projects, legal opening and market-side hedging — any robust prediction of timing remains speculative. As set out in the E-Bridge study commissioned by AquaVentus in 2024, offshore electrolysis requires a technological "triple jump":
1. Trialling under real offshore conditions (demonstrators), 2. Scaling up through the first industrial installations in the SEN-1 area, 3. Integration into system infrastructure and market mechanisms (e.g. core network and contracts for difference). Provided the demonstration projects currently planned receive funding promptly, the first offshore hydrogen projects in the SEN-1 area could become reality on a larger (pre-industrial) scale as early as the beginning or middle of the 2030s. A realistic timetable for a SEN-1 tender (for offshore hydrogen production with sub-areas of more than 250 MW) could look as follows: • tender procedure with award in 2027 • project development 2027-2030 and start of construction 2029-2030 • commercial operation (COD) in the years 2032-34. Tenders for further sites for offshore electrolysis in Zones 4 and 5 of the EEZ could take place as early as 2030. If this coordinated ramp-up succeeds — both technologically and on the market side — nothing stands in the way of successful scaling. Large-scale production in the gigawatt range would be possible from the mid-2030s. Merely waiting for "technological maturity" without an economic policy impulse, by contrast, leads to delays and competitive disadvantages as well as to a more expensive offshore expansion.
2. How advanced is the technical development, particularly with regard to integration and adaptation to offshore environments, and what dimensions are realistically achievable in the next few years? Electrolysis technology itself — particularly low-temperature processes (PEM, alkaline electrolysis) — is already regarded as commercially or early-commercially deployable onshore. For offshore deployment — that is, under demanding environmental conditions (salt water, wind- and wave-related loads, restricted maintenance access) — the first pilots and demonstrators are currently in planning (3 known projects in Germany) and under construction (e.g. in the Netherlands or France). For the next step in offshore hydrogen production in the range above 100 MW, further projects are in planning. However, commitments for these projects, including sites and financing, are still lacking. Technologically the foundations are in place, but full adaptation to offshore conditions — including the integration of electrolysis, water and electrolysis water treatment, compression, pipeline/export and maintenance — has not yet been trialled at industrial scale. The most important risks and uncertainties for offshore hydrogen production concern:
– maintenance costs in an offshore environment, where the costs of replacing central components and the costs of qualified labour for offshore deployment are unknown, • installation costs, which arise mainly for electrolysers placed on platforms. Realistic dimensions in the coming years: • Short term (2026-2028): pilot installations in the megawatt range (e.g. below 20 MW). • Medium term (approx. 2032-34): the construction and commissioning of installations in the three-digit megawatt range onshore and first offshore installations in the range of 50-250 MW are conceivable, provided regulatory, financial and technical framework conditions are right. However, these offshore installations also require a coordinated ramp-up as well as flexibility in realisation, particularly as regards scaling, penalties and the timeline. Tenders for sub-areas on SEN-1 could take place as early as 2027, with the aim of commissioning and offshore hydrogen production at gigawatt scale in 2032-34. • Long term (from approx. 2035): for offshore hydrogen at gigawatt scale the preconditions are currently still being built. Scaling depends strongly on demonstration results (including SEN-1 projects), energy infrastructure connection and cost degression. Onshore, electrolysis installations are already being realised today at scales of, for example, 100-300 MW. These projects will help to reduce risks in offshore electrolysis as well. The advantage of offshore production lies above all in the fact that cost-intensive infrastructure can be saved directly, particularly in the distant areas of the North Sea, thereby mitigating network development and overplanting problems in the electricity grid. There are two concepts for offshore electrolysis at industrial scale: (1) Electrolysers on central platforms — realisable from 2032-34. Electrolysers on central platforms are the most widespread conceptual design. Several large offshore EPC and engineering companies have publicly presented their developments on this concept. The electrolysis platform builds on experience from offshore oil and gas platforms, which follow established industry standards. Additional safety requirements for hydrogen, particularly for compressed hydrogen, mean that many of these designs are executed as platform "clusters": several platforms located close together, connected by bridges and equipped with a separate platform for safe, manned operation. The platform offers economies of scale in the balance of plant of the electrolyser, which can reduce equipment costs. By contrast, the platform costs themselves are high, since the topside is compact and has numerous complex interfaces. The observed costs of these designs are, per installed megawatt, two to three times those of a comparable onshore installation. This corresponds to experience with offshore HVDC substations (at a high level).
(2) Energy island for offshore hydrogen production and HVDC export — realisable from 2035. An energy island with electrolysers and HVDC technology is a concept in which an artificial island is built at strategically favourable locations — in relative proximity to offshore wind farms and in waters with depths of up to around 40 metres. The island has costs similar to building an HVDC converter platform, but can be enlarged more cost-effectively and can accommodate very large capacities both for electricity transmission and for electrolysis. At a scale of 1-2 GW of offshore hydrogen production and 2 GW of HVDC connection, the artificial island is cost-competitive both with offshore electrolysis on platforms and with transporting all the electricity to land with subsequent hydrogen production. The greatest advantage of an energy island is its flexible design: installations for hydrogen production, converter stations and further infrastructure elements can be built flexibly on the island. Capacities can moreover be added or removed later without changes to the underlying infrastructure (the island itself). A large-scale energy island is currently being built in Belgium (Princess Elisabeth Island) as a pure electricity island. This island provides valuable insights for the construction and installation of electrical facilities. Moreover, all technical disciplines involved in building an energy island rest on mature technologies, for instance from port extensions, coastal protection, land reclamation and foundation engineering. The construction of artificial islands has also been successfully implemented many times in the Middle East. Concept — advantages — costs — size/capacity. Central platform-based electrolysis: economies of scale in manufacture, reduced equipment costs; approximately twice the cost of a comparable onshore solution per installed megawatt; 160 to 500 MW. Energy island-based electrolysis: large capacities possible, high operational and maintenance reliability, flexible use; initial costs less relevant at large scale, competitive from 1-2 GW, can accommodate very large HVDC and electrolysis capacities (over 6 GW); from 1-2 GW up to more than 6 GW.
The system development strategy likewise recognises offshore hydrogen production as a strategically relevant option for the future energy system. Particularly as offshore wind expansion grows, offshore electrolysis enables direct
conversion into hydrogen close to the source, thereby reducing system costs, grid bottlenecks and curtailment losses.
3. What are the optimal conditions for offshore electrolysis in view of the specific offshore conditions (weather, salt water, infrastructure)? Offshore electrolysis takes place under demanding conditions, characterised by weather extremes, salt water, difficult accessibility and high requirements for materials and operational safety. Nevertheless, experience from offshore wind energy and from decades of operating oil and gas platforms shows that technology in the offshore environment is manageable and capable of development. At present offshore electrolysis is at a technology readiness level of TRL 6-7. This means that prototypes and initial demonstration systems exist but must be developed further in a targeted manner and tested under real conditions. Central development tasks here are integration into offshore platforms, protection against salt water corrosion, the treatment of seawater (desalination, pure water) and the safe handling of hydrogen under offshore conditions. Cost reductions are to be expected above all from a scale of 100 MW upwards — particularly: • in seawater treatment (large quantities of desalinated water), • in gas treatment and compression offshore, • as well as through standardisation and modularisation of the electrolysers. Comparable developments in offshore wind show that unit costs fall significantly as series production matures — even for technology that was initially challenging. Connection to combined infrastructures (electricity + hydrogen) is decisive for this. An offshore electrolyser can play to its strengths when it is embedded in an integrated overall system — for example through bidirectional electricity flows, hydrogen pipelines and sector-coupled use. As with pure offshore wind electricity generation, the following also applies to offshore hydrogen: shading and overly dense site development impede the wind yield from both technologies. An electrolyser likewise cannot produce if electricity production is restricted. Several studies from academia and practice show, moreover, that alongside the economic competitiveness of hydrogen from offshore production, the resulting reduction in curtailment can have a positive effect on the service life of offshore wind turbines — provided regulatory hurdles are removed and combined connection concepts are enabled. Beyond this, from an energy system and cost perspective it is optimal to create a contiguous, spatially adjacent cluster for offshore sector coupling, in order to increase proximity to offshore wind farms and thereby reduce the costs of inter-array cables, and to ensure proximity to infrastructure for transporting electricity and hydrogen to consumers.
4. How can the challenges arising for waste heat, seawater desalination and brine management be addressed, including from environmental and permitting perspectives? Environmental protection is a central component in the development and implementation of offshore electrolysis projects. Particularly in seawater desalination and in handling by-products such as waste heat and saline brine, efficient technical solutions must be reconciled with environmental law requirements. Offshore electrolysis requires high-purity water, produced by desalinating seawater. The waste heat arising in the process can be efficiently returned to the treatment process or used for further processes (e.g. in thermal pre-treatment). The return of brine must be arranged so that it does not lead to local salinisation and warming of marine habitats. This requires well-considered technical solutions, such as dilution systems or controlled discharge. In the water balance of PEM electrolysers, so-called drag water can contain small quantities of PFAS from the membranes. The system design must therefore ensure that this process water remains within the circuit and does not reach the marine environment untreated. In order to gain robust findings on environmental impacts and best-practice procedures, these challenges should be investigated and documented specifically within funded demonstration projects. Only in this way can a realistic benchmark be created for assessing environmental effects and technical countermeasures. The BSH should — as with other offshore technologies — define clear limit values and environmental standards for offshore electrolysis installations, for instance on brine concentration, waste heat discharge and discharge points. These standards must be integrated into existing approval procedures and create predictability for project developers. Environmental compatibility should play a role not only in permitting law but also in the award of sites. Bidders could thus score points in the tenders for SEN-1 and later for the sites in Zones 4 and 5 if they have robust concepts for seawater treatment, brine handling and waste heat use. References from comparable projects (onshore/offshore) should also be taken into account in the assessment. The environmentally sound implementation of seawater desalination and brine management is feasible — but it requires technical care, regulatory guardrails and innovative concepts.
5. What period do initial offshore demonstration projects need in order to investigate open technological questions in real operation? What funding is required? Blanket statements on the period and funding required can only be made to a limited extent, since pilot and demonstration projects in the offshore sector can pursue very different objectives and technological priorities — from electrolysis technology itself through water treatment to grid integration and operation under harsh offshore conditions. What is decisive is that only real operation in the offshore environment can deliver the findings needed to develop technology and operational safety robustly. According to their own statements, the offshore electrolysis pilot projects planned in Germany so far could begin construction immediately after receiving a possible funding and approval decision in 2026, and could deliver first results on the technological questions in real operation as early as 2027/2028. Not only technical feasibility but also the resilience of the infrastructure and environmental aspects (e.g. brine, waste heat) should be evaluated in the process. The specific funding required depends strongly on the scope, technological approach and scale of the pilot. Individual projects could lie in the double-digit million range, while integrated concepts (e.g. with wind farm, platform, electrolysis, pipeline connection) would lie considerably above that. In any case, targeted funding is important that covers construction, operation and evaluation under real offshore conditions, not only research projects in a laboratory setting. Therefore — and in order to clarify open technological questions fully in real operation — Germany should also implement demonstrators of offshore hydrogen production at industrial scale as promptly as possible, that is, projects above 250 MW. These deliver findings and validation of integrated configurations across the technologies (offshore wind, electrolysis and transport). This could take place through a swift tender in the SEN-1 area. While the underlying technologies (offshore wind, electrolysis and transport) are each well established, their combination in an offshore environment at industrial scale gives rise to complex interfaces and questions of commercial feasibility that must be tested. Demonstration-scale real projects should therefore be realised within the SEN-1 tender, provided combined connection concepts (electricity and hydrogen) are permitted in regulatory terms. Further detailed information can be found in the annex to this statement or taken from the project applications available to the Federal Ministry.
6. What capacity would corresponding hydrogen pipelines have to be able to transmit? Is a meshed system sensible? What challenges arise for hydrogen pipelines with regard to cross-border connections, parallel transport and the connection of foreign hydrogen exports and offshore electrolysis, or safety? What further challenges must be considered?
For an economically viable offshore hydrogen infrastructure, hydrogen pipelines with transport capacities in the gigawatt range (e.g. AquaDuctus in Germany, HyOne in the Netherlands) are required. Individual lines of several gigawatts are necessary in order to capture the economies of scale of offshore electrolysis. To arrange this efficiently, the legislator should define a statutorily anchored minimum capacity for offshore hydrogen production and transport, oriented towards the expansion planning of the core network. Only in this way can economies of scale in electrolysis, pipeline construction and compression be triggered early. Furthermore, in the forthcoming update of the FEP by the BSH in 2026 it is essential that changes to the Offshore Wind Energy Act — particularly on permitting combined connection concepts — be anchored in law promptly. In this way, planning options for an integrated offshore hydrogen infrastructure can be taken into account in Zones 4 and 5. The BSH should therefore either anticipate regulatory developments or be enabled to do so by a clear instruction from the Federal Ministry. Offshore energy hubs (e.g. on energy islands) moreover offer the opportunity to bundle offshore hydrogen cost-efficiently and feed it into the European infrastructure in a system-friendly manner. They create a mainland-equivalent environment at sea in which electricity and hydrogen flows can be planned and operated in an integrated way. Bundling several electrolysis or wind installations at a hub creates economies of scale in the generation, conversion and compression of hydrogen. They also enable the development of a meshed hydrogen backbone in which energy from several countries can be bundled, traded and distributed flexibly. In a meshed system, however, technological challenges such as offshore compression and pressure management must be planned early. Hydrogen must be brought to a suitable pressure level already at sea in order to be transported cost-efficiently by pipeline. The pressure level in the pipeline must be aligned with network compatibility, safety requirements and the specifications of the feed-in point. These technologies still need to be scaled in the offshore context and require targeted international coordination of national infrastructure projects. Hydrogen imposes particular requirements regarding leak prevention, material compatibility, emergency shutdown and monitoring, especially under offshore conditions. Parallel transport routes: electricity and hydrogen lines must be coordinated spatially and in planning terms, which is in turn supported by combined connection concepts. Meshed grids further increase the robustness of the energy system through redundancy and flexible alternative routes in the event of disruption. A meshed offshore system is not merely sensible. It is essential for a resilient, efficient and integrated European hydrogen ramp-up. It also allows so-called line packing in hydrogen pipelines to be used. From a systems perspective this offers considerable flexibility advantages, but from a materials engineering perspective it is closely linked to the issue of fatigue crack growth. By deliberately exploiting the pressure range between minimum and maximum operating pressure, the line is used as temporary storage (a "gas battery"). This inevitably leads to additional pressure fluctuations and thus to cyclical stress on the
pipe wall. For steel pipelines carrying 100 % hydrogen this means that not only classical pressure-cycle fatigue must be taken into account, but also hydrogen-assisted fatigue crack growth. Hydrogen can embrittle the crack tip zone, increase crack propagation rates and thus considerably reduce service life compared with pure natural gas operation. Simply adopting design rules from natural gas networks is therefore not sufficient. In designing an offshore hydrogen pipeline system, the planned line-pack use must be explicitly incorporated into the fatigue assessment. This includes a realistic estimate of the number and amplitude of pressure cycles (operation, operating regime of electrolysers, network bottlenecks) as well as an assessment of crack growth under the influence of hydrogen on the basis of suitable material parameters (da/dN curves in hydrogen). Safety factors and inspection intervals are to be adjusted accordingly. From an operational perspective this means that the available line-pack latitude must not be optimised solely according to systemic flexibility (e.g. intraday storage) but always stands in a field of tension between the gain in flexibility and additional fatigue loading. Conservative management of minimum pressure, maximum pressure swing and compressor operating regime helps to limit the risk of accelerated fatigue crack growth. For offshore lines of great length and difficult accessibility, such an integral consideration of line packing and fatigue is essential for an acceptable service life risk. Cross-border (offshore) hydrogen infrastructure is not a distant prospect — it is already being concretely prepared, for instance through joint projects between Germany, Denmark and the Netherlands. In regulatory terms, however, coherent, integrated electricity and hydrogen regulation is required. This should be created swiftly. A first milestone would be the North Sea Summit 3 on 26 January in Hamburg. The aim must be a European harmonised legal framework that conceives offshore hydrogen production, transport and offtake as an integrated overall system.
B. Costs / financing. 1. What costs are to be expected for generating hydrogen at sea, and what costs for transport at sea and on land? To what extent does offshore electrolysis entail additional costs compared with onshore electrolysis (for maintenance, infrastructure, water desalination, further equipment) as against cost reductions through higher utilisation and system integration? The costs of hydrogen generation at sea — particularly for long-term considerations — are currently still subject to considerable uncertainty, since there are as yet no industrial reference installations under offshore conditions. Figures for absolute production costs are therefore highly speculative. More decisive for the planning process, however, is not the absolute level of costs but the relative cost comparison between offshore and onshore electrolysis. Here several studies show that electrolysis at sea delivers immense cost savings through reduced electricity grid expansion while at the same time creating a further calculable source of revenue for offshore wind operators in the form of hydrogen. A robust approach to estimating the premium for offshore electrolysis can be found in the E-Bridge study "Assessment of connection concepts for distant offshore wind areas in the German North Sea for an efficient energy transition". On the basis of information from experienced offshore wind operators, it assumes a cost premium of around 70 % compared with onshore electrolysis installations in the years after 2035. This premium reflects in particular higher maintenance and servicing costs, the necessary offshore seawater desalination, structural complexity and additional safety requirements at sea. The prerequisite for this is the coordinated and step-by-step ramp-up of the technology. At the same time, a further study by Frontier Economics shows that offshore electrolysis is economically sensible even at a premium of up to 100 % over onshore electrolysis, provided the higher utilisation rates (e.g. more than 5,000 hours per year) and the system integration effects of combined connection concepts are realised. The costs of hydrogen transport — both offshore and onshore — are not a purely hypothetical factor but are already accounted for in the regulatory framework: they are covered by the ramp-up charge for the hydrogen core network (including offshore connections) and are publicly accessible via the Federal Network Agency. These network charges include, among other things, the construction and operation of the AquaDuctus offshore pipeline. Additional transport costs for offshore hydrogen therefore do not arise in isolation but are systemically integrated. Decisive for the development of competitive offshore hydrogen costs is not only technical progress but also targeted political framework-setting, in particular: funding of demonstration projects, SEN-1 tenders and the permitting of combined connection concepts that enable the simultaneous use of electricity and hydrogen infrastructure and thereby lower costs. With targeted funding and an intelligent tender architecture, these uncertainties and supposed additional costs can be reduced and scaled step by step. Regarding technical implementation, the body of studies shows that considerable cost savings are possible for offshore hydrogen production above 1 GW if production is enabled on offshore energy hubs.
2. Are generation and transport refinanceable at current market prices for hydrogen? What funding is required? Under today's market conditions, full refinancing of offshore hydrogen projects without targeted funding is currently not possible. However — as was also the case for offshore wind in its early phase — this does not contradict the long-term economic prospects of the technology. Today's market prices for hydrogen reflect neither the actual macroeconomic advantages nor the market development to be expected in the medium term. The price range for hydrogen is currently very wide and depends on many external factors such as the carbon price, fossil alternatives, the geopolitical situation, industrial demand and regulatory framework conditions. A reliable market price basis for investment decisions does not currently exist. A robust market price for green hydrogen — particularly from offshore wind — does not currently exist. The uncertainties surrounding the design and recognition of RFNBO criteria, as well as the absence of offtake contracts with clearly defined willingness to pay, considerably complicate bankable refinancing. There is therefore a structural funding requirement, particularly for large-scale offshore projects. Alongside funding instruments for generation and offtake, the build-up of a functioning hydrogen transport system ("midstream") is decisive for bankability. The role of independent midstream actors — as set out in the discussion paper by BET and SEFE — should be promoted in regulatory terms in order to create investment certainty and functioning interfaces between generation and demand. Since the costs are not currently fully refinanceable, initial funding is necessary. The generation of hydrogen at sea and its transport via hydrogen pipelines is currently not economic without state start-up financing. Permanent subsidy is not, however, the aim — rather, the point is to enable the necessary market ramp-up and cost degression through targeted funding. The focus should be on system integration and scaling, not on short-term price comparisons. Offshore hydrogen can thereby make a load-bearing contribution to the energy transition in the medium to long term — economically, ecologically and in terms of security of supply. In addition, there are as yet hardly any market-effective incentives on the demand side, particularly for the offtake of hydrogen from offshore generation. As a result, the economic refinancing of offshore hydrogen projects — including transport infrastructure — is currently not feasible without targeted funding. Cost degression presupposes scaling, however: as offshore wind shows, costs fall significantly only through step-by-step expansion and industrial scaling. This development can also be expected for offshore hydrogen, particularly through serial manufacture of electrolysers, optimised offshore platform designs (including offshore hubs) and learning curve effects in operation and maintenance. Funding is therefore a lever for economies of scale, not a permanent substitute for market revenues. A purely isolated view of offshore hydrogen also falls short. What is decisive is the role of offshore electrolysis as an enabler of cross-sectoral system integration. Surplus, curtailed or particularly cheap electricity from offshore wind can be converted into hydrogen by electrolysis and made usable flexibly in time and space. This contributes to relieving the grid, to security of supply and to climate neutrality. An assumption for the cost development of hydrogen (onshore and offshore) follows from the study on hydrogen generation costs by Öko-Institut and Deloitte of June 2025. It estimates hydrogen production costs of under EUR 3 per kilogram (approx. EUR 90 per MWh) where system-integrated electricity prices are used. Offshore wind, too, did not emerge without funding. Offshore wind energy depended on comprehensive support in its early phase but has today reached near market maturity in many markets. Offshore hydrogen can undergo a comparable development, provided the right political course is set today.
3. What advantages do business models offer that aim at the combined marketing of electricity and hydrogen? Please describe the business case. Business models with combined connection concepts (electricity + hydrogen) enable offshore wind farm operators to market electricity and hydrogen in parallel. This creates a second revenue pillar alongside the classical sale of electricity. This additional source of income through hydrogen generation increases the economic viability and resilience of a project — particularly in the face of fluctuating electricity prices or grid constraints. Such models make an active contribution to genuine market integration, as is also called for in connection with the Federal Ministry's monitoring report. Instead of rigid feed-in to the grid, it is possible to switch flexibly between electricity and hydrogen production, depending on the grid situation and market conditions. The E-Bridge study and the Frontier Economics study commissioned by AquaVentus show clearly that combined connection and marketing concepts are economically attractive, since they enable higher full-load hours and greater flexibility. This offsets the challenges posed by increasing low-price and negative-price hours, particularly for operators of offshore wind farms. Based on the electricity price forecasts for Germany by the consultancy AFRY, from 2040 around 9 % of all production hours will lie below EUR 0.02 per MWh. These figures relate to the electricity market system and to the fact that the correlation between low electricity market prices and offshore wind electricity production will be very high. This inevitably makes it more difficult to present an economic incentive for electricity offtake without state support, for example via contracts for difference or attractive power purchase agreements. Introducing hydrogen production into the offshore wind business case can therefore represent an attractive increase in value for the system as a whole. The offshore wind farm can sell electricity at high prices either via CfD-supported mechanisms or via power purchase agreements while at the same time earning revenue from electrolysers during low-price hours.
By placing the electrolysis close to the generating installation ("behind the meter"), offshore wind electricity that would otherwise have to be transported to land is used efficiently. Offshore hydrogen production is particularly sensible where electricity would have to be transported more than 100-150 km from the mainland. The grid savings on land and offshore arise from the possibility of "oversizing" offshore wind and electrolysis capacities relative to the HVDC connection. The HVDC line is thereby better utilised and the onshore grid need not be designed for peak load hours but can be planned and built for more even production from the offshore wind farm. Additional revenue paths and flexibility lower the socio-economic investment risk — which in turn will reduce the funding required. This does, however, require that the savings be allocated in such a way that offshore wind farm operators have an incentive to expand offshore electrolysis, so that a private-sector incentive arises for offshore wind farm operators to install the electrolyser offshore. In perspective, offshore hydrogen projects could even compete with onshore projects within the same funding regime, which would reduce complexity in the funding landscape — as, for example, in the stalled tender for system-friendly electrolysers under Section 96.9 of the Offshore Wind Energy Act. Here too, combined business models in the onshore sector will close the gap, through market-friendly, technically realistic and economically viable structures. In addition, unused volumes from onshore wind and photovoltaic installations could be utilised in offshore electrolysis hubs where these have free capacity because of low wind availability. The prerequisite for this is a bidirectional transport and conversion capability, which is enabled only by combined connection concepts.
4. How many operating hours are required for economic operation? Can a business model also be based on electricity volumes subject to peak shaving? A business model geared exclusively to peak-shaved electricity volumes does not currently appear economically viable. For the economic operation of electrolysers — particularly offshore — a high number of full-load hours (operating hours) is advantageous. According to the study by Frontier Economics commissioned by AquaVentus, an electrolyser utilisation of around 60 % can be achieved where market integration takes place. That corresponds to roughly 5,000 to 5,300 hours per year —
considerably more than would be achievable through peak shaving of 20 % alone. Relying solely on electricity volumes arising from peak shaving is therefore not sufficient to build a viable business model for hydrogen production. These electricity volumes arise in a volatile and unplannable manner, and the resulting low utilisation of the electrolysers leads to high specific production costs as well as a high capital lock-up risk. Oversizing the offshore wind capacity relative to the HVDC capacity is part of the configuration of offshore sector coupling. The precise degree of this oversizing depends on the configuration of the offshore sector coupling but will be considerably greater than in a pure electricity overplanting scenario. A future-proof business model must therefore rely on system integration: through bidirectional electricity connections that permit flexible use of electricity surpluses; through connection to offshore hubs or energy islands that can bundle electricity and hydrogen and distribute them as needed; and through combined connection concepts that enable a flexible choice between marketing electricity and marketing hydrogen. These approaches enable not only higher technical utilisation of the electrolysers but also market-integrated use of the hydrogen generated — a central criterion for economic viability and scaling.
C. Planning and regulation. 1. From when should sites for offshore electrolysis be tendered in the other energy generation area SEN-1? When should further sites for hydrogen generation be tendered, if applicable? The SEN-1 area should be tendered from 2027 onwards and used as the first site for offshore electrolysis, in a step-by-step and staged manner. Tendering sub-areas makes it possible to realise further demonstrators of industrial ambition and to gather important experience for planning, permitting, construction and operation under offshore conditions. This staged award supports a trial-based, scalable development — in line with the technological triple jump of the AquaVentus concept (demonstration – scaling – integration). The SEN-1 area should therefore be retained as the first, staged test site, in the spirit of the AquaVentus triple jump. The results of the planned demonstration projects should be closely interlinked with the further development of sites. Nevertheless, additional SEN areas in the more distant Zones 4 and 5 should already be taken into account today in the Site Development Plan (FEP). Their tendering could take place shortly after the first SEN-1 site, as early as 2030. This creates planning certainty for investors early on and permits targeted preparation (grid, logistics and cooperation). These sites should likewise be geared to combined connection concepts (electricity + hydrogen) and lie in spatial proximity to the planned AquaDuctus pipeline. With a view to the forthcoming update of the FEP by the BSH in 2026, it is essential that changes to the Offshore Wind Energy Act — particularly on permitting combined
connection concepts — be anchored in law promptly. Otherwise there is a risk that no planning options for an integrated offshore hydrogen infrastructure will be taken into account in Zones 4 and 5. The BSH should therefore either anticipate regulatory developments or be enabled to do so by a clear instruction from the Federal Ministry. Alongside a direct tender for electrolysers, the SEN-1 area could also be used as an optimisation site for surrounding wind farms — for instance through the targeted conversion of surplus electricity into hydrogen in the event of curtailment. The prerequisite for this is combined connection concepts that are permissible in regulatory terms. Offshore wind farm operators could plan and establish the connection to the central electrolysis themselves. The strict separation hitherto between wind sites and areas on the one hand and SEN areas on the other is becoming increasingly obsolete in practice. What matters in future is which infrastructure arises where — not how a site was originally classified. Combined electricity and hydrogen solutions should also be enabled in classical wind sites in spatial proximity to AquaDuctus, where this is technically sensible and system-friendly.
2. What concepts are conceivable for offshore hydrogen generation in future? Future offshore hydrogen generation should be conceived and set up in a technology-neutral, system-friendly and market-integrated way. It is decisive that different concepts be enabled, trialled and subsequently scaled — embedded in an industrial roadmap and a long-term infrastructure build-out. One forward-looking concept is offshore energy hubs or energy islands, on which electrolysers can be operated at large scale, infrastructure is bundled (wind, electricity, hydrogen, possibly CO₂) and system advantages arise (grid relief, flexibility, security of supply). These hubs create a mainland-like environment at sea in which different technologies can be combined modularly and networked with European partners — particularly in the context of a meshed European offshore grid. The SEN-1 area offers the possibility of realising first projects while at the same time gathering technological and regulatory experience. A step-by-step tender in sub-areas makes it possible to realise demonstrators of industrial ambition. Combined connection concepts (electricity + hydrogen) should be explicitly enabled in order to ensure flexible market participation and cross-sectoral integration. Future concepts should deliberately be kept technology-neutral. This diversity makes it possible to implement the most efficient model in each case, depending on location, depth, distance from the coast and grid situation. The award of sites for future projects should be closely linked to the planning of the offshore hydrogen infrastructure (AquaDuctus). Only through this correlation between site development and transport infrastructure can costs be lowered, risks minimised and investment certainty created. Further SEN areas in Zones 4 and 5 should likewise be identified early in the Site Development Plan (FEP).
3. What permitting questions arise from the operator's perspective for the overall projects, and what adjustments to the Offshore Wind Energy Act would be required from the sector's perspective? For the implementation of offshore hydrogen projects, a central prerequisite from the sector's perspective is that combined connection concepts of submarine cables and hydrogen pipelines — that is, electricity and hydrogen infrastructure within one project — be explicitly permitted in law. A clarifying adjustment in the course of the forthcoming amendment is necessary in order to create investment certainty — particularly for projects in the SEN-1 area and in suitable wind sites beyond it. The AquaVentus Förderverein can make concrete drafting proposals available for the legislative amendment. A central permitting issue for operators accordingly concerns the question of decision-making authority over the use of the energy generated. May the offshore wind farm operator decide itself, in a market-integrated manner, whether the electricity generated is fed in or converted into hydrogen on site? Or are there restrictive requirements imposed by network operators, regulatory authorities or the legislator? From the sector's perspective a flexible, market-oriented (electricity-price-dependent) mode of operation is essential: only in this way can economic business models be realised that capture cost savings in the energy infrastructure and ensure electricity-price-led system benefit. AquaVentus therefore proposes the following concrete adjustments to the Offshore Wind Energy Act as four packages of measures: (1) Expansion targets for electrolysis (other energy generation installations under the Ordinance on Other Energy Generation Areas, SoEnergieV) and implementation in the FEP. Under the Offshore Wind Energy Act, the offshore wind turbines relevant to achieving the expansion target (70 GW by 2045) are to be connected to the electricity grid (Section 1(2) WindSeeG), i.e. offshore wind turbines connected to offshore electrolysers but not to the electricity grid are not counted towards the 70 GW target. In order to achieve an optimised expansion of offshore wind energy that lowers investment and system costs and contributes to an efficient use of the available sites, targets for optimised offshore hydrogen production in the German EEZ should be set. For example, 10 GW of offshore hydrogen production capacity through electrolysers (other energy generation installations) by 2045 at the latest could be formulated as a target, and offshore wind turbines that are (also) connected to offshore electrolysers could be counted towards the existing expansion target for offshore wind energy. These targets would have to be regulated in the Offshore Wind Energy Act and then implemented in the FEP. (2) Introduction of combined (hybrid) connection concepts, i.e. a grid connection for offshore electrolysers, and introduction of sector coupling tenders. The electricity connection of electrolysers for offshore hydrogen production should be permitted in law. This creates the flexibility, depending on electricity demand and supply, to feed electricity into the grid or to draw electricity from the grid for hydrogen production. The electricity grid connection of electrolysers helps to increase the efficiency of the existing energy system, since fewer transmission facilities are used more efficiently
(through higher utilisation) and the curtailment of offshore generating installations is reduced. This in turn leads to lower energy costs for consumers. We therefore propose that future tenders for offshore wind turbines in Zones 4 and 5 take the form of so-called "sector coupling tenders", i.e. that future offshore wind turbines can be connected both to the electricity grid (even if only with a share of their capacity) and to offshore electrolysers. Such a combined (hybrid) connection concept can help to meet part of the future demand for green hydrogen and to capture the cost reduction potential in the offshore grid. It also implements the demand set out in the current coalition agreement. (3) Clarification of technology-neutral usability. In order to promote cost-efficient offshore hydrogen generation, the new legal framework should contain a clarification that the structural implementation of offshore electrolysers can take place on a technology-neutral basis. Market participants would thereby be enabled to develop the most cost-efficient solution for hydrogen generation at each location. We therefore propose supplementing the Offshore Wind Energy Act by way of clarification to the effect that offshore electrolysers may also be built on artificial islands. (4) Adjustment for the legally secure implementation of the AquaDuctus pipeline. For the AquaDuctus hydrogen pipeline there are currently legal uncertainties under the Offshore Wind Energy Act, since it applies only to the section connecting SEN-1 and not to the onward import section within the EEZ. The pipeline, however, fulfils a dual function — connection and import — which currently necessitates two permitting regimes (the Offshore Wind Energy Act and the Federal Mining Act). This division is not appropriate and could lead to delays. In order to increase planning certainty and accelerate procedures, the Offshore Wind Energy Act should be adjusted so that it also applies to cross-border import lines and to the entire course of AquaDuctus within the EEZ. This includes changes to the scope of application (Section 1 WindSeeG) and placing the transport infrastructure on an equal footing with wind farms and connection lines in terms of overriding public interest. In addition, the Federal Administrative Court should be designated as the court of first instance for permitting procedures relating to this infrastructure — by analogy with other line construction projects.
D. Scaling. 1. How would the step-by-step expansion of offshore electrolysis have to be supported and flanked politically in order to enable industrial scaling in the medium term?
The successful expansion of offshore electrolysis requires a systematic, politically flanked ramp-up strategy oriented towards the technological triple jump, as set out for instance in the E-Bridge study (Figure 42, p. 73). In the demonstration phase (T₀ to T₀+5 years), a start is made with 1-3 pilot projects in order to test operation under real offshore conditions. The objectives are to trial technical interfaces, water treatment, operational safety, maintenance and grid integration of the offshore electrolyser. This requires targeted project funding and regulatory latitude (permitting, environmental standards, market integration). The SEN-1 scaling phase (T₀+6 to 10 years) then follows, with SEN-1 as the first large-scale tender of offshore electrolysis in combination with offshore wind. The objective must be to establish 1 GW of electrolysis capacity as a building block of an industrial ramp-up. This requires a clear allocation of sites with combined connection concepts and suitable funding instruments. For the market ramp-up and market integration (from T₀+10 years), tenders for further sites (in Zone 4 or 5) and the parallel expansion of the infrastructure (AquaDuctus) are necessary. Such tenders can take place soon and in combination with the allocation of sites in Zone 4. For the implementation of the technological triple jump — the roadmap for the step-by-step scaling of offshore hydrogen production — it is essential that the first two steps be politically flanked and specifically supported. Both the pilot projects (step 1) and the demonstrators in the SEN-1 area (step 2) form the technological and regulatory basis for the later industrial ramp-up, which should manage without permanent subsidy. In all of this the starting point T₀ is decisive. The earlier the pilots and demonstrators are initiated, the earlier scaling can take place. The following political measures are necessary for the step-by-step expansion: 1. Regulatory opening in the Offshore Wind Energy Act: permitting combined connection concepts (electricity + hydrogen) in the SEN-1 area and in Zones 4 and 5 of the EEZ. 2. Funding of pilots and demonstrators in order to cushion the initial additional effort and innovation risks. 3. Setting an expansion target for offshore electrolysis (e.g. 10 GW by 2045) in order to create planning and investment certainty. 4. Integrated infrastructure planning (sector coupling, energy islands, hydrogen transport, AquaDuctus) with European coordination. Scaling is built on experience. Onshore electrolysers therefore also deliver important technical and economic reference values. This experience can be transferred to offshore applications — with the necessary adaptations to a saline environment, higher maintenance costs and different operating conditions. At the same time, offshore wind enables a considerably higher utilisation of the electrolysers (more than 5,000 hours per year), which can lead to better economies of scale and economic viability in the long term.
2. What challenges do you see in training skilled workers for the construction, operation and maintenance of offshore hydrogen installations? From the sector's perspective, securing skilled workers in the field of offshore hydrogen is less a challenge than an opportunity for Germany as a technology location. All the necessary competences and resources already exist in the country — whether in offshore wind energy, in classical mechanical and plant engineering (including the construction of offshore electrolysers) or in the process industry. Added to this are excellent references from the European offshore oil and gas industry, which has decades of experience in building, operating and maintaining complex installations under maritime conditions. The offshore wind sector has already successfully established training, instruction and safety standards that can now be transferred to offshore hydrogen production with comparatively little adaptation — for instance in platform operation, corrosion protection, subsea technology or remote monitoring. Developing a targeted qualification strategy (e.g. via existing education clusters, chambers of industry and commerce, technology consortia or university programmes) can moreover help early on to define new occupational profiles along the entire value chain — from planning and construction through to maintenance — and to fill them with life. Germany brings all the prerequisites for successfully building the skilled-worker base for offshore hydrogen installations — building on existing competences from offshore wind, onshore electrolysis (mechanical and plant engineering) and the maritime industry. The challenge lies not in a shortage but in coordination. Here lies the opportunity to shape an attractive future labour market with foresight and a clear roadmap. This is precisely where the AquaVentus Förderverein sees its role, supporting its member companies and the sector.
3. What role does offshore electrolysis play in a cost-optimal overall electricity and hydrogen system in 2045, particularly compared with purely electrical transport at sea? Offshore electrolysis can play a central role in 2045 in a cost-optimal and integrated overall energy system — not as a replacement for, but as a system-friendly complement to, the electrical connection. Its advantages lie in optimising grid infrastructure by reducing expansion costs in the distant areas of the EEZ, in sector coupling as a way of increasing offshore wind farm operators' revenues, and in market integration. By converting electricity into hydrogen already at sea, offshore electrolysis can help to reduce grid bottlenecks, since not all energy has to be transported through power lines. This permits better use of wind energy potential and a more flexible response to grid and market signals, particularly during load peaks or curtailment, coupled with considerable cost saving potential. Integrated offshore hydrogen generation promotes sector coupling directly at the site of
primary energy generation — an important building block for the resilience and efficiency of the energy system. The economic advantages are borne by cost savings in the overall system and by integration into the existing electricity market. Several studies demonstrate the significant economic advantage of an offshore hydrogen strategy compared with a purely electricity-based approach: according to a study by E-Bridge of September 2024, an overall system with offshore electrolysis is up to EUR 31 billion cheaper in net present value than a purely electricity-based scenario up to 2045. The Frontier Economics study of November 2025 shows savings of EUR 1.7 billion annually where offshore hydrogen is integrated. International studies such as that of the North Sea Wind Power Hub consortium or analyses by Fraunhofer IEE likewise underline the systemic relevance and economic viability of offshore electrolysis in interplay with trans-European infrastructures. For offshore wind farm operators, offshore electrolysis opens up the possibility of additional marketing via two paths: electricity and hydrogen. This broadening of revenue and spreading of risk is a decisive lever for investment decisions and strengthens market integration in line with the second key measure called for by the Federal Ministry in connection with the publication of the monitoring report. Offshore electrolysis is not only a solution for German needs but also a building block for cross-border energy strategies, for instance through hydrogen exports or as part of a meshed grid system. It is thus a strategic element of European energy policy, particularly in cooperation with the North Sea riparian states. Offshore electrolysis is therefore an integral component of a cost-optimal energy system in 2045. It reduces grid costs, increases system flexibility, creates new revenue models for operators and supports the cross-sectoral integration of wind energy — with demonstrated savings potential in the billions. It should therefore be conceived as strategically equivalent to the electrical connection and must accordingly be promoted politically.
2) Market integration and tenders. The AquaVentus Förderverein welcomes the engagement with the future market integration and design of the tendering mechanisms for offshore wind and hydrogen. As with point 1.1, we do not answer the individual questions in detail. Instead we would like to point to fundamental aspects that are central from the perspective of the offshore hydrogen industry.
Market integration. First of all it must be ensured that the expansion of offshore wind energy in Germany continues without interruption. Without a stable expansion pathway for offshore wind, a ramp-up of offshore hydrogen production is not realistic. Conversely, the offshore wind industry needs the long-term prospect of hydrogen utilisation in order to remain economically viable even at a higher level of expansion. Both sectors depend on one another and should therefore be considered jointly in the tendering system and in site planning. The successful market integration of offshore hydrogen projects requires a balanced auction design that offers investment certainty while also permitting market-based options. A two-sided contract for difference can be a central instrument here for hedging against price fluctuations, but must not become a permanent subsidy. It is decisive that contracts for difference be designed competitively — for instance through dynamic auctions and limits such as "one lease per bidder" — in order to avoid market distortions. In addition, a one-off opt-out from the contract for difference should be made possible in order to realise long-term power purchase agreement models. This option should, however, be designed without a right of return ("no opt-in") in order to ensure predictability and market responsibility. If a project chooses the opt-out, it must be ensured in regulatory terms that the generation of guarantees of origin and RFNBO-compliant certification are legally secure. This requires clear rules and a transparent certification pathway. Cross-subsidisation of non-competitive concepts via the levy must be avoided. Even with possible carve-outs for offshore hydrogen projects, the logic of the auctions must not be undermined: the award should continue to be made on the basis of the lowest CfD strike price, in order to keep efficiency and system costs in view.
Tenders. A prompt start of tenders for offshore hydrogen projects from 2027 — particularly on the SEN-1 site and in suitable wind sites with combinable connection concepts — is necessary in order to realise initial economies of scale. In this, the use of electricity volumes under Section 13k of the Energy Industry Act should be taken into account, as should clear rules on the definition of peak shaving and on the permissible use of the energy volumes arising from it. Electricity procurement criteria from EU Directive 2023/1184, as part of the 37th Federal Immission Control Ordinance — such as the limitation of the day-ahead price to EUR 20 per MWh or the price relation to the carbon certificate price — are helpful anchors here. Legally secure interpretation and application must be ensured. Regarding the design of tenders, AquaVentus recommends a technology-neutral design that also permits concepts such as offshore hubs or islands. Competition between different infrastructure concepts — for instance platform solutions as against island-based approaches — should be expressly enabled. In order to be able to provide the transport infrastructure in good time, targeted advance investment in hydrogen pipelines is unavoidable. Beyond this, the introduction of regulatory overplanting obligations (e.g. 20 % overplanting across the board) should be avoided. This can in the end even be counterproductive to the original objective if compensation payments to offshore wind farm operators become due as a result. Instead, incentives for system-friendly overplanting should be set through the auction design, making both grid connections and site use more efficient. In order for combined electricity and hydrogen connections in Zones 4 and 5 to be realised in perspective, the Offshore Wind Energy Act must now be adjusted accordingly, and this adjustment must already be taken into account in the FEP planning (presumably in 2026) by the BSH. Only in this way can the BSH plan the sites in the FEP with foresight — either by anticipating the legislative change or through a clear instruction from the Federal Ministry. Such a model would help to preserve the necessary degrees of freedom in planning and project development without having to commit early to a particular use. At the same time it opens up room for integrated infrastructure approaches, such as combined connection concepts with electricity and hydrogen lines. Tenders could accordingly be designed so that bidders can offer combined concepts or optionally retrofittable hydrogen pathways alongside classical wind projects. This would strengthen the dynamics of innovation in the market and enable a step-by-step scaling of the offshore hydrogen industry — with efficient use of sites and forward-looking infrastructure planning at the same time. In sum it is central that the future tendering and market structure be designed not only for the pure marketing of electricity but that it consider and enable the integration of offshore hydrogen from the outset. The AquaVentus Förderverein is glad to be available as a partner for the further development of these approaches.