AquaVentus Förderverein e.V. represents member companies along the entire offshore hydrogen value chain with the aim of developing offshore wind energy and offshore electrolysis as complementary building blocks of an integrated North Sea strategy, and took part in the joint market survey of the transmission system operators (TSOs) and the gas and hydrogen transmission network operators with a cut-off date of 13 March 2026.
This statement addresses guiding questions 1, 15, 16 and 25 of the accompanying document of August 2026. AquaVentus comments separately in the same proceedings on the corresponding passage in the draft Gas and Hydrogen Scenario Framework (chapter 3.3.2.2, p. 95).
The key points:
– The statement that SEN-1 is “planned without a connection to the public electricity grid and therefore not relevant for power system modelling” (p. 61, note on figure 21 on p. 62) is factually incorrect.
– Classifying combined development concepts as a perspective “beyond the 70 GW target” (p. 82 f.) misses the point: the assessment by overall system efficiency and infrastructure costs that the TSOs themselves call for is only possible within the 70 GW – and that is where the benefit is greatest.
– The draft anticipates future law in two places – when crediting capacity from neighbouring EEZs and for offshore overbuilding. It does not do so for offshore electrolysis, although the legislative process is further advanced there.
– Offshore electrolysis opens up a second revenue stream for offshore wind farm operators and, through bidirectional use of the expensive electricity infrastructure, substantially increases its utilisation.
1. Correction required: SEN-1 is planned with a grid connection (on question 15)
Passages concerned
Chapter 3.4 “Hydrogen and electrolysers”, p. 61:
“It should be noted that the electrolysis capacity shown in the scenarios includes one offshore electrolysis project (SEN-1) in each case, which is planned without a connection to the public electricity grid and is therefore not relevant for power system modelling.”
Note on figure 21, p. 62:
“Offshore electrolysis projects without a connection to the public electricity grid are not allocated to any federal state.”
Facts
The statement confuses two matters. It is correct that no dedicated offshore grid connection system (ONAS) is provided in the site development plan for the other energy generation area SEN-1 – the draft itself states this on p. 82. It does not follow, however, that SEN-1 is planned without a grid connection.
The connection concept of SEN-1 is hybrid:
– The hydrogen is transported via the AquaDuctus hydrogen pipeline, part of the hydrogen core network.
– The electrical connection runs via the electrical infrastructure of the neighbouring converter platform of ONAS NOR-10-1. This is precisely why a dedicated ONAS is not required – an efficiency feature of the concept, not a renunciation of the grid connection.
– The project is structured in four tranches of 250 MW each of modular PEM electrolysis (up to 1 GW); tranche 1 targets commissioning in 2033.
– Establishing the grid connection by the responsible TSO is a prerequisite and the subject of ongoing coordination. The project data were reported in the joint market survey of 13 March 2026, including 1 GW of offshore wind capacity.
Effect on modelling
Classifying the project as “not relevant for power system modelling” has three consequences:
First, it creates an inconsistency in the draft's own figures. According to the TSOs, SEN-1 is part of the electrolysis capacity shown in table 11, but its electricity demand is not part of the modelled load. According to the joint electrolyser list, SEN-1 enters the joint scenario with 1,000 MW and the status “design planning” and is included in Scenario Path B at 50 percent, i.e. around 500 MW; in Paths A and C according to project progress. This capacity is contained in the electrolysis capacity shown, but not in the modelled electricity consumption.
Second, the flexibility potential is lost. An offshore electrolyser on a bidirectionally usable subsea cable works in both directions: when wind output is high it absorbs generation that would otherwise have to be curtailed or transported via the cable; when wind output is low and prices are low it draws grid electricity. The draft already reflects exactly this mode of operation for onshore electrolysers (p. 60: fully flexible, marginal-price-driven operation, adjustable in congestion management). For offshore electrolysers it is excluded without justification. The technology used is decisive here: SEN-1 is designed as PEM electrolysis. PEM plants are load-following, efficient in part-load operation and, offshore, the more economical option because of their high power density and lower space and weight requirements – and thus both system-serving and cost-efficient. In this they differ fundamentally from chlor-alkali electrolysis, mentioned in the same paragraph, a continuously operated industrial process that is rightly treated as base load. Removing both from electrolysis modelling in the same breath fails to recognise this difference.
Third, the demonstration purpose is undermined. SEN-1 is the only project that can measure the effect of offshore electrolysis on ONAS demand, cable utilisation and curtailment under real conditions within this decade – in time for the connection decisions on zones 4 and 5.
Proposed wording (replacing the paragraph concerned on p. 61)
“It should be noted that the electrolysis capacity shown in the scenarios includes one offshore electrolysis project (SEN-1) in each case. No dedicated offshore grid connection system is provided for this project in the site development plan; according to the reported project concept, the electrical connection is planned via the electrical infrastructure of the neighbouring offshore grid connection system NOR-10-1, and the hydrogen produced is transported via a hydrogen pipeline. The project is therefore relevant for power system modelling and is taken into account as a load at the associated grid connection point. In line with the reported technology, it is modelled as PEM electrolysis with fully flexible, marginal-price-driven operation, analogous to the other electrolysers. In the grid development plan, the TSOs will also examine to what extent bidirectional use of the connection changes the operation of the electrolyser and the utilisation of the offshore power transmission infrastructure. To be distinguished from this is the chlor-alkali electrolyser, also included, whose electricity demand as a continuous industrial process is already taken into account by the TSOs in modelling the existing industrial load.”
Proposed wording (replacing the note on figure 21, p. 62)
“Note: Offshore electrolysis projects are not allocated to any federal state. Their electricity demand is taken into account via the grid connection point of the associated offshore grid connection system.”
If the draft maintains its classification, the approved scenario framework should state which capacity is excluded from power system modelling and on what basis the assumption of a missing grid connection rests.
2. Offshore electrolysis must be considered within the 70 GW target, not beyond it (on questions 1 and 25)
Passage concerned
Chapter 4.2, section “Offshore electrolysis”, p. 82 f.:
“In the TSOs' view, the potential benefit of this concept may arise in the long term, particularly with a view to developing offshore wind energy beyond the statutory offshore expansion target of 70 GW. In principle, the respective usage options must be carefully weighed in the course of further development, taking into account overall system efficiency and infrastructure costs.”
AquaVentus shares the second sentence: the usage options must be weighed by overall system efficiency and infrastructure costs. It is precisely this assessment, however, that the first sentence prevents, because it is only possible within the 70 GW pathway.
Why the assessment is only possible within the 70 GW
An assessment requires a reference case. This exists only within the statutory expansion target: for the far-offshore sites of zones 4 and 5, which must be developed to reach 70 GW, site planning, ONAS planning and cost assumptions are available. Only against this reference case can it be quantified how a combined connection concept of subsea cable and hydrogen pipeline affects infrastructure needs, system costs and efficiency. Beyond 70 GW there is no adopted expansion pathway, no grid planning and no cost basis – the required assessment cannot take place there methodologically.
Added to this is the timing. The connection decisions for zones 4 and 5 are made in this and the following grid development plan cycle; lead times for HVDC systems are around seven years. An assessment deferred to the “long term” takes place after the infrastructure decisions have been made. The deferral is therefore itself a pre-determination.
The empirical evidence contradicts the classification as a perspective beyond 70 GW
In its study “Efficient integration of offshore wind energy through offshore hydrogen production” (November 2025, commissioned by AquaVentus), Frontier Economics concludes that offshore sector coupling reduces the net infrastructure costs of offshore integration by around EUR 1.7 billion per year in the 70 GW scenario and by around EUR 0.5 billion in the 55 GW scenario. The direction of this difference is decisive: the advantage is considerably greater in the 70 GW scenario than in the more conservative pathway, because offshore hydrogen is particularly valuable precisely for integrating the last, most remote gigawatts. The benefit of combined development concepts therefore does not arise only beyond the statutory target, but increases as that target is approached.
Other AquaVentus lead studies reach the same finding: E-Bridge Consulting (September 2024) puts the savings of combined transport and connection concepts compared with a pure HVDC pathway at up to EUR 31 billion; Fraunhofer IEE (September 2024) confirms the systemic advantages of hybrid offshore infrastructure in the European context.
The statutory target covers grid-connected capacity – and hybrid concepts are grid-connected
Section 1(2) of the Offshore Wind Energy Act (WindSeeG) expressly relates the expansion target to “the installed capacity of offshore wind turbines that are connected to the grid”. This is exactly why combined development concepts belong in the 70 GW pathway: a hybrid-connected offshore wind farm is connected to the grid; it feeds part of its energy in as electricity and transports another part away as hydrogen. Only a pure island solution without a grid connection lies outside the target.
The factual correction under point 1 is therefore no formality: as long as SEN-1 is listed as a project without a grid connection, it appears to lie outside the statutory target; with an electrical connection via NOR-10-1 it lies within it.
The draft amendment to the WindSeeG adopted by the Federal Cabinet on 2 September 2026 confirms this. In section 3 no. 9, “which are in each case not connected to the grid” is replaced by “in particular electrolysers”; in section 4(3) sentence 1 the same restriction is deleted; the explanatory memorandum states that this enables “both feeding into the electricity grid and using electricity from the onshore grid”. The deletion of section 5(2a) sentence 2 will in future allow the site development plan to designate routes for cables that carry energy from other energy generation areas into the grid – according to the explanatory memorandum “against the background of the [...] fundamental decision to open the other energy generation areas to grid connection”.
Crediting capacity from neighbouring EEZs: the same question, a different result
The draft credits 5.0 GW to 9.4 GW of generation capacity from neighbouring exclusive economic zones towards the German expansion targets, including hybrid interconnectors and cross-border radials, for some of which there is neither an intergovernmental agreement nor confirmation in the grid development plan (cf. question 25). It is not consistent to credit foreign generation capacity towards the German target while treating domestic capacity in the German EEZ as irrelevant to the target merely because part of its energy is transported as hydrogen.
On the crediting question itself (question 25): crediting foreign capacity should be tied to a robust project and contractual status. If this is departed from, equal treatment of domestic hybrid concepts becomes all the more compelling.
The TSOs already anticipate future law in two places – but not for offshore electrolysis
The reticence towards offshore electrolysis is justified with the legal situation; the Gas and Hydrogen Scenario Framework states this explicitly: SEN-1 is taken into account “as the legal planning basis is already fully in place today”, whereas for zones 4 and 5 an improved basis is only expected with the WindSeeG amendment (p. 95 and footnote 1).
In two other places the TSOs proceed in exactly the opposite way and anticipate a legal situation that is not yet in force.
First, when crediting capacity from neighbouring EEZs. The draft itself states on p. 77:
“The current legal situation does not provide for crediting generation capacity from neighbouring EEZs. However, political developments suggest a corresponding amendment. [...] Against this background, the TSOs already anticipate such a legislative amendment and assume individual creditability.”
The supporting basis consists of political agreements of the North Sea Summit of 26 January 2026 and section 5 of a ministerial draft of the Renewable Energy Sources Act (EEG) dated 22 January 2026. On this basis, 5.0 to 9.4 GW enter the scenario key figures.
Second, for overbuilding of the offshore grid connection capacity: the draft assumes an average overbuilding rate of 10 percent “in the German and neighbouring EEZ outside the sites already defined in the FEP” (p. 81), based on a study for BWO and BDEW. The area- and site-specific designation on which its application is to be based is still outstanding (p. 77) – the site development plan, which must be used as a basis under section 12b(1) sentence 4 no. 7 EnWG, has not made it for these sites.
AquaVentus considers this forward-looking planning to be right: grid planning with lead times of seven years and more cannot wait until every legal basis is in force, otherwise it structurally lags behind demand. What is not comprehensible is not applying the same method to offshore electrolysis – especially as the legislative process there is further advanced than in the example the TSOs themselves cite: a ministerial draft there, a cabinet decision of 2 September 2026 here.
The direction of the selection is striking: anticipation takes place where the assumption reduces the need for offshore grid connection systems – relocating generation capacity abroad, overbuilding. There is no anticipation where it would reduce the same need through an alternative means of energy transport. The draft gives no reason for this.
The drafts reflect the status of June 2026 and could not take account of the cabinet decision. Approval, however, only takes place after the consultation has closed – the legal situation at the time of approval should be decisive.
Contradiction with the Gas and Hydrogen Scenario Framework consulted in parallel
The Gas and Hydrogen Scenario Framework is based on a different expectation. In chapter 3.3.2.2 (p. 95, footnote 1) it states that the 2026 WindSeeG amendment is expected to provide an improved legal basis for integrated offshore electricity and hydrogen production, “in particular for combined connection concepts of subsea cable and hydrogen pipeline”, and that this is “relevant above all for far-offshore sites in zones 4 and 5”. Two drafts in the same proceedings thus assess the same matter in opposite ways: once as a foreseeable planning basis, once as a perspective beyond the 70 GW target. This inconsistency should be resolved in the approval procedure.
Proposed wording (replacing the two sentences on p. 82 f.)
“Combined development concepts are already relevant for achieving the statutory offshore expansion target of 70 GW, as they concern the connection of the far-offshore sites in zones 4 and 5, whose development is necessary to reach the target. The respective usage options must therefore be carefully weighed within the 70 GW expansion pathway, taking into account overall system efficiency and infrastructure costs. The TSOs will underpin this assessment in the NEP 2040/2045 (2027) with a sensitivity analysis in which part of the generation capacity in zones 4 and 5 is developed via a combined connection concept of subsea cable and hydrogen pipeline. The effects on the need for offshore grid connection systems, on the utilisation of the offshore power transmission infrastructure, on curtailment and on infrastructure costs will be shown.”
3. Second revenue stream and higher utilisation of the electricity infrastructure (on question 1)
Offshore electrolysis stabilises offshore wind commercially
The scenario framework reflects how much offshore wind capacity is built. Whether it is built depends on refinancing. In 2025, tenders for offshore wind sites received no bids for the first time; at the same time, hours with negative electricity prices are increasing, and the market value of offshore generation falls as simultaneous feed-in grows. An expansion pathway based solely on electricity revenues thus itself becomes a delivery risk for scenarios B and C.
Offshore electrolysis opens up a second revenue stream for offshore wind farm operators that applies precisely in the hours when electricity revenues are low or negative: instead of curtailing or feeding in at negative prices, hydrogen is produced and marketed via the pipeline. Frontier Economics quantifies this: in the 55 GW scenario, the annual revenue gap of offshore integration of around EUR 343 million in the planned expansion (coastal electrolysis, no overplanting) and around EUR 227 million with pure electricity overplanting turns into a positive contribution margin of around EUR 134 million with offshore sector coupling – from electricity and hydrogen sales at wholesale prices alone, without network charges or other remuneration mechanisms. The second revenue stream thus lowers project risk and the need for state support.
Bidirectional use increases the utilisation of the expensive electricity infrastructure
Subsea cables are the most expensive element of offshore integration; the grid development plan shows around EUR 158 billion for offshore transmission up to 2045. Their utilisation is therefore a key economic indicator – and it rises markedly with offshore electrolysis on a bidirectionally usable connection:
– Frontier Economics (2025): the utilisation of the offshore power transmission infrastructure rises in the 70 GW scenario from 52 percent with pure electricity overplanting to 65 percent with offshore sector coupling; in the 55 GW scenario from 55 to 64 percent.
– E-Bridge Consulting (2024): with bidirectional cable use, the electrolyser can draw electricity from the mainland when wind output is low. The capacity factor of the cables rises by 11 percentage points on average, that of the electrolysers by around 6 percentage points; in the hydrogen-dominated mixed concept, joint capacity factors of up to 60 percent are achieved, compared with around 43 percent for single connection concepts.
– At the same time, curtailment in the 70 GW scenario falls from 14 to 11 percent, corresponding to around 2.5 TWh of additional usable energy per year; in the 55 GW scenario from 5 to 3 percent, or around 1 TWh per year.
4. The project baseline of Scenario Path B does not fully reflect the joint electrolyser list (on question 16)
Finding
Question 16 asks whether the reduction of the project baseline in joint Scenario B is appropriate. It is based on the joint electrolyser list, prepared for the first time jointly by the TSOs and the gas and hydrogen transmission network operators and published for consultation. For each expansion stage it indicates whether the project is taken into account in the joint scenario.
Analysis of the list confirms the methodology described in the draft: of 236 published expansion stages totalling 52,993.5 MW, 113 have the project status “design planning/regional planning procedure” or better; 112 of these are marked for the joint scenario (15,958 MW). The project-based share of Scenario Path B of 11 GW shown in table 11 follows arithmetically from this: detailed planning, procurement and commissioning in full (7,284 MW) plus 50 percent of design planning (8,674 MW), together around 11.6 GW.
Within this methodology there is exactly one deviation, and it concerns the offshore entries. The SEN-1 project, with 1 GW and the status “design planning”, is correctly marked for the joint scenario. The entry for the SEN-X project with 10,000 MW – with the same project status the largest single entry in the entire list – is, by contrast, not marked. The capacity figure also requires clarification: for SEN-X, 10 GW of offshore wind capacity was reported as the total potential of zones 4 and 5, not electrolysis capacity of that size; the list nevertheless shows the 10 GW as the electrical capacity of an electrolyser. Regardless of the amount, the marking must be corrected in line with the methodology described – the entry meets the status criterion. Together, both directly affect the project-based share of Scenario Path B; without clarification, question 16 cannot be answered.
In addition, the list contains seven expansion stages with the federal state “North Sea” totalling 16,000 MW. The Gas and Hydrogen Scenario Framework lists these as a separate “Offshore” row with 16 GW and 11.7 GWh/h of injection capacity and states that around 30 percent of reported capacity is located offshore (table 39, p. 60). Following the above, this figure rests to a considerable extent on confusing wind and electrolysis capacity. In the Electricity Scenario Framework, conversely, none of the offshore volumes appear: figure 21 does not allocate offshore projects to any federal state, and the text mentions only “one offshore electrolysis project (SEN-1)”. Both drafts are based on the same list but present its offshore share in opposite ways – and in both cases it cannot be verified without publication of the underlying reports.
Demand
– State how the offshore entries of the joint electrolyser list are treated in Scenario Paths A, B and C – after reconciling their capacity figures.
– Reconcile the capacity figure of this entry with the reported data, and mark it in line with the rules or give a comprehensible justification for the deviation.
5. Summary of demands
1. Correct the description of SEN-1 on p. 61 and in the note on figure 21 (p. 62) in line with the proposed wording: SEN-1 is planned with an electrical connection via NOR-10-1 and is therefore relevant for power system modelling.
2. Transparently state which share of the electrolysis capacity shown in table 11 is excluded from power system modelling, if the TSOs maintain their classification.
3. Treat offshore and onshore electrolysers methodologically alike as flexible loads: model SEN-1 in line with the reported PEM technology with fully flexible, marginal-price-driven operation – not as inflexible base load like a chlor-alkali process – including a bidirectionally usable connection.
4. Correct the classification of combined development concepts on p. 82 f. in line with the proposed wording: the assessment by overall system efficiency and infrastructure costs must be carried out within the 70 GW expansion pathway.
5. Include an “offshore sector coupling” sensitivity analysis in which part of the generation capacity of zones 4 and 5 is developed via combined connection concepts, showing the effect on ONAS demand, cable utilisation, curtailment and infrastructure costs.
6. Apply the anticipation principle consistently: anyone who anticipates the crediting of capacity from neighbouring EEZs on the basis of a ministerial draft (p. 77) must take equal account of opening the other energy generation areas to grid connection – the subject of a cabinet decision since 2 September 2026.
7. Resolve the contradiction between the two draft scenario frameworks (Gas and Hydrogen, p. 95, footnote 1) regarding the expectation for combined connection concepts in zones 4 and 5.
8. State how the offshore entries of the joint electrolyser list are treated in Scenario Paths A, B and C, reconcile their capacity figures with the data actually reported – for SEN-X, 10 GW of offshore wind capacity was reported, not electrolysis capacity of that size – and mark it in line with the rules or justify the only deviation from the inclusion methodology.
9. Treat the optimisation pathways “relocation to neighbouring EEZs” and “offshore sector coupling” equally when assessing full-load hours and utilisation.
AquaVentus is available for a technical discussion to go into the technical and economic foundations in more depth.
Study references
– Frontier Economics: “Effiziente Integration von Offshore-Windenergie durch Offshore-Wasserstoffproduktion” (Efficient integration of offshore wind energy through offshore hydrogen production), 24 November 2025, commissioned by AquaVentus Förderverein e.V. https://aquaventus.org/en/leitstudien/frontier-economics-2025
– E-Bridge Consulting: “Bewertung von Anschlusskonzepten für weit entfernte Offshore-Windgebiete in der deutschen Nordsee” (Assessment of connection concepts for far-offshore wind areas in the German North Sea), September 2024, commissioned by AquaVentus Förderverein e.V. https://aquaventus.org/downloads/studien/kurzstudie-2024-de.pdf
– Fraunhofer IEE: “German Offshore Energy Islands in the European Energy System – A case study analysis”, September 2024. https://aquaventus.org/downloads/studien/fraunhofer-iee-energy-islands-2024.pdf