15.2.1 Regional Planning

When it comes to constructing new hydrogen pipelines, the requirements of regional planning processes must be taken into account. Key provisions include the allocation of energy plants and conflict resolution between such plants and other land uses.Footnote ¹⁵

The regional planning procedure, as outlined in article 15 Regional Planning Act (ROG), can play an important role in the planning of energy facilities in the absence of comprehensive planning requirements.Footnote ¹⁶ Pursuant to article 1 No. 14 Regional Planning Ordinance (RoV), a regional planning procedure is required for gas pipelines of more than 300 mm diameter. As per article 43l (7) EnWG, the term ‘gas pipelines’ in article 1 No. 14 RoV explicitly includes hydrogen networks. It follows from the legislative documents that the wording ‘with a diameter of more than 300 mm’ is to be understood as the inside diameter as the nominal width.Footnote ¹⁷ This clarification is necessary because in engineering, diameters of pipelines are defined for the outer diameter.Footnote ¹⁸ This difference in understanding can lead to problems of application in practice.Footnote ¹⁹

In this context, the literature raises the question whether, in the case of an interconnection of several hydrogen pipelines with different nominal diameters, one pipeline section with a diameter of more than 300 mm is sufficient for the fulfilment of the legal requirements, in this case article 1 No. 14 RoV in conjunction with article 43l (7) EnWG, or whether the predominant share of such pipelines in a network is decisive.Footnote ²⁰

While the wording seems to indicate that a single pipeline cannot fulfil the definition of a ‘network’, the legislator’s explanatory memorandum (as well as the ‘network’ term in article 2 (2) of Directive 2009/73/EC) support the assumption that a single pipeline section is in fact sufficient to fulfil the definition of a ‘network’ and thus opens up the scope of section 1 No. 14 RoV.Footnote ²¹ The argument against this reading is that, given the legislator’s intention to create a framework for the accelerated development and expansion of hydrogen networks, the implementation of regional planning procedures, which have so far not been necessary for gas supply networks, could also be avoided for hydrogen networks.Footnote ²² For the time being, there is a stronger case for assuming that a section of pipeline with a diameter of more than 300 mm is sufficient to meet the legal requirements and therefore the terms hydrogen pipeline and hydrogen network are to be understood synonymously.

Accelerating regional planning procedures was the subject of a recent legislative resolution by the German Federal Parliament.Footnote ²³ Long procedures are not only economically detrimental to project developers and investors but they also impede a swift energy transition.Footnote ²⁴ The acceleration provisions include leveraging enhanced digitisation in participation procedures, reducing redundant amendments to draft plans, and refining plan maintenance rules to bolster planning and investment assurance.Footnote ²⁵ Additionally, efforts aim to enhance cohesion between regional planning and approval processes, ultimately streamlining the overall procedure.Footnote ²⁶

Against the backdrop of the legislator’s intention to quickly develop and expand Germany’s hydrogen infrastructure amid sustained high expansion demand for the energy transition, expediting regional planning through the recent resolution holds potential for notable simplification and optimisation.

As mentioned above, the regional planning procedure has a broad geographical scope. For the more concrete approval of projects, the plan approval procedure is relevant, and will be discussed next.

15.2.2 Plan Approval

Large infrastructure projects often lead to conflicts of interest. To carefully weigh up all interests and take the best possible account of those affected, there is a plan approval procedure in Germany. It involves extensive participation by the authorities and, in most cases, the public.Footnote ²⁷ Decisions on large-scale projects have to be made based on a single procedure to ensure that all relevant facts and interests are taken into account and an appropriate balance is struck.Footnote ²⁸ The plan approval procedure is thus designed as a one-stop shop in that it includes all other official decisions required for the project’s implementation.Footnote ²⁹ This so-called concentration effect ensures that further public law permissions are not required for the energy facility, according to article 75 (1) 1 Administrative Procedures Act (VwVfG).Footnote ³⁰

Whether or not a plan approval procedure is required is determined by the relevant sectoral law.Footnote ³¹ The legal basis for the plan approval procedure can be found in articles 72–78 VwVfG.Footnote ³² For planning approval concerning the construction of hydrogen pipelines, article 43 and following EnWG contain special provisions. Explicit reference to articles 72–78 VwVfG is made in article 43 (4) EnWG, which shows the mentioned interdependence between the sectoral regulations and the general provisions in the law of energy plants.

15.2.3 Environmental Law

Various attempts to unify German environmental law have so far failed, which means German environmental law is splintered and consists of various sectoral laws.Footnote ⁴⁵ As a result, the many sectoral environmental laws that focus on specific environmental areas – such as the UVPG, as well as nature conservation law, water resources law, or forest law – must be taken into account individually when constructing hydrogen pipelines.

The Federal Immission Control Act (BImSchG) is another law which aims to protect various aspects of the environment.Footnote ⁴⁶ The BImSchG is limited to general requirements. It is only through sub-legislative concretisation in numerous implementing ordinances that these become manageable for legal application. One of those is the 4th Ordinance on the Implementation of the BImSchG (4. BImSchV), which plays a constitutive role in determining the types of installations subject to permission. As the transportation of hydrogen is not listed in its Annex 1, an emission control permit is not required here.

Interestingly, hydrogen-specific provisions can only be found for the EIA. However, the legal privilege outlined in article 43l (1) EnWG, which establishes the overriding public interest privilege until 31 December 2025 for the construction of hydrogen pipelines, may play a decisive role in balancing processes with individual environmental laws.

The construction and operation of a gas supply pipeline require an EIA if length and diameter exceed certain values, according to No. 19.2 of Annex 1 to the UVPG. Article 43l (2) 1 EnWG stipulates that Annex 1 No. 19.2 UVPG is applicable to hydrogen networks. The EIA obligation varies depending on whether it is mandatory (projects in column 1 of Annex 1) or determined through an official preliminary assessment (projects in column 2 of Annex 1).Footnote ⁴⁷ For hydrogen grids with a length over 40 km and a diameter over 800 mm, the EIA is mandatory according to Annex 1 No. 19.2.1 of the UVPG in conjunction with article 43l (2) 2 EnWG. In the case of hydrogen networks with pipelines having a diameter between 300 mm and 800 mm, new projects require a preliminary assessment under article 7 UVPG.Footnote ⁴⁸

The purpose of the preliminary assessment is to check, in a relatively quick and inexpensive way, whether or not an EIA is required for projects that could have an abstract or concrete significant environmental impact.Footnote ⁴⁹ A distinction is made between two types of preliminary assessment: a general preliminary assessment (article 7 (1) 1 UVPG) and a site-specific preliminary assessment (article 7 (2) UVPG). The latter corresponds to a large extent to the former, but with the possibility of a reduced assessment programme.Footnote ⁵⁰ The preliminary assessment will be particularly helpful for projects where large parts of the natural gas pipelines can be repurposed for hydrogen and only a few new pipelines with diameters between 300 mm and 800 mm need to be built to complement the network.

However, it must be acknowledged that the EIA authorisation process, in general, is quite time-consuming. Between 2009 and 2021 the average time from application to decision was 16.8 months.Footnote ⁵¹ This clearly poses a challenge for the intended rapid development of a hydrogen infrastructure in Germany and will need to be addressed further by policy-makers going forward, in the interest of accelerating the permission procedure. One area where such acceleration has arguably occurred is pipeline rights and land use agreements, to which the following section is devoted.

15.2.4 Pipeline Rights and Land Use Agreements

Pipeline-based energy supply often requires the use of land that is owned by third parties.Footnote ⁵² While public law permissions primarily address public law concerns, they do not account for potential conflicts with the private rights of third parties, such as land ownership. As a result, construction and operationFootnote ⁵³ of gas supply pipelines require civil law approval in addition to public law permits.

For pipeline rights to properties that are not dedicated as public transport routes, such as licence agreements, limited personal easements or other agreements that do not provide for the registration of a limited personal easement, article 113a (1) EnWG determines that existing approvals for gas supply pipelines are, when in doubt, to be interpreted in a manner that includes the construction and operation of hydrogen pipelines. However, if it can be concluded from the agreement that the third party did not wish to authorise hydrogen pipelines on its property, or would not have had it been asked to do so, there is no doubt about interpretation, and therefore no applicability of article 113a (1) EnWG.

Pipeline rights on public transport routes, so-called land use agreements within the meaning of article 46 EnWG, are regulated in article 113a (2) and (3) EnWG. If a network operator has a land use agreement as defined by article 46 EnWG for gas pipelines, this contract also applies to the transport and distribution of hydrogen, but only until the end of its term, according to article 113a (2) EnWG.Footnote ⁵⁴ However, article 113a (3) EnWG establishes the right of hydrogen network operators to request land use agreements from municipalities if the current contract period has come to an end. In effect, this imposes a contracting obligation on the latter, alleviating the burden of contract negotiations for new projects.Footnote ⁵⁵ Moreover, article 113a (3) EnWG stipulates that the conditions of land use agreements for hydrogen pipelines may not be less favourable than those of land use agreements for gas pipelines.Footnote ⁵⁶

Only when new contracts are concluded do developers need to take action; it is only new contracts with private parties that are not subject to special regulations. Overall, article 113a EnWG enables the gradual expansion and development of hydrogen networks without delays caused by legal uncertainties in contract interpretation or required contract negotiations.Footnote ⁵⁷

Having assessed the permission regime for the construction of hydrogen pipelines, we will now turn to the issue of repurposing existing natural gas pipelines for the transportation of this promising carrier of energy.

15.3.1 Plan Approval Procedure

The most important planning law regulation for accelerating the establishment and expansion of hydrogen networks is the regulation governing procedural simplifications for the repurposing of existing gas supply pipelines to hydrogen, which is outlined in article 43l (4) EnWG.Footnote ⁵⁹ Article 43l (4) and (5) EnWG provide a special lever. They extend the scope of official approvals for natural gas pipelines and their ancillary facilities to hydrogen transportation. This is subject to the requirement that the initial natural gas pipeline approvals were integrated in a plan approval procedure and do not require an emission control permitFootnote ⁶⁰ (see Section 15.2.3), and had been based on the EnWG or another law.Footnote ⁶¹ According to article 43l (4) 2 EnWG, the transferability applies not only to previous official approvals, but also to pipelines that were subject only to a notification procedure. Accordingly, these gas supply systems are allowed to be repurposed for hydrogen without a plan approval procedure.Footnote ⁶²

According to article 43l (4) 3 EnWG in conjunction with article 113c (3) EnWG, there is a mandatory notification requirement for repurposing. The notification, along with necessary safety assessment documents and an expert report verifying compliance with the technical rules of the German Technical and Scientific Association for Gas and Water (DVGW),Footnote ⁶³ must be submitted to the competent authority at least eight weeks before the repurposing begins.Footnote ⁶⁴ The authority then has an eight-week window to confirm that there are no objections to the repurposing (article 43l (4) 3 EnWG in conjunction with article 49 (1) EnWG).

Article 113c (3) EnWG does not differentiate between gas pipelines of different pressure levels or different lengths and diameters, extending the official preventive control to all gas pipelines that are to be repurposed. Scholars have questioned the proportionality of this extension of regulatory control, arguing that it restricts the technical self-administration of the gas industry enshrined in article 49 EnWG and brings about additional bureaucracy.Footnote ⁶⁵ This can be countered by the fact that article 49 EnWG actually provides for the operator’s own responsibility to comply with the technical rules, so that the authority only takes action in exceptional cases, namely when the operator clearly fails to meet its responsibilities.Footnote ⁶⁶ The obligation to notify and the requirement to obtain an expert’s opinion during the repurposing process therefore serve to ensure safety during the transitional phase.Footnote ⁶⁷

Until recently it was assumed that technical modifications would be necessary when repurposing natural gas pipelines for the use of hydrogen.Footnote ⁶⁸ However, a current research project by the DVGW, which investigated the fracture-mechanical material behaviour of natural gas steel pipelines, demonstrated their suitability for hydrogen transmission.Footnote ⁶⁹ Should modifications nevertheless become necessary, these may fall under the requirements of either article 43l (2) EnWG or article 43f EnWG.

According to article 43l (2) EnWG, the modification of hydrogen pipelines with a diameter of more than 300 mm requires planning approval. The modification of pipelines with a diameter of 300 mm or less is subject to a facultative plan approval procedure (as discussed earlier in this chapter). That said, article 43l (4) EnWG determines that for modifications and extensions of natural gas pipelines for the transport of hydrogen, article 43f EnWG remains unaffected, according to which a notification procedure can replace the planning approval procedure in cases of insignificant modifications or extensions.

The determining factor for article 43f (1) EnWG to be triggered is that a ‘modification’ is made and that this modification is considered to be ‘insignificant’. There is no legal definition of the term ‘modification’.Footnote ⁷⁰ Whether a ‘modification’ occurred must be based on the previous approval decision and interpreted on the basis of the approved version of the plant, including all ancillary provisions, application documents and procedures.Footnote ⁷¹ In the literature, Riege concludes that the more detailed the authorisation documents are, the more likely repurposing measures will be considered a significant deviation, while the more general the description of the installation is, the more likely a notification procedure will be approved.Footnote ⁷² Further, article 43f (1) EnWG allows for the assumption of ‘insignificance of a modification or extension’ if (i) an EIA is not required, (ii) other public interests are not affected, and (iii) the rights of third parties are not affected or appropriate agreements are concluded. To this end, article 43f (2) No. 1 in conjunction with article 43l (4) EnWG stipulates that for ‘modifications and extensions’ to repurpose natural gas pipelines for hydrogen, an EIA is not necessary (if the requirements of article 43f (2) EnWG are met).Footnote ⁷³ Pursuant to article 43f (4) 5 in conjunction with article 43f (2) 1 No. 1 EnWG, no examination of the rights in property of others is required for the modifications and extensions of gas supply pipelines in question. The permitting for repurposing pipelines with a diameter exceeding 300 mm can thus be streamlined and simplified by usage of the notification process.Footnote ⁷⁴

It must be noted, though, that the notification procedure can only replace the planning approval procedure if it would be necessary without the requirements of article 43f EnWG. That means cases of facultative planning approval are excluded from the scope of applications.Footnote ⁷⁵ This result affects modifications made to pipelines with a diameter of 300 mm or less, according to article 43l (2) EnWG. Developers of pipelines with these diameters must therefore obtain the necessary permissions individually unless they opt for a facultative plan approval procedure. This leads to the, rather peculiar, result that the modification of the larger diameter pipelines, which might have more impact than the smaller ones, can be approved through a simple notification procedure, while the smaller ones have to obtain individual approvals for the modification.

Although article 43f (4) 4 EnWG provides for an official decision deadline of one month, in practice this deadline will often not be met due to lack of personnel.Footnote ⁷⁶ In this situation, there is no fictitious approval that would allow the developer to start the repurposing project after a certain period of time.Footnote ⁷⁷ In fact, the resources of the authorities determine the decision deadline. In the event that the deadline is exceeded, developers may only file an action for failure to act pursuant to article 75 Administrative Court Procedures Code (VwGO).Footnote ⁷⁸ However, from a technical point of view, the essential parameters of an existing gas supply pipeline, such as its route, outside diameter, or length, remain unchanged in case of repurposing.Footnote ⁷⁹ Against this backdrop, the obligation for planning approval for the modification of pipelines seems unreasonable, as does the lack of a fictitious approval in the case of insignificant modifications to pipelines.

Before moving on to the matter of land use agreements, an important aspect of the aforementioned environmental law pertaining to the repurposing of pipelines (as opposed to their construction, see Section 15.2.3) merits a brief discussion.

15.3.2 Environmental Impact Assessment

The use of an EIA when repurposing pipelines differs from the case of the construction of a pipeline. As the EIA is always conducted as an integral part of an official approval procedure, according to article 4 UVPG, it requires a so-called carrier procedure, and thus a procedure in which it is embedded.Footnote ⁸⁰ However, if the procedural simplification of article 43l (4), (5) EnWG applies, as is the case with repurposing of gas pipelines, such a carrier procedure is lacking.Footnote ⁸¹ Consequently, article 43f (2) No. 1 EnWG specifies that an EIA is not necessary for the modification or expansion of gas supply pipelines for hydrogen transport under article 43l (4) EnWG. This allows for quick repurposing while still requiring a notification and thus allowing the competent authority an intervention to prohibit the repurposing due to safety concerns.Footnote ⁸²

In the literature, Benrath raises concerns about the exclusion of an EIA in cases of repurposing.Footnote ⁸³ He argues that if the pipeline is used for hydrogen instead of natural gas, this could alter the risk profile for the pipeline operation, and the environmental impacts of potential incidents should be taken into account alongside the normal operational burdens.Footnote ⁸⁴ A blanket exemption from the EIA would be contrary to the existing system.Footnote ⁸⁵ This argument can be refuted when there is no additional adverse environmental effect resulting solely from the change of medium in the pipeline.Footnote ⁸⁶ As long as the essential parameters such as the route and the diameter of the pipeline do not change, it is reasonable to exempt the repurposing of a gas network to hydrogen from the EIA obligation.

While an EIA is a critical tool for identifying and evaluating environmental impacts and ensuring compliance with environmental regulations, it must be noted that the preceding approval procedure for the natural gas pipeline will already have featured an EIA. Therefore, in the case of mere repurposing where modifications, if necessary, are made solely on the inside of the pipelines or the pressure they are operated with is altered, the omission of a second EIA seems justified. Moreover, in light of the time-intensive nature of such a procedure, the omission of an EIA will significantly support the intended rapid expansion of a hydrogen infrastructure in Germany.

15.3.3 Land Use Agreements

When repurposing natural gas pipelines for the transport of hydrogen, project developers will regularly be confronted with the fact that the existing civil law contracts with landowners for the construction and operation of the pipelines do not refer to hydrogen.Footnote ⁸⁷ Therefore, in the event of disagreement with the landowner over the inclusion of the repurposed pipeline in the scope of the agreement, the relevant agreement will have to be interpreted.Footnote ⁸⁸ As demonstrated above, article 113a (1) EnWG contains an interpretation rule in favour of the developer (see Section 15.2.4).

Pipeline rights on public transport routes, so-called land use agreements within the meaning of article 46 EnWG, are regulated by article 113a (2) and (3) EnWG. These agreements will continue to be valid for the transport and distribution of hydrogen until their agreed term expires (see Section 15.2.4). It has to be said that repurposed pipelines may no longer meet the requirements of article 46 EnWG, which pertains to the concession award for energy supply networks in municipal areas.Footnote ⁸⁹ During the initial phase of the hydrogen ramp-up, these conditions may no longer be met, particularly for hydrogen networks initially serving only individual industrial enterprises and extending beyond municipal boundaries.Footnote ⁹⁰ To this end, article 113a (2) ensures ongoing revenues for municipalities even if the pipelines no longer serve end consumers within municipal areas, while enabling network operators to utilise the repurposed pipelines without encountering significant bureaucratic obstacles.Footnote ⁹¹ It is only at the end of the agreed term that the parties will need to enter into a new agreement, which must offer terms no less favourable than those of the previously existing contracts (article 113a (3) EnWG), as discussed above in Section 15.2.4.

Following the analysis of the legal regime for repurposing pipelines, we now turn to the subsequent challenge of hydrogen storage.

16.1.1 French Political Aspirations for Hydrogen

In France, more than 900,000 tons of hydrogen are consumed each year for refining of petrol fuels, producing chemicals and ammonia for fertilizers as well as in the steel and cement industry and heavy transport.Footnote ¹ Up to 98 per cent of that hydrogen is produced by fossil fuels (brown/grey hydrogen),Footnote ² which adds 11.5 tonnes of carbon dioxide (CO2) emissions in France.Footnote ³ Moreover, it is important to note that a part of this hydrogen is ‘co-produced’, meaning it is a side product of industrial processes and generated during the processing of oil cuts in refineries or the gasification of coal in steel factories or steam reforming of natural gas, making these industries in part self-sufficient.Footnote ⁴

France prides itself on being one of the first countries to identify the full potential of hydrogen.Footnote ⁵ Already back in 2015, article 121 of the French Energy Transition Law (No. 2015-992)Footnote ⁶ identified hydrogen as a solution to climate change and put the obligation on the government to submit to Parliament a plan for the development of the storage of renewable energy using decarbonized hydrogen. Moreover, the law specifically asked for the deployment of an infrastructure of hydrogen distribution stations and the adaptation of regulations to enable the deployment of these new hydrogen applications, such as the conversion of electricity into gas.Footnote ⁷ This plan was finally published in June 2018, being the first official French hydrogen deployment plan.Footnote ⁸ Its aim is to support the development of low-carbon hydrogen with the purpose of decarbonizing the industrial sector, the transport sector (road, rail and so on) and to develop storage capacities and stabilize the energy networks.Footnote ⁹

In September 2020, France published its National Hydrogen Strategy in which it announced over €7 billion up to 2030 for low-carbon hydrogen deployment, with €3.4 billion planned for the period 2020–2023.Footnote ¹⁰ In February 2022, almost €2 billion was added to the previous amount with the France 2030 Plan, bringing total government investment in hydrogen to €9 billion.Footnote ¹¹ In November 2022, the revision of the French hydrogen strategy by the end of the first half of 2023 was announced, focusing on hydrogen hubs and expertise in hydrogen-related equipment, but nothing had been published by autumn 2023.Footnote ¹²

The creation of France’s national strategy on hydrogen has been a long-term project. The crucial investment decisions by France were based on the knowledge and experience gathered before 2018 by the hydrogen projects created all over the country with the support of the regions and industrial players. Since 2016, ADEMEFootnote ¹³ has launched quite a fewFootnote ¹⁴ calls for tenders relating to hydrogen,Footnote ¹⁵ while a new call under the ‘Hydrogen Territorial Ecosystems’ programme was launched in May 2023 with a budget of €175 million to finance the production and distribution of hydrogen and the deployment of vehicles.Footnote ¹⁶

From all the above, the prospect of hydrogen for decarbonization and for achieving climate neutrality in France becomes clear. This chapter will focus on one of the important parameters needed for hydrogen deployment, namely the transport of hydrogen. Specifically, the aim is to determine whether or not the French legal system includes provisions aiming at accommodation and facilitation of the transport of hydrogen, which could help France with its ambition to achieve its energy transition goals. Transport of hydrogen plays a crucial role in the French decarbonization plan as it can support innovation, ensure that all points of demand nationally are supplied, and also offers France a potentially central role in cross-border hydrogen trade.

16.1.2 Rule- and Goal-Setting Approaches to Legislation

Furthermore, the chapter aims to determine whether or not French authorities follow a rules-based or goal-based theory regarding the adopted legislation on hydrogen and specifically energy transport. When choosing the appropriate regulatory approach, various factors are taken into consideration, such as the desired allocation of risks, the incentives and behaviour of regulatees as well as enforcement approach and style, and the capacity and expertise of the regulator.Footnote ¹⁷ A rules-based approach to legislation is the classic way of establishing rules with the description of specific conduct that is desired or not.Footnote ¹⁸ This theory, regardless of the advantages that it may present – for example, predictability, stability, comfort in planningFootnote ¹⁹ – has been criticized as inflexible and restrictive. That led to the creation of an opposite regulatory trend, where instead of the rules, certain goals, outcomes, principles or standards are set without prescribing how regulatees need to achieve these goals and outcomes. Even though there is no common agreement on the term for this approach,Footnote ²⁰ in this chapter, ‘goal-setting approach’ will be used.Footnote ²¹ The goal-setting approach is perceived by many as offering flexibility, shifting the focus away from a strict rule on the desired outcomes and a box-ticking mentality to a situation where regulatees are involved in considering the best way to achieve the outcome.Footnote ²² Which of the two regulatory approaches was followed when putting in place the rules for hydrogen transport in France will be considered in the following sections.

16.2.1 The Different Types of Hydrogen in France

Internationally, a spectrum of colours (white to grey)Footnote ²³ is used to provide information related to the energy sources and technical procedures used to produce hydrogen. In the French ‘Hydrogen deployment plan for the energy transition’, published in 2018, a first effort to differentiate the types of hydrogen in France can be seen. In this text, renewable hydrogen is defined as hydrogen produced via electrolysis without the use of fossil fuels, whereas decarbonized hydrogen is hydrogen produced from fossil methane with the CO2 from the production procedure captured and stored underground.Footnote ²⁴

Ambiguity about what is considered to be renewable and decarbonized hydrogen under the French system vanished with the adoption of Ordinance No. 2021-167 of 17 February 2021 on hydrogen.Footnote ²⁵ Article L811-1 (as amended by article 81 of Law 2023-175) of Book VIII of the French Energy Code,Footnote ²⁶ originally introduced by the Ordinance, defines three types of hydrogen: renewable, low-carbon and carbon-based hydrogen. These are distinguished by greenhouse gas emissions and by the primary energy source used for production.Footnote ²⁷

• Renewable hydrogen is ‘produced either by electrolysis using electricity from renewable energy sources as defined in Article L. 211-2, or by any other technology using exclusively one or more of these same renewable energy sources and not conflicting with other uses allowing their direct recovery. This electricity may be supplied as part of an individual or collective self-consumption operation as defined in Articles L. 315-1 and L. 315-2. In all cases, its production process emits, per kilogram of hydrogen produced, a quantity of carbon dioxide equivalents less than or equal to a threshold’.

• Low-carbon hydrogen is hydrogen ‘whose production process generates emissions less than or equal to the threshold for the qualification of renewable hydrogen, without being able, however, to receive this latter qualification, because it does not meet the other criteria’.

• Carbon-based hydrogen is ‘hydrogen that is neither renewable nor low-carbon’.

From the above, it is clear that renewable hydrogen in France is considered to be hydrogen produced by using electricity from renewable energy sources via electrolysis and other production processes like steam reforming of biogas or the thermolysis of biomass. Therefore, going back to the colour spectrum, it can be deduced that French renewable hydrogen is mainly equivalent to green hydrogen. As far as the other categories are concerned, abiding by the same CO2 threshold but also using non-renewable sources for production leads to the conclusion that yellow,Footnote ²⁸ pinkFootnote ²⁹ and blue hydrogen are found under the low-carbon hydrogen definition in France. Lastly, hydrogen that does not conform to either of the first two categories is viewed as carbon-based (grey, brown and black), such as hydrogen produced by steam reforming of natural gas (around 11 kgCO2/kgH2), coal gasification (20 kgCO2/kgH2) or electrolysis using carbon-based electricity mixes.Footnote ³⁰ It is important to note that this third category could potentially include hydrogen produced not only by fossil fuels but also by renewable sources if the emissions of their production process are above the kgCO2eq/kgH2 threshold. According to France Hydrogène,Footnote ³¹ an example could be hydrogen produced from biomass or biogas, depending on the nature of the inputs used and the associated carbon footprint, or depending on the methane leaks taken into account upstream.Footnote ³²

France Hydrogène drafted a table correlating the different ‘colours’ of hydrogen with the new definitions of the French legal system, which confirm those presented above.Footnote ³³ Renewable is ‘green hydrogen’, low-carbon is ‘pink, yellow and blue hydrogen’ and carbon-based is ‘grey, brown and black hydrogen’. Lastly, it is interesting to note that the table includes no correlation for turquoise hydrogen. Turquoise hydrogen is usually produced via pyrolysis of natural gas using energy that was not produced by renewable sources together with solid black carbon.Footnote ³⁴ Since the by-product, black carbon, can be used for purposes like enriching the soil or for the construction of other products such as tyres, its handling can be considered similar to carbon capture, utilization and storage (CCUS) of CO2 in the production of blue hydrogen and therefore turquoise hydrogen should be considered as low-carbon hydrogen. However, if the energy driving the pyrolysis is from renewable sources and/or the feedstock for the pyrolysis is biomethane and not natural gas, the production of turquoise hydrogen becomes zero-carbon and carbon-negative respectively,Footnote ³⁵ making turquoise renewable hydrogen.

The threshold of the CO2 equivalent and the method of its calculation, were set via the relevant decree finally published in July 2024.Footnote ³⁶ The greenhouse gas emissions threshold for qualifying hydrogen as renewable or low-carbon is set at 3.38 kg of CO2 equivalent per kg of hydrogen produced,Footnote ³⁷ which corresponds to the benchmark of a 70% reduction in greenhouse gas emissions compared with a fossil equivalentFootnote ³⁸ introduced by the recast Gas Directive (EU)2024/1788.Footnote ³⁹

For renewable hydrogen, greenhouse gas emissions from production, input supply, processing, transport, distribution, end use and carbon capture and geological storage are counted and they are determined in accordance with the rules for calculating greenhouse gas emissions from hydrogen set out in the AnnexFootnote ⁴⁰ to European Delegated Regulation 2023/1185,Footnote ⁴¹ whereas the methodology for low-carbon hydrogen is presented in the Annex of the French order,Footnote ⁴² but includes all the life-cycle steps listed also for renewable hydrogen. Lastly, from the above, we notice that pink hydrogen is considered low-carbon hydrogen, whereas the fact that the order includes for counting only emissions from the production that are stored geologicallyFootnote ⁴³ and not others like captured and then used in industrial process, seems to exclude blue hydrogen from this category.Footnote ⁴⁴

16.2.2 Transport of Hydrogen

At a global level hydrogen can be transported mainly via three means: trucks, ships and pipelines.Footnote ⁴⁵ The optimal form of transport depends on the end use and the targeted destination.Footnote ⁴⁶ Usually, the use of the existing gas network, after being retrofitted (ensuring leakage prevention, for example), is the optimal choice for medium-distance transportation.Footnote ⁴⁷ Away from pipeline grids, the supply of refuelling stations alongside major road arteries requires the use of alternative forms of transport, with trucks being the most popular option.

As mentioned before, France based its national hydrogen strategy on three pillars for which hydrogen is considered the solution for decarbonization: industry, the energy system and heavy transport. It becomes clear then that there will be a need to deliver massive production of renewable and low-carbon hydrogen throughout the country to the points of consumption. This is one of the main reasons why the transport of hydrogen in France must be looked into. Moreover, due to its geographical location (between the southern Europe producers/exporters and the northern importers), the existing gas infrastructure and interconnections with most of its neighbours, plus the availability (present and planned) of low-emission electricity, France can easily transition to become a hydrogen hub.Footnote ⁴⁸ However, interestingly enough, regardless of the role that France can play in hydrogen transport across Europe and the cross-border hydrogen trade, French hydrogen plans have not included, at least not yet, specific measures for cross-border transport or hydrogen imports and focus mostly on internal production and industry hubs.Footnote ⁴⁹ Nevertheless, transport of hydrogen is crucial for its plans for nationwide decarbonization and that is why it is examined.

17.2.1 Transport

In 2021, a study conducted by several organisations in the Netherlands showed that it is possible and, from a societal point of view, desirable to reuse the Gasunie gas transport network for hydrogen transport.Footnote ⁸ The existing network could be reused to transport hydrogen and connect future hydrogen consumers, suppliers and storage.Footnote ⁹ The gas transport network would be gradually freed up to accommodate the increasing need for transporting hydrogen. This reuse would be more cost effective than the development of new hydrogen transport pipelines and would require an investment of around €1.5 billion.Footnote ¹⁰ The main recommendations of the study are displayed in Figure 17.1.Footnote ¹¹

Figure 17.1 HyWay 27: Realisation of a national hydrogen network

Source: HyWay 27, ‘Hydrogen transmission using the existing natural gas grid? Final report for the Ministry of Economic Affairs and Climate Policy’, June 2021, p. 11 <www.rijksoverheid.nl/documenten/kamerstukken/2021/06/30/kamerbrief-over-ontwikkeling-transportnet-voor-waterstof>

Based on the HyWay 27 report, the Dutch State Secretary of Economic Affairs and Climate (State Secretary) indicated in a letter to the Dutch parliament that a hydrogen transport network would be necessary for a CO₂-free hydrogen chain and that as far as possible it should be based on reuse of existing gas pipelines. The State Secretary also announced a plan for the rollout of the national hydrogen transport network and indicated the intention to request Gasunie to develop this network and free up gas pipelines for reuse.Footnote ¹²

In June 2022, the Dutch government proclaimed that HyNetwork Services, a Gasunie group company, is to develop and operate a dedicated nationwide hydrogen transport network. The investments would have to be made for the, yet to be developed, different hydrogen markets. However, it would not be an option to defer these investments to a later time, because the planned projects for hydrogen production, storage and import require such a hydrogen transport network to be available in order to be realised. The Dutch government has reserved a maximum of €750 million for the development of the hydrogen transport network. The network will connect the major Dutch industrial clusters and storage facilities, and with the neighbouring countries; it is expected to be fully operational by 2030, at the latest.Footnote ¹³

In July 2023, the Minister of Climate and Energy Policy informed the Dutch Parliament of the progress being made on the development of the hydrogen transport network. He indicated that several steps had been taken to centralise the permitting process (Rijkscoordinatieregeling). Furthermore, the planned routing of the hydrogen transport network had to be partly changed, due to two recent developments. First, the war in Ukraine changed natural gas flows, meaning that certain gas pipelines would only become available for reuse at a later time than initially planned. Second, the planned routing had to be aligned with a recently initiated project for the transport of several commodities (including hydrogen) from Rotterdam harbour to the Ruhr area in Germany (Delta Rijn Corridor).Footnote ¹⁴

The development and operation of the hydrogen transport network is expected to have a learning-by-doing character. This means that in the first period the network will be developed in stages and as a linear connection. The pipelines will have fewer connections to other pipelines than in the existing gas transport network. The hydrogen transport network will, at first, due to its linear setup, not have any rerouting possibilities. This means that the operational behaviour of the first hydrogen transport network users will have considerable influence on the integrity of the hydrogen transport network. For example: the consequences of the feeding in of hydrogen that does not comply with the quality specifications, as published, could be felt throughout the whole hydrogen value chain.

17.2.2 Storage

Hydrogen storage is considered an integral part of the development of the hydrogen value chain. The Dutch National Hydrogen Programme, a public–private hydrogen collaboration, foresees a hydrogen storage demand of 750–1,000 gigawatt hours (3–4 salt caverns) for 3–4 gigawatts (GW) electrolyser capacity in 2030 in the Netherlands.Footnote ¹⁵ In Germany, expectations of future demand for hydrogen storage are even higher.Footnote ¹⁶

Hydrogen storage activities focus on the development and operation of large-scale underground hydrogen storage connected to hydrogen transport networks in both the Netherlands and Germany. The idea is to create flexibility and provide hydrogen market players a tool for dealing with both short-term and long-term fluctuations in hydrogen supply and demand. Another function of hydrogen storage will be to increase the security of supply in the energy system as a whole and the socio-economic benefits by allowing the storage of electricity produced and its conversion to hydrogen in a period of over-production of electricity (from renewable sources) and to use that hydrogen to produce electricity in a period of under-production (from renewable sources).Footnote ¹⁷ The first Gasunie hydrogen storage will be developed in the north of the Netherlands and the first cavern is expected to be fully operational in 2028. Three more caverns are planned to be operational after 2030.Footnote ¹⁸

17.2.3 Import

Hydrogen import activities in the Netherlands consist of the development and operation of hydrogen terminal infrastructure for ships in both the Netherlands and Germany, currently with a focus on the ports of Rotterdam, Eemshaven (both in the Netherlands) and Brunsbüttel (Germany).Footnote ¹⁹ The import of renewable hydrogenFootnote ²⁰ is seen by the Dutch government as essential for meeting expected future demand for such hydrogen.Footnote ²¹ By combining hydrogen with nitrogen to create ammonia, it can be transported, stored and converted into green hydrogen in larger quantities. Another possibility is to transport hydrogen via ships by use of so-called liquid organic hydrogen carriers (LOHC), which are essentially organic compounds that may store hydrogen as reversible chemical bonds.

17.2.4 Offshore

In May 2022, Denmark, Germany, Belgium and the Netherlands signed the so-called Esbjerg declaration, agreeing to develop the North Sea as a ‘green power plant’. This will consist of multiple connected offshore energy projects and hubs, centring around large-scale offshore wind energy production, and electricity and hydrogen interconnectors. By 2030, the four EU Member States intend to produce at least 65 GW of offshore wind energy, increasing to at least 150 GW by 2050; 20 GW of the targeted offshore wind energy for 2030 is to be earmarked for onshore and offshore production of green hydrogen and these four countries look to expand the production even further for 2050.Footnote ²²

In December 2022, the Dutch government stated that it intends to assign to Gasunie the task of developing and realising an offshore hydrogen transport network.Footnote ²³ This offshore hydrogen transport network will connect with the onshore network, thereby also connecting offshore infrastructure with onshore hydrogen storage infrastructure.

Having briefly sketched the different hydrogen activities, we will now turn to the Dutch legislative framework which regulates these activities.

17.4.1 Third-Party Access to Hydrogen Transport Networks

Starting with the proposed third-party access regime for hydrogen transport networks, the European Commission proposes that as of 1 January 2031 (and the Council’s starting position is as of 1 January 2036), all EU Member States shall have a system of regulated third-party access in place based on published tariffs, which are applied objectively and non-discriminatorily.Footnote ⁴³ In the amended preamble to its proposal for a new Gas Directive, the European Commission indicates that ‘as a result of the high capital expenditure required for their construction, hydrogen pipeline networks could constitute natural monopolies’.Footnote ⁴⁴

Until 31 December 2030 (until 31 December 2035 in the Council’s starting position), EU Member States have the freedom to opt for a negotiated third-party access regime, whereby the network operator and its customers are obliged to negotiate ‘in good faith’. If the EU Member State opts to apply negotiated third-party access to the hydrogen transport network(s) until the end of 2030 (until the end of 2035 in the Council’s starting position), the regulatory authorities of the Member States need to provide guidance for the network operator’s customers as to how negotiated tariffs will be affected when regulated third-party access is introduced.Footnote ⁴⁵

In the Netherlands, the Minister of Climate and Energy Policy has indicated his intention to make use of the option to introduce a negotiated third-party access regime until 2031 and to determine the framework within which the conditions and tariffs for access and services are set up and HyNetwork Services has to negotiate with parties.Footnote ⁴⁶ This so-called hybrid negotiated third-party access regime, which will be a combination of a regulated and negotiated third-party access regime,Footnote ⁴⁷ will be applied under the earlier mentioned service of general economic interest (see Section 17.3), in advance of the implementation of the Decarbonisation Package. Once the provisions of the Decarbonisation Package have been implemented in the new Energy Act, this hybrid negotiated third-party access regime will gradually be transformed into a regulated third-party access regime with an advisory role for the Dutch regulator, the Netherlands Authority for Consumer and Markets (ACM). Roughly, the foreseen planning is as shown in Figure 17.2.

Figure 17.2 Three-stage approach towards a full regulatory network.

Source: Gijs Kreeft, Ministry of Economic Affairs and Climate Policy, ‘Policy framework conditions hydrogen transport’, presentation given at the Hynetwork Services Information Session ‘National Hydrogen Network and Hydrogen Contractual Framework’, online 22 April 2022, slide 16. See ‘Explanatory Slidepack Consultation’ <www.hynetwork.nl/en/become-a-customer/contracts> accessed on 22 October 2023

Considering that nationwide pipeline infrastructure, such as the natural gas transport networks in the various EU Member States, often forms a natural monopoly, it is understandable that the European Commission seeks to, in the end, have a regulated third-party access regime.Footnote ⁴⁸ It also makes sense not to require EU Member States to immediately introduce such a regime as the different national hydrogen transport markets are yet to develop or, at best, have only just started developing. Too deep regulation (in the form of detailed network codes) at too early a stage could slow or even hamper the development of these markets.

What is more, there would simply be very little infrastructure to apply the regulation to in the first place. Think, for instance, of the very detailed EU regulation on gas transport capacity allocation,Footnote ⁴⁹ which would make no sense at all to apply to the hydrogen transport markets in the coming years as these markets will simply be too immature and not yet liquid enough for such regulation to have any effect. From that perspective, the European Commission’s approach seems sensible.

Nevertheless, for Gasunie, which is, as discussed in Section 17.2, in the middle of the development of a nationwide hydrogen transport network, it is also valuable to have sufficient legal certainty.Footnote ⁵⁰ To be able to invest in such a network, Gasunie will need to have long-term financial commitments from customers. Such commitment usually comes in the form of long-term transport agreements, as has, in our experience, long been the practice in the EU gas transport sector.

The risk of a ‘simple’ negotiated third-party access regime, whereby Gasunie and its potential customers have almost complete commercial freedom in agreeing on tariff and access conditions, is that greatly (between customers) differing long-term hydrogen transport agreements are concluded which later (partly) prove not to be in line with the requirements of the then introduced regulated third-party access regime. This divergence could relate to the agreed tariff as well as to other conditions such as hydrogen quality, pressure and the like.

Therefore, a ‘hybrid’ negotiated third-party access regime that forms a step up to a fully regulated third-party access regime in 2031 seems to be a good option. By setting several of the key tariff and access conditions, the Dutch Minister of Climate and Energy Policy ensures a basic form of non-discriminatory third-party access to the hydrogen transport network while simultaneously providing both Gasunie and its customers some certainty that the long-term commitments accordingly entered into will not become obsolete as soon as a regulated third-party access regime applies. In addition, it provides for learning-by-doing experiences which can be used for the design and roll-out of the regulated third-party access regime as of 2031.

Nevertheless, considerable uncertainty remains for both Gasunie and its potential customers. Even though access conditions such as tariff and hydrogen quality are of great importance to both Gasunie and its potential customers, the exact roles of Gasunie and its potential customers are still to be developed, as are more detailed access conditions. This uncertainty will remain until a full-fledged regulatory third-party access regime has been introduced. Together with other, more external, uncertainties such as the availability of sufficient renewable wind energy for converting renewable electricity into ‘green’ hydrogen as well as the availability of sufficient subsidies, this will have an impact on the willingness to, on both sides, engage in long-term commitments in the current development phase.

17.4.2 Third-Party Access to Hydrogen Storage

The European Commission has proposed a system of regulated third-party access to hydrogen storages, which came as a surprise to companies active in the sector.Footnote ⁵¹ The European Commission notes the following in the proposed preamble to the revised Gas Directive:

The European Commission’s proposal is remarkable in at least two respects.

First, for gas storage, the Gas Directive leaves the choice between either negotiated or regulated third-party access to the Member States.Footnote ⁵³ As hydrogen storage markets currently seem to be developing, we have no reason to assume that the structure of these markets would be very different from that of the gas storage markets. In that respect, the difference between the access regime for the two categories of storage is striking. It would only make sense to introduce a system of regulated third-party access in the case of (perceived) problems with regard to the hydrogen storage market structure. To date, we have no indications that such problems are likely to arise.

Second, the European Commission’s argumentation as to large-scale underground (hydrogen) storage facilities being limited and distributed unevenly across EU Member States likewise holds for (potential) CO₂ storage (for the application of carbon capture and storage – CCS). Nevertheless, Directive 2009/31/EC (CCS Directive) appears to leave EU Member States the choice between the two third-party access regimes.Footnote ⁵⁴

The European Council has taken a more nuanced starting position. It would require negotiated third-party access in the start-up phase and would prescribe regulated third-party access only from 1 January 2036 onwards.Footnote ⁵⁵

But there is also a point to be made concerning the development of hydrogen storage infrastructure. The timeline for the development of hydrogen storage infrastructure mentioned above (Section 17.2.2) is based on the expected demand for storage services. The lead time that is required for developing hydrogen storage is relatively long and can easily take 6–8 years, as considerable time is required for the permitting processes of the underground activities and the above-ground facilities, for the preparation of the underground infrastructure such as assessing and monitoring the geological details, leaching a salt cavern and removing brine with a first fill of hydrogen.

Developers of hydrogen storage infrastructure need to take development decisions soon in order for hydrogen storage to be fully developed by the time the developing hydrogen markets needs hydrogen storage infrastructure. They need to take these decisions, even though hydrogen markets are still nascent and only a limited number of market participants in the different parts of the value chain have sufficient insight into their specific demand for storage services and are able and willing to commit at this early stage.

For developers of hydrogen storage infrastructure, legal certainty is crucial to proceed with their projects. The more freedom the developers of hydrogen storage have to enter into storage agreements with initial storage customers and the longer-term the commitment of the latter, the better these developers can mitigate the financial risks associated with the cost-intensive development of hydrogen storage. Likewise, early commitment of the hydrogen storage developer is crucial for storage customers to mitigate part of their commercial risk through certainty as to the storage products they will receive and the tariffs they will have to pay.

A regime of negotiated third-party access, as would be the case under the starting position of the European Council, but not pursuant to the European Commission and the European Parliament, would support the early development of hydrogen storage infrastructure as the developers of such infrastructure would have sufficient freedom to agree on long-term contracts with storage customers at an early stage, while complying with the obligations of non-discrimination and open access. However, the European Commission’s proposal is rather aiming to apply a regulated third-party access regime. Such a strict regime may pose problems for the development of the hydrogen storage market, in particular due to the two following issues.

The first issue is that a regulated third-party access regime can only provide for a limited degree of certainty on the storage services and tariffs for the coming period. Only once the amended Gas Directive has been adopted and entered into force will the regulated third-party access regime be formally applicable and the regulator have the legal competence to approve the applicable tariffs for the storage services. Up to that moment, hydrogen storage developers and their customers will bear the risk that the tariff approved by the regulator at a later stage will differ from any agreement negotiated between the two at an earlier stage.

In this respect, developers of hydrogen storage infrastructure differ from hydrogen transport infrastructure developers. For the latter, the Member States may choose the negotiated third-party access regime for a transition period, but if they do so, ‘the regulatory authorities shall provide guidance to hydrogen network users on how the negotiated tariffs will be affected when regulated third-party access is introduced’.Footnote ⁵⁶

Such guidance, as well as a transition period towards the regulated third-party access regime, will not be available for hydrogen storage infrastructure developers. This lack of certainty may result in potential storage customers delaying the contracting of storage services. A delay in the contracting of storage services may in turn delay the development of the hydrogen storage infrastructure. It may also create a bigger challenge for the developer to design storage infrastructure that will fully meet future market demand.

The second issue is that under a regulated third-party access regime the storage operator has limited possibilities to adapt the storage services to changing market demand. The storage operator can only provide a storage product once the tariff has been approved by the regulator. This limitation on the ability to quickly adapt to market needs may pose problems, in particular in the phase of the market ramp-up when the storage customers have yet to learn in practice whether their anticipated need for specific storage services is justified by market reality or not.

17.4.3 Third-Party Access to Hydrogen (Import) Terminals

For hydrogen (import) terminals, EU Member States are, according to the European Commission’s proposal to implement a system of negotiated third-party access, whereby the national regulators shall take the necessary measures for potential hydrogen terminal customers to be able to negotiate access to such terminals.Footnote ⁵⁷ The term “hydrogen terminal” covers both an installation used for the transformation of liquid hydrogen or liquid ammonia into gaseous hydrogen as well as an installation used for the liquefaction of gaseous hydrogen.Footnote ⁵⁸ The national regulators shall monitor access conditions and their impact on hydrogen markets and take measures where necessary to safeguard competition.

The starting position of the Council is less strict: it allows a Member State to apply a system of regulated instead of negotiated third-party access, without a compulsory end date for the negotiated third-party access.Footnote ⁵⁹

From what we currently see, it is our expectation that some of the parties currently active in the liquified natural gas (LNG) (import) terminals market will also be active in the hydrogen terminal market. In our opinion, the LNG terminals market is competitive and, accordingly, we expect no fundamental problems with regard to market structure in the future hydrogen terminals market. Apparently, the European Commission is of the same opinion. It expects competition not only between the various future hydrogen import terminals, but also between different means of hydrogen import.Footnote ⁶⁰

However, the European Commission leaves some leeway for national regulators to intervene by taking required measures should these markets not develop properly under a negotiated third-party access regime. This seems like a reasonable and prudent approach. Under the starting position of the Council, the Member State would be allowed to apply regulated third-party access.

17.4.4 Exemptions for New Hydrogen Infrastructure

The proposal for a revised Gas Regulation opens up the possibility of exempting certain new hydrogen infrastructure from specific rules of third-party access and unbundling.Footnote ⁶¹ This provision is similar to one in the existing Gas Directive for new gas infrastructure.Footnote ⁶² Several gas infrastructure projects have received such exemptions, such as the new floating terminal for LNG in Eemshaven, the Netherlands, and LNG terminals in Lubmin and Stade in Germany.Footnote ⁶³

Under the European Commission’s proposal for the revised Gas Regulation, new hydrogen storage infrastructure may be exempted from the regulated third-party access regime, provided the conditions for exemptions are met. These are, in short, that the investment (1) enhances competition, (2) contributes to decarbonisation, (3) is of such a risk level that the investment would not take place without the exemption, (4) is undertaken by a person independent at least in legal form from the hydrogen system operator and (5) that the exemption is not detrimental to competition and other specified goals. The starting position of the European Parliament adds the requirement that demand-side solutions have been taken into account as possible alternatives.Footnote ⁶⁴

It is commendable that the European Commission proposed the possibility of exempting certain new hydrogen infrastructure from the requirements of third-party access under the proposed new Gas Directive. However, one of the exemption conditions seems to form a barrier for exempting new hydrogen infrastructure for which the final investment decision was taken before entry into force of the amended Gas Regulation and thus the coming into existence of the exemption possibility. It is the condition that the level of risk is such that the investment would not take place unless the exemption was granted.Footnote ⁶⁵ At first sight, this condition seems to make it very difficult to argue, in cases where the final investment has already been made, that the investment in question has such a level of risk.

Obviously, this limiting of the exemptions would not help with the quick development of hydrogen markets. If we take the example of hydrogen storage: A hydrogen storage developer who intends to be a frontrunner by taking the necessary investment decision at an early stage before the amended Gas Regulation has been adopted and has come into force will have great difficulties in getting the new infrastructure exempted and very likely remain faced with a regulated third-party access regime. A hydrogen storage developer who makes an investment decision at a later stage, after the amended Gas Regulation entered into force, may receive an exemption under the amended Gas Regulation. Thus, the front runner is put in a more problematic situation than the party that waits.

This barrier could be removed by introducing a transitional provision for the exemption of new hydrogen infrastructure, where the investment decision was taken prior to the entering into force of the exemption possibility of the proposed recast Gas Regulation. The barrier could also be removed, as a side note, if the Council adopted as a starting position that the Member State can apply negotiated third-party access to hydrogen storage until 2036 (see Section 17.4.2). However, should the European Commission’s proposal be adopted unchanged in this respect, this could prove to be a disincentive to the development of hydrogen storage markets at an early stage, which in turn could delay the development of hydrogen markets in general.