Part IV - Regulating Hydrogen Transport

15 Accelerating Permission Hydrogen Transport and Storage Regulation – A German Case Study

Cathérine Jansen

15.1 Introduction

German efforts to exploit the potential of hydrogen to accomplish the energy transition have in recent months seen significant acceleration. Following an update to the National Hydrogen Strategy (NWS) in July 2023,¹ the government recently doubled down on a decision to construct the basic and most important parts of the hydrogen network – the core network – which constitutes a crucial element of the wider infrastructure required to put hydrogen to use.

Legally, this is to be brought about via an amendment to the Energy Industry Act (EnWG) in article 28r EnWG-E.² Projects approved under this article are deemed to be necessary for the energy industry and in the overriding public interest provided they are commissioned by 2030. Further plans are underway to legally accelerate the permission procedure for projects related to core network construction.³ The crucial issue of hydrogen storage is also acknowledged in both the recent amendment and the underlying strategy and is the subject of a separate concept currently being developed by the Federal Ministry for Economic Affairs and Climate Protection.⁴

More broadly, and beyond these new plans to swiftly bring about a new core network (the full mapping of which has yet to occur⁵), it is fair to say that a well-functioning planning and approval law is of paramount importance for the development of a hydrogen infrastructure.⁶ Against this background, the following legal discussion focuses on those equally crucial parts of the hydrogen infrastructure that are not expected to be part of the new proposals and are subject to the existing planning and approval laws of energy plants.

Here, project developers face a significant number of sectoral regulations that are interconnected and can only be understood if their interdependencies are taken into account.⁷ Importantly, Germany’s law of energy plants is not self-contained or uniformly codified.⁸ Depending on the classification, energy plants fall within the scope of application of the EnWG and/or another law and thus within the competence of the energy supervisory authority and/or other supervisory authorities.⁹ Crucially, the EnWG includes provisions for expediting the development of hydrogen infrastructure, which can only be applied if the EnWG is applicable to the respective project. As will be shown below, this might not always be the case.

Moreover, Germany has two types of permission procedures – formal and simplified.¹⁰ Public participation is required during the formal but not during the simplified procedure,¹¹ making the first more time-consuming.¹² To assess the relevant permit requirements, the competent authority must first be aware of the proposed energy installation.

To this end, the so-called administrative opening control requires the developer to inform the authority of the project and/or submit an application for permission before constructing and operating an energy plant.¹³ With regard to the administrative opening control, a fundamental distinction must be made between the obligation to notify and the obligation to obtain a permit. The obligation to notify provides authorities with the necessary information, whereas permission obligations subject the construction and/or operation of an energy facility to a state permit.¹⁴

It is against this wider background of policy dynamism and domestic legal mechanisms that this chapter examines the matter of accelerated permission procedures for the construction of much-needed hydrogen infrastructure. Following this introduction, the chapter is structured into five further sections. Section 15.2 will examine the permission regime for the construction of new hydrogen pipelines. Section 15.3 then shifts the focus to the repurposing of existing natural gas pipelines for the transportation of hydrogen. Section 15.4 directs attention to another important hydrogen infrastructure component and delves into the permission regime for the construction of hydrogen storage. Section 15.5 does the same with a view to the repurposing of cavern storage from natural gas to hydrogen. Building upon these sections, a final conclusion and outlook will be presented in Section 15.6.

15.2 The Permission Regime for the Construction of Pure Hydrogen Pipelines

This section will show that new construction projects in Germany are subject to stringent approval procedures, with little to no option for project developers to benefit from acceleration procedures. Further, it will illustrate that there is no single legal framework exclusively dedicated to energy plants, such as the construction of hydrogen pipelines and their associated facilities. Instead, the interconnectedness of numerous sector-specific provisions that may potentially apply will be looked into.

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.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.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.¹⁷ This clarification is necessary because in engineering, diameters of pipelines are defined for the outer diameter.¹⁸ This difference in understanding can lead to problems of application in practice.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.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.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.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.²³ Long procedures are not only economically detrimental to project developers and investors but they also impede a swift energy transition.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.²⁵ Additionally, efforts aim to enhance cohesion between regional planning and approval processes, ultimately streamlining the overall procedure.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.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.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.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).³⁰

Whether or not a plan approval procedure is required is determined by the relevant sectoral law.³¹ The legal basis for the plan approval procedure can be found in articles 72–78 VwVfG.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.

Plan Approval Decision and Plan Authorisation

The planning approval authority can either be decided by means of a plan approval decision (article 74 (1) VwVfG) or a plan authorisation (article 74 (6) VwVfG). The plan authorisation substitutes the plan approval decision and thus, like the latter, enables the execution of the project described in the submitted plan.³³ The main difference between the two procedures is the exclusion of mandatory public participation from the plan authorisation procedure, leading to a faster process by comparison.³⁴ Due to the interplay with Annex 1 No. 19.2 Environmental Impact Assessment Act (UVPG) as per article 43l (2) EnWG, public participation may be mandatory if the construction of a hydrogen pipeline requires an environmental impact assessment (EIA). That is the case when length and diameter exceed certain values. If there is an obligation to carry out an EIA, public participation within the meaning of article 73 VwVfG is mandatory according to article 3 and 18 (1) UVPG. In this case, the option of an accelerated plan authorisation is ruled out because the requirements of article 74 (6) VwVfG are not met, and a planning approval decision is required. The same applies if a regional planning procedure is mandatory, since it too requires public participation and thus excludes the application of section 74 (6) VwVfG (see Section 15.2.1).³⁵ As the procedural provisions of the UVPG (which will be discussed below under Section 15.2.3) and ROG supplement the general procedural provisions of the VwVfG, the interplay of the different laws applicable becomes apparent.

Mandatory Plan Approval

The legal consequences of obtaining planning approval, as set out in article 43c EnWG in conjunction with article 75 VwVfG, encompass granting permission for the project, while taking into consideration all affected interests. As a result of the concentration effect of article 75 (1) 1 VwVfG, no additional official decisions are required.³⁶

For hydrogen pipelines, a planning approval pursuant to article 43 EnWG might be applicable, provided they are ‘gas supply pipelines’ with a diameter exceeding 300 mm. According to article 43l (1) 1 EnWG, ‘the term gas supply pipeline in part 5 of the law also includes hydrogen networks’. Moreover, article 43l (2) EnWG determines that the planning approval process applies to the construction, operation, and modification of hydrogen pipelines with a diameter exceeding 300 mm.³⁷ Thus, all provisions of the EnWG on plan approval apply to hydrogen networks with a diameter exceeding 300 mm.

In accordance with article 43 (3) EnWG, the consideration of plan approval for a project necessitates the inclusion of both public and private interests that are affected by the project.³⁸ The weighing of interests is a decision-making instrument in German administrative law. It involves the special circumstance that a permit can be granted or an intervention legitimised even though the interests or rights of others are affected. Here, the weighing process must take into account municipal, as well as environmental concerns in relation to the public law permission for an energy pipeline project.³⁹ It is important to note that article 43l (1) 2 EnWG features a so-called overriding public interest for the construction of hydrogen pipelines. This overriding public interest privilege is limited until 31 December 2025. Therefore, in situations where protected interests need to be balanced, priority should be given to hydrogen pipelines, at least until the end of 2025.⁴⁰ In view of the typical length of the planning approval procedure and (if necessary) a preceding regional planning procedure,⁴¹ however, the duration of the overriding public interest privilege seems to be too short and the legislator should reconsider extending the privilege beyond 2025.

Facultative Plan Approval or Mandatory Plan Authorisation

Project developers have the option to voluntarily submit an application for planning approval under article 43l (3) 1 EnWG, when a planning approval procedure is not mandatory because the pipeline’s diameter does not exceed 300 mm as stipulated by article 43l (2) and 43 EnWG in conjunction with article 43l (1) 1 EnWG.

One argument in favour of seeking planning approval is the concentration effect, which eliminates the need to apply for individual approvals from numerous authorities.⁴² Another is the early transfer of ownership as specified in article 44b EnWG and the possibility of commencing construction early under article 44c EnWG. Conversely, as long as the provision of article 43l (1) 2 EnWG on the overriding public interest for the construction of hydrogen pipelines is in force, it may be possible to secure the necessary individual permits more easily compared to undergoing a time-consuming planning approval procedure.

Additionally, the regulation of article 65 (2) UVPG must be taken into account, according to which the project requires planning authorisation if no EIA is required. For the construction of hydrogen pipelines with a diameter of less than 300 mm, for which there is no obligatory plan approval procedure and for which the general preliminary examination or site-specific examination of the individual case indicates that no EIA is necessary, project developers have the choice of whether they want to carry out a facultative plan approval under the EnWG or a plan authorisation under the UVPG.

In the case of a facultative plan approval under the EnWG, the advantage over plan authorisation under the UVPG would be that the specific acceleration regulations under energy law would apply.⁴³ However, the legal privilege under article 43l (1) 2 EnWG only applies until 31 December 2025. In contrast, plan authorisation offers advantages over plan approval in that it has the same legal effect without having to comply with the time-consuming requirements associated with the plan approval process, such as the public participation procedure under article 73 VwVfG.⁴⁴ To conclude, developers must promptly establish the appropriate and optimal procedure for their project to capitalise on the benefits of the procedure that best suits their respective project plans.

Finally, if a plan approval procedure is carried out, environmental concerns are included in the concentration effect; if not, such concerns must be addressed separately. The following section therefore examines what in all cases is part and parcel of the permission procedure.

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.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.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).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.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.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.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.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.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 operation⁵³ 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.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.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.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.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 The Permission Regime for Repurposing Pipelines

As the new EnWG amendment and the revised NWS emphasise,⁵⁸ Germany is banking heavily on the repurposing of natural gas pipelines for hydrogen. Given the decline in fossil fuels required to achieve climate targets, it is logical to use the existing natural gas infrastructure for hydrogen transport. As this section will demonstrate, from a permission point of view, this approach is already flanked by energy legislation that existed prior to the recent EnWG amendment.

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.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 permit⁶⁰ (see Section 15.2.3), and had been based on the EnWG or another law.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.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),⁶³ must be submitted to the competent authority at least eight weeks before the repurposing begins.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.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.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.⁶⁷

Until recently it was assumed that technical modifications would be necessary when repurposing natural gas pipelines for the use of hydrogen.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.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’.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.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.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).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.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.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.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.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).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.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.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.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.⁸²

In the literature, Benrath raises concerns about the exclusion of an EIA in cases of repurposing.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.⁸⁴ A blanket exemption from the EIA would be contrary to the existing system.⁸⁵ This argument can be refuted when there is no additional adverse environmental effect resulting solely from the change of medium in the pipeline.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.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.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.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.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.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.

15.4 The Permission Regime for Hydrogen Storage Construction

Storage is a key part of the required hydrogen infrastructure. Due to natural fluctuations in renewable energy production from sources like wind and solar, efficient storage options are crucial to balance out these fluctuations and meet demand.⁹² Hydrogen can be stored above ground or underground. Both options are subject to different permission requirements. Cavern storage and pore storage are the two primary underground storage options (above-ground storage for considerable amounts of hydrogen is restricted due to technical limitations and high costs).⁹³ Higher injection and withdrawal rates render cavern storage more efficient than pore storage.⁹⁴ While the former can be fully repurposed to hydrogen, use of the latter requires further research.⁹⁵ Therefore, here the focus will be directed at the legal regime for salt cavern storage.

It is important to acknowledge that large-scale underground storage of hydrogen has not yet been pursued in Germany, and there exists no definitive legal framework.⁹⁶ Presently, only pilot projects are underway, indicating an early stage of development.⁹⁷

As established in the Introduction, the EnWG includes provisions for expediting the development of hydrogen infrastructure, which can only be applied if the EnWG is applicable to the respective project. The EnWG, however, is not applicable underground and does not cover the construction of salt caverns used for storing hydrogen. Instead, German mining law is applicable. As will be shown, mining law does not yet provide for any special regulation concerning hydrogen. The following sections consider the construction of salt caverns for hydrogen storage, before then turning to the repurposing of existing natural gas salt caverns for hydrogen purposes.

Salt cavern storage facilities for hydrogen are ‘underground storage’ facilities within the meaning of mining law. Article 4 (9) Federal Mining Act (BBergG), defines ‘underground storage’ as a facility that is employed for the subterranean storage of gases, liquids, and solid substances, excluding water. The utilisation of containerless storage techniques is mandatory to bring underground hydrogen storage facilities within the scope of the BBergG.⁹⁸ This is the lever for the inclusion of cavern storage facilities for gaseous hydrogen in the scope of the Act.⁹⁹

Article 126 (1) BBergG lists specific regulations that are applicable to underground storage. According to article 51 (1) in conjunction with article 126 (1) 1 BBergG, the permitting of construction and management of underground storage facilities is only possible on the basis of operating plan procedures.¹⁰⁰ The various types of operating plans are regulated by article 52 BBergG. The type of operating plan procedure largely determines the scope and duration of the approval process, with projects not subject to EIA being approved significantly faster than those having to go through public participation.¹⁰¹

Pursuant to article 126 (1) BBergG in conjunction with article 51 and following BBergG, underground storage facilities require a main operating plan under mining law. The main operating plan is an essential and constitutive part of the permit for the commencement of mining operations and cannot be replaced by other plans under mining law.¹⁰² It forms the operational and technical basis for the construction and management of the operation.

In addition, the preparation of a framework operating plan is required under article 52 (2a) BBergG in conjunction with article 126 (1) BBergG, and a plan approval procedure is needed for its approval if a project requires an EIA pursuant to the ordinance under article 57c BBergG in conjunction with article 4 and following UVPG. The relevant ordinance is the Environmental Impact Assessment Ordinance Mining (UVP-V-Bergbau). Article 1 UVP-V-Bergbau lists the operations which require an EIA. Hydrogen is currently not listed there. However, this is seen as a regulatory gap that is to be closed by a current draft of an amendment to the ordinance.¹⁰³ According to the draft, the same requirements will apply to the storage of hydrogen as in the case of storage of natural gas. The current lack of legal certainty as to when an EIA is necessary for underground hydrogen storage facilities will thus be eliminated. Therefore, the construction of underground salt cavern storage for hydrogen will be subject to an EIA under mining law and therefore require planning approval. In conclusion, a main operating plan and additionally a framework operating plan will have to be drawn up.

The current draft amendment to the UVP-V-Bergbau underlines the early stage of a framework for underground hydrogen storage. Hydrogen-specific regulations that would support accelerated permission procedures for underground storage, as they exist for pipelines, are not provided for by current mining law. Having said that, the German government is currently working on a hydrogen storage strategy that is supposed to be finalised by 2024.¹⁰⁴

Following this discussion of the permitting regime for pure and newly built hydrogen storage, we will now turn to the question of repurposing existing natural gas storage.

15.5 The Permission Regime for Repurposing Existing Salt Cavern Storage from Natural Gas to Hydrogen

From a technical point of view, it is possible to fully repurpose salt cavern storage from natural gas to hydrogen.¹⁰⁵ Legally, the repurposing of underground natural gas storage facilities will require an amendment to the operating plan, article 52 (4) 2 BBergG.¹⁰⁶ The amendment, like the original operating plan, requires official approval.¹⁰⁷ As mentioned above, hydrogen-specific acceleration provisions do not currently exist but are being developed.

Although the official approval granted for the cavern storage for natural gas could potentially be transferred to the storage of hydrogen through a notification procedure,¹⁰⁸ the current legal framework does not provide for such an approval to be transferred. The underlying assumptions, namely that (1) all necessary approvals have already been granted for the previous use for natural gas; (2) the relevant procedures conducted; and (3) the risk profile does not change in line with the medium in the storage facility or pipeline, are similar to the discussions earlier in this chapter. To sum up: a provision on the repurposing of natural gas storage in the BBergG would greatly benefit the intended accelerated expansion of the hydrogen infrastructure.

15.6 Conclusion and Outlook: From Intentions to Implementation

The imperative to swiftly develop Germany’s hydrogen infrastructure is evident and German policy-makers’ legislative intentions are clear. With the pressing need for an energy transition and the legislators’ explicit goal of establishing an accelerated framework for hydrogen infrastructure development, the government’s recent decision to construct a hydrogen core network, accompanied by an acceleration law, sets the right course. This core network will be the first step in establishing the full-blown infrastructure that hydrogen use requires.

The aim of the second step of hydrogen infrastructure planning is a nationwide, meshed hydrogen network. Among the existing regulatory provisions for the construction of new pipelines, article 113a EnWG concerning easement agreements offers a pathway for project developers to circumvent the laborious and costly contract negotiation process under specified conditions. This provision stands out as an exception by providing vital support for the rapid scaling up of a hydrogen infrastructure.

The broader regulatory landscape, notably article 43l (1) 2 EnWG, which asserts the paramount public interest in hydrogen projects during the balancing process, falls short. Its application ceases as early as 31 December 2025, implying potential invalidity when regional planning or plan approval procedures, which are inherently time-intensive, are required. This limitation, coupled with the recognised protracted nature of the EIA process, presents a palpable impediment to the prompt development of the hydrogen infrastructure envisioned in Germany. Relief will be brought about for projects that will be part of the core network. Article 28r EnWG-E stipulates that these projects are considered to be in the overriding public interest provided they are commissioned by 2030.

Considering this, article 43l (4), (5) EnWG emerges as a pivotal regulation significantly facilitating the establishment and expansion of hydrogen networks. It governs procedural simplifications specifically for the repurposing of existing natural gas supply pipelines for hydrogen. By contrast, the construction of new pipelines necessitates the navigation of a complex web of permissions under diverse laws, underscoring the streamlined notification procedure for repurposing projects as an advantageous alternative.

Turning to hydrogen storage, an astonishing absence of hydrogen-specific regulation for underground cavern storage must be observed, even though such facilities play a critical role in maintaining grid stability and providing essential system services. However, things are changing. While storage systems were a minor consideration in NWS 2020, they feature more prominently in the updated NWS. Further, the amendment to the UVP-V-Bergbau is under way. It provides a degree of clarity regarding the matter of underground hydrogen storage. Moreover, the government is currently working on its first hydrogen storage strategy.

Considering the pressing need for establishing a hydrogen infrastructure to reach climate targets, recent legal developments could be game changers. They demonstrate that Germany is serious about promoting hydrogen and developing it into an important pillar of climate-neutral energy supply.

As Germany strives for a prominent global position in hydrogen technologies, the development of its hydrogen infrastructure will significantly shape its energy landscape, aiding a sustainable, low-carbon future. Streamlined and expedited permission procedures for pipelines and storage facilities will be key to aligning ambitious policy intentions with implementation goals. Picking up speed, then, will be pivotal to ensure that Germany’s hydrogen economy soars high rather than glides low, fuelling even more ambitious transition objectives in the process.

16 Goal-Setting Approaches to the Regulation of Hydrogen Transport A Case Study from France

Kleopatra-Eirini Zerde

16.1 Introduction

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.¹ Up to 98 per cent of that hydrogen is produced by fossil fuels (brown/grey hydrogen),² which adds 11.5 tonnes of carbon dioxide (CO2) emissions in France.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.⁴

France prides itself on being one of the first countries to identify the full potential of hydrogen.⁵ Already back in 2015, article 121 of the French Energy Transition Law (No. 2015-992)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.⁷ This plan was finally published in June 2018, being the first official French hydrogen deployment plan.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.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 2020–2023.¹⁰ 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.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 2023.¹²

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, ADEME¹³ has launched quite a few¹⁴ calls for tenders relating to hydrogen,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.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.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.¹⁸ This theory, regardless of the advantages that it may present – for example, predictability, stability, comfort in planning¹⁹ – 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,²⁰ in this chapter, ‘goal-setting approach’ will be used.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.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 Hydrogen in France

16.2.1 The Different Types of Hydrogen in France

Internationally, a spectrum of colours (white to grey)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.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.²⁵ Article L811-1 (as amended by article 81 of Law 2023-175) of Book VIII of the French Energy Code,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.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,²⁸ pink²⁹ 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.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,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.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.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.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,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 2024.³⁶ 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,³⁷ which corresponds to the benchmark of a 70% reduction in greenhouse gas emissions compared with a fossil equivalent³⁸ introduced by the recast Gas Directive (EU)2024/1788.³⁹

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 Annex⁴⁰ to European Delegated Regulation 2023/1185,⁴¹ whereas the methodology for low-carbon hydrogen is presented in the Annex of the French order,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 geologically⁴³ and not others like captured and then used in industrial process, seems to exclude blue hydrogen from this category.⁴⁴

16.2.2 Transport of Hydrogen

At a global level hydrogen can be transported mainly via three means: trucks, ships and pipelines.⁴⁵ The optimal form of transport depends on the end use and the targeted destination.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.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.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.⁴⁹ Nevertheless, transport of hydrogen is crucial for its plans for nationwide decarbonization and that is why it is examined.

Transport of Hydrogen (Road, Rail and Water Transport)

This section will present the rules applicable for the transport of hydrogen for road, rail and sea transport. In these cases, the French legal system is very clear, classifying hydrogen (regardless of means of production and end use) as a dangerous material and therefore imposing the rules that are applicable to other dangerous materials. Dangerous goods or hazardous materials are substances and articles the carriage of which is prohibited or is authorized only under specific conditions, due to health and safety reasons.⁵⁰

The rules on the national or international transport of dangerous goods by road, rail and inland waterways in France can be found in the ‘TMD Decree’ (Arrêté Transports de Marchandises Dangereuses) (Decree of 29 May 2009 as amended).⁵¹ Specifically, the TMD Decree deals with the application of the Agreement concerning the International Carriage of Dangerous Goods by Road (ADR), the Regulation for International Transport of Dangerous Goods by Railway (RID) and the European Agreement on the International Carriage of Dangerous Goods by Inland Waterways (ADN).⁵² These agreements follow a similar pattern. Each agreement contains a table that pairs the list of identified dangerous materials under their United Nations (UN) number with the requirements applied for the transport of this substance. This is a four-digit number that identifies dangerous goods, hazardous substances and articles (such as explosives, flammable liquids, toxic substances) in the framework of international transport, assigned by the United Nations Committee of Experts on the Transport of Dangerous Goods.⁵³ Specifically for road transport, the ADR contains two Annexes, with Annex A laying down the packaging and labelling requirements and Annex B containing the conditions for the construction, equipment and operation of the vehicle carrying the dangerous good. The RID, which deals with the rail transport of dangerous goods, is appended (Appendix C) to the Convention concerning international transport by train (COTIF, Convention relative aux transports internationaux ferroviaires).

In these conventions, the following are most important in relation to the transport of hydrogen: UN 1049-Hydrogen compressed, UN-1966-Hydrogen liquified/refrigerated, UN 2034-compressed hydrogen and methane admixtures, UN 3166-Vehicle, flammable gas powered or vehicle, flammable liquid powered or vehicle, fuel cell, flammable gas powered or vehicle, fuel cell, flammable liquid powered and UN 3468-Hydrogen in a metal hydride storage device.⁵⁴ The TMD Decree establishes some general obligations for the transport of all dangerous goods, regarding labelling, packaging and documentation of the dangerous goods, the obligation to have a security adviser (article 6 of the TMD) and to provide special training to employees (L 4141-1 and following of the Labour Code).⁵⁵ Under the above UN numbers, hydrogen, whether in gaseous or liquid state, is categorized under class 2, with the principal characteristic as flammable. Each agreement has its own obligations, but they are largely similar regarding weight, packaging and labelling.

Concerning the distribution of hydrogen in refuelling stations, the provisions of ADR and RID, transposed via the TMD Decree, initially did not regulate products used as energy feedstock or fuel inside vehicles. This changed with the adoption of the ministerial decree of 22 October 2018⁵⁶ establishing new headings under the Installations Classified for Environmental Protection (ICPE, Installations classées pour la protection de l’environnement) regulation (heading number 1416⁵⁷ on hydrogen distribution in refuelling stations for mobility applications).

The above shows that the rules on the transport of dangerous material have already been applicable to the transport of hydrogen outside pipelines for many years, without any specific adaptation or modification. The framework for the transport of dangerous goods is highly detailed and meticulous and explains to the regulatees in advance what actions are permissible, leaving almost no margin. The rules-based approach to legislation, that is clearly followed here, is a logical choice in cases such as the transport of dangerous goods legislation where safety with ex ante prohibition of certain actions is the only option.

Hydrogen Transport by Pipelines

The transport of hydrogen via grid connection is a key aspect of future hydrogen-based economies, especially for transport of large quantities.⁵⁸ The hydrogen can be integrated into the natural gas grid by injection as an admixture, by using it to produce synthetic methane to then be injected into the natural gas grid or by the creation of or conversion to 100 per cent hydrogen networks.⁵⁹ Synthetic methane is renewable synthetic gas produced by combining CO2 with hydrogen (methanation).⁶⁰ France, due to its geographical position, has a high incentive to secure proper hydrogen infrastructure that could be part of a pan-European network, since it would be able to export locally produced hydrogen to its neighbours but also import renewable hydrogen from other countries where its production is more economically advantageous (for example, Spain).⁶¹

The right of injection and transport of hydrogen in the gas grid was officially established with the adoption of Ordinance No. 2021-167/17.02.2021 and specifically part III of the newly established Book VIII of the French Energy Code, dedicated to the transport and distribution of hydrogen. Articles L831-1 and L832-1 of the Energy Code set a framework for the transport and distribution of hydrogen in autonomous transport networks, specially dedicated to hydrogen, and separate from those for natural gas. The idea behind the creation of dedicated hydrogen grids in France is that with the expected decline in demand for natural gas over the next decades, the existing, extensive natural gas grid could be used for the transport and distribution of hydrogen, after performing the necessary technical adjustments. The idea of using the existing infrastructure is financially attractive, a fact already well recognized; as Anthony Mazzenga, director for renewable hydrogen and gas of GRTgaz, recently declared: ‘a grid adapted for hydrogen will cost 2 to 3 times less than a new grid dedicated to hydrogen’.⁶² Western Europe already features a hydrogen-dedicated pipeline network of almost 2,000 km running through France, the Benelux and Germany.⁶³

The right to use natural gas pipelines to transport hydrogen was established for the first time by Ordinance No. 2021-167/17.02.2021, which created articles L831-2 and L832-2 of the Energy Code. Specifically, these articles extend the obligations of gas network operators to include hydrogen transport: in the case of injection of hydrogen into natural gas transmission and distribution networks, they ‘shall implement the necessary measures to ensure the proper functioning and balancing of the networks, the continuity of the natural gas transmission and delivery service and the safety of people and property’.⁶⁴

These newly established articles strengthen the pre-existing right to access of other gases into gas systems, which was established a few years before. Originally, article 94 of Law No. 2018-938/30.10.2018⁶⁵ modified article L. 111-97 of the French Energy Code to establish the right of injection of biogas into the natural gas transport and distribution system.

The same article was amended again by article 49 of the Law on Energy and Climate (Law No. 2019-1147/8.11.2019) so that the scope of the article now also includes hydrogen and other renewable gases. It becomes clear from the report on the discussions of the French National Assembly⁶⁶ before the adoption of the Law on Energy and Climate that the extension of the right to access the gas network is important for the producers of renewable hydrogen and will further support the deployment of renewable and low-carbon hydrogen.⁶⁷

The new wording of article L. 111-97 is:

Subject to preserving the proper functioning and security level of natural gas infrastructures, a right of access to the natural gas transmission and distribution facilities and to liquefied natural gas (LNG) installations, including facilities providing ancillary services, is guaranteed by operators who use them for customers, to the producers of renewable gases, low-carbon hydrogen⁶⁸ and recovery gas as well as suppliers and their agents, under conditions defined by contract.⁶⁹

Therefore, owners and/or operators of hydrogen production installations – since the term producers, which is used, does not distinguish between the two – gained the right to access the natural gas systems, which entails their right to use, in line with the ruling of the ECJ in the Sabatauskas case.⁷⁰ However, it is important to note that this right to use depends on the technical safety criteria imposed, determining the gas quality.⁷¹ The connection will depend on the fulfilment of the technical standards needed for the injection and the capacity of the network, since no obligation to prioritize the hydrogen injection projects has been established (first come, first served system). Therefore, it can be deduced that the rules regarding the injection of hydrogen into the natural gas grid establish a general guideline for preserving the proper functioning and safety of the grid without setting down a more detailed framework – following a goal-based regulatory approach, where the goal is the safe injection of hydrogen within the natural gas grid, but leaving the relevant actors to determine how exactly this will be succeeded.

Technical Conditions for Injecting Hydrogen into Natural Gas Networks

In accordance with articles L-433-13, L-453-4 and R-433-14 of the French Energy Code,⁷² transmission system operators (TSOs) and gas distribution system operators (DSOs) issue and make public the guidelines concerning the technical conditions for safe injection that apply to pipelines and connections for gas transmission, distribution and storage facilities, which must be respected by actors in the gas market in order to ensure the safety of the grid.⁷³ GRTgaz and Teréga at the transmission level and GrDF at the distribution level issued their own codes where their rights and obligations are defined as well as the technical prescriptions applicable to their grids.⁷⁴ All three documents include articles on the technical rules that gases other than natural gas have to comply with (articles 7.1.2 and 5.1.2 respectively).⁷⁵ There are provisions on the level of impurities of the gas (concerning Hg, Cl, F, NH3 and so on). The level of H2 in the gas grid is set at 6 per cent (molar) admixture at most.⁷⁶ Moreover, the other gases must comply with the general technical conditions that are also imposed on natural gas – that is, Wobbe index, total sulphur content, density and others.⁷⁷ Interestingly, hydrogen injected into the gas grid was initially considered to be an impurity in the gas system,⁷⁸ which has changed recently.

The report produced by gas infrastructure operators to determine the technical and economic conditions for injecting hydrogen into the networks, based on measure 7 of the French hydrogen plan, shows that hydrogen blended at a rate of 6 per cent (volume) can be achieved in most networks, excluding cases where sensitive structures or installations are present at the customers’ end.⁷⁹ However, to achieve a share of 10 per cent or even 20 per cent of hydrogen in the networks, significant investment is needed.⁸⁰ Moreover, the percentage of blended hydrogen cannot be the same nationally.⁸¹ The volume of injectable hydrogen and the issues that this injection may cause depend, for example, on the specific characteristics of an area (sub-zone of the grid), the nature of pipelines, the presence or not of aquifer storage tanks, the gas quality and the possibility for proper metering, network equipment, network capacity and types of customers connected.⁸²

The proportion of up to 6 per cent of pure hydrogen that may be injected into the grid provides an answer to the question whether or not it is allowed to admix gases in the grid which at the entry point do not fully comply with the technical gas specifications, but they become compliant at the exit point due to the mixing with the pre-existing gases in the gas grid. The GRHYD pilot project⁸³ was able to demonstrate that the injection of a gas mixture composed of up to 20 per cent hydrogen (by volume) into new natural gas distribution networks is technically possible, and Jupiter 1000⁸⁴ safely injected up to 1 per cent hydrogen (by volume) and could reach a theoretical limit of 6 per cent in the transport system.

Guarantees of Origin

Lastly, since France aims to use hydrogen to decarbonize many of its energy systems and processes, it is important to mention the provisions on traceability and guarantee mechanisms established by Ordinance No. 2021-167.⁸⁵ According to article 821-3 of the French Energy Code, a guarantee of origin is issued to attest the origin of the renewable or low-carbon hydrogen produced, if it is likely to be mixed with another type of hydrogen or gas between stages or if the guarantee issued during its production is likely to be sold independently of the hydrogen produced.⁸⁶ The system of guarantees of origin for hydrogen is modelled upon the existing system for biogas (article L. 445-3 and following the French Energy Code) and can play an important role in development and deployment of renewable and low-carbon hydrogen, even if mixed with other gases. However, the guarantee of traceability of article L-821-2 is issued for renewable or low-carbon hydrogen produced and not mixed with another type of hydrogen or gas and that has been physically delivered to the buyer or final consumer.

From the French Energy and Climate Law as well the National Hydrogen Strategy, there is a clear need to increase the deployment of renewable and low-carbon hydrogen for the decarbonization of the energy system and heavy transport. However, since there is no certainty on the exact technical conditions that need to be fulfilled, the French legislators opted to set the general goal of injecting hydrogen into the grid and leaving market players responsible for fulfilment, while keeping the network’s security. Moreover, when setting the traceability and guarantee of origin system, the legislator is pretty precise regarding the system and how it should function, and even established a specific authority to handle and supervise the system (Chapter V of Book VIII of the French Energy code). The goal-setting approach that is followed in view of the right of injection of hydrogen is a good way to achieve the purpose of hydrogen integration into gas systems while ensuring system safety, for which there are still many uncertainties. The goal-setting approach is arguably the best choice in facing technological change and can facilitate technological innovation by allowing regulatees the freedom to experiment,⁸⁷ as happened in the case of France with the development of numerous pilot projects.

16.3 Conclusion

The goal of this chapter was to examine how the existing French legal system accommodates the transport of hydrogen and to scrutinize the regulatory approach followed.

France finally took the first important step towards the establishment of a specific framework related to hydrogen with the adoption of Ordinance No. 2021-167/17.02.2021. Hydrogen (low-carbon and renewable) and the related technologies, such as power-to-gas have been at a central position in the future energy plan for France and have been viewed as important solutions for decarbonization by stakeholders in both the private and public sector. Even though there were some pre-existing elements concerning the regulation of hydrogen transport, they were largely confined to the general rules for transport of dangerous materials. For the hydrogen sector to blossom and to play the role that was envisioned for the French energy transition, some specific elements are needed for hydrogen (specific rules on the types of hydrogen, transport, sale and so on), which has been noted by the private sector over the years.

Besides the existing modes of transporting hydrogen (road, rail, water), France takes great interest in the injection of hydrogen – and especially of green hydrogen – into grids to transport the gas from the hubs of production. For the use of the existing gas network for hydrogen transport, it was concluded that a right to access for hydrogen and renewable gas to the gas grid was adopted a few years ago, opening the way for hydrogen and synthetic natural gas (SNG) injection. The adoption of Ordinance 2021-167 creates the legal leeway for both: a hydrogen-only transport and distribution system as well as the obligation for TSOs and DSOs to take the appropriate measures to ensure the proper functioning and balancing of the gas systems when hydrogen is injected. In terms of numbers, testing for injection of hydrogen admixed with natural gas up to 20 per cent yielded positive results. There now is the clear need to follow up on this quickly by changing the safety regulations and including this technical possibility into law by raising the amount of admissible hydrogen to the natural gas grid from 6 to 20 per cent.

From a regulatory techniques perspective, the approach followed in the case of hydrogen legislation in France is currently moving away from the prescriptive technical rules, such as the rules on the transport of dangerous goods, and towards the setting of important targets – that is, hydrogen injection with respect to the proper function and security of the grid. This latter approach leaves it to the market participants to determine, based on the individual characteristics, how safety in the grid can be achieved.

All in all, the analysis indicates that the decision on regulatory approaches is not a one-time decision: each time for every part of the system, which approach is most suited to reach a given regulatory objective must be considered. In case of hydrogen injection, the adoption of the goal-setting approach is considered a success for the French legislator as it provided leeway to each network operator to experiment based on their particularities. Even though there are still some important legal gaps in existing legislation and ambivalences that need to be resolved, France can be viewed as a positive example for how using a suitable regulatory approach can have a real effect on the quality and speed of adaptation of the legal system to a new energy carrier.

17 The Development of Hydrogen Infrastructure in the Netherlands and Third-Party Access

Maaike Broersma , Philipp Jäger and Marijn Holwerda

17.1 Introduction

Both the EU¹ and the Netherlands² have recently announced their ambitions on the production and consumption of (renewable) hydrogen. The European Commission has proposed legislation on hydrogen by means of a recast of the Gas Directive³ and the Gas Regulation,⁴ the so-called Decarbonisation Package, in December 2021.⁵ The EU has also taken other steps to increase the use of (renewable) hydrogen.⁶ With its experience in hydrogen production, strategic location near the North Sea, potential for offshore wind energy production and extensive onshore natural gas (gas) pipeline network, combined with the expected substantial consumption of hydrogen domestically and in neighbouring countries, the Netherlands has a good starting position for developing a hydrogen economy both at home and in the wider EU.

A significant increase in hydrogen production and consumption in the Netherlands will require the development of large-scale hydrogen infrastructure such as hydrogen transport and storage infrastructure. This chapter examines the development of such infrastructure in the light of recent EU proposals for so-called third-party access to new and repurposed infrastructure. For clarity’s sake, when talking about the development of hydrogen infrastructure, we also refer to the later operation of such infrastructure, even when not explicitly stating so.

N.V. Nederlandse Gasunie (Gasunie), together with its group companies, is active in the development of hydrogen infrastructure in the Netherlands and northern Germany. Gasunie is wholly owned by the Dutch state and one of its group companies operates the Dutch high-pressure natural gas network. Gasunie also operates other natural gas infrastructure.

Below, we will briefly discuss the plans of Gasunie and the Dutch government for the development and operation of hydrogen transport, storage and import infrastructure (Section 17.2). Thereafter, we will give a concise overview of the current Dutch legal framework regulating the hydrogen infrastructure activities Gasunie is developing (Section 17.3). Finally, we will discuss the European Commission’s proposals on third-party access to the different forms of hydrogen infrastructure as well as its proposals for (possibly) exempting new hydrogen infrastructure (Section 17.4). In doing so, we will try and give a first assessment of how these proposals could impact the development of hydrogen infrastructure in the Netherlands, with a focus on hydrogen transport and storage infrastructure. We aim to give the reader an idea of how the different possible regimes for third-party access to hydrogen infrastructure could impact the development of such infrastructure and what challenges could arise for an energy infrastructure company like Gasunie.

17.2 Hydrogen Infrastructure Activities in the Netherlands

In the northern part of Germany and in the Netherlands, Gasunie acts as a transmission system operator of a high-pressure gas network as well as, through its group companies,⁷ an operator of gas storage and gas import infrastructure. In the remainder of this chapter, we will refer to the activities of Gasunie group companies as Gasunie activities.

Besides its more traditional energy infrastructure activities, Gasunie partakes in the Dutch and EU energy transition by developing renewable hydrogen projects. Gasunie hydrogen activities consist of a wide set of initiatives for the development and operation of hydrogen transport, storage and import infrastructure, which will now be discussed in turn.

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.⁸ The existing network could be reused to transport hydrogen and connect future hydrogen consumers, suppliers and storage.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.¹⁰ The main recommendations of the study are displayed in Figure 17.1.¹¹

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.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.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).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.¹⁵ In Germany, expectations of future demand for hydrogen storage are even higher.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).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 2030.¹⁸

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).¹⁹ The import of renewable hydrogen²⁰ is seen by the Dutch government as essential for meeting expected future demand for such hydrogen.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 2050.²²

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.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.

17.3 The National Legislative Framework for Hydrogen Infrastructure Activities

Alongside the obvious areas of law such as spatial planning law and competition law, the Dutch legislative framework for hydrogen activities in essence consists of the Dutch Gas Act. In June 2023, a draft for a new Energy Act was submitted to the Dutch Parliament, aimed at amending and merging the Gas Act with the Electricity Act 1998, to form a new, all-encompassing act.²⁴

A two-stage process is foreseen, whereby in the current first stage the Gas Act and Electricity Act will be merged and in the second stage the amendments to the Gas Directive that the European Commission proposed in December 2021 in the so-called Decarbonisation Package²⁵ will be implemented into Dutch law, very likely in the Energy Act.²⁶ The latter will be initiated after these proposals have gone through the complete EU legislative process and have been enacted as EU law.

Currently it is foreseen that Gasunie will, under national law, be given the statutory task of developing and managing a nationwide onshore and offshore hydrogen transport network (see Section 17.2.1). Considering that the legislative recast process for the Gas Act is ongoing, and the outcome is not clear, our focus here is on the current Gas Act.

As a so-called sector-specific regulation, the Gas Act represents the Dutch transposition of the various EU Gas Directives, such as the current Gas Directive.²⁷ The Gas Act determines which tasks the Dutch gas transport network operator, Gasunie Transport Services (GTS), is to fulfil and which activities it may perform. Since 2019, the Gas Act has also contained a provision on the activities that Gasunie group companies, which form part of the same group as GTS, are allowed to perform in areas other than gas transport.

According to this provision, the Gasunie group, within the meaning of the Dutch Civil Code, shall mainly perform the tasks assigned to GTS by the Gas Act or any act based on it.²⁸ It is to mainly focus on the regulated activity of gas transport.²⁹ However, Gasunie group companies are allowed to perform a limited number of listed activities other than gas transport, mainly in the energy transition field.³⁰

The Gas Act states that Gasunie group companies are allowed to develop and manage hydrogen pipelines or installations (leidingen of installaties voor waterstof), including the transport of hydrogen,³¹ as long as the Dutch ownership unbundling rules are observed.³² Even though the Gas Act speaks of pipelines or installations, the legislator’s intention clearly has been to allow Gasunie to be involved in both types of infrastructure.³³

Finally, the Gas Act gives the Minister of Economic Affairs and Climate Policy the authority to instruct GTS in case the provisions of the Gas Act, or any legislation based on them, are not adhered to.³⁴

In addition, the Dutch Minister of Climate and Energy Policy intends to assign to Gasunie, until the proposed changes to the Gas Directive have been implemented in the new Energy Act, the service of general economic interest of developing and managing a nationwide hydrogen transport network (see Section 17.2.1).³⁵

The concept of a service of general economic interest stems from EU state aid law.³⁶ The term refers to a service which cannot profitably be provided for by the market, but which an EU Member State would like to have carried out in the general (societal) interest.

Since the ruling of the European Court of Justice in the Altmark case, compensation from an EU Member State given to a company for providing a service of general economic interest does not constitute state aid within the meaning of article 107 of the Treaty on the Functioning of the EU, if four conditions are met.³⁷ One of these conditions is that the recipient has to have clearly defined public service obligations.

In a nutshell, at the time of writing, the Dutch legislative framework for hydrogen activities principally consists of the abovementioned provisions of the Gas Act, allowing companies belonging to the Gasunie group to develop and manage hydrogen pipelines and installations, including the transport of hydrogen itself. In addition, the Dutch Minister of Climate and Energy Policy will, through decisions on the hydrogen transport service of general economic interest, also determine part of the legislative framework for hydrogen transport activities, at least until the changes proposed by the European Commission in December 2021 have been transposed into Dutch law. As such, the service of general economic interest decision can be seen as a temporary elaboration of the broader framework of the Gas Act.

17.4 Third-Party Access to Hydrogen Infrastructure under the EU Decarbonisation Package

On 15 December 2021, the European Commission proposed several changes to both the Gas Directive and EU Regulation 715/2009 (Gas Regulation), in order to include hydrogen in the EU’s legislative framework on gas. These proposals have become known as the Decarbonisation Package.³⁸ As the European Commission’s proposals for including hydrogen in the EU gas regulation are extensively discussed in Chapter 2 of this book, ‘Hydrogen Regulation in Europe’ by Hancher and Suciu, we will not get into their full details here.³⁹ Having said that, this chapter will analyse one particular aspect, namely third-party access to hydrogen infrastructure, and the proposals for exempting new hydrogen infrastructure.

The European Parliament⁴⁰ and the Council of Ministers (Council)⁴¹ have adopted their respective starting position for the trialogue in spring 2023. Negotiations between the European Parliament, the Council and the European Commission have started and are, at the time of writing, still ongoing. No clarity yet exists regarding the final versions. We base our appraisal on the Commission’s original proposals only, paying attention to the starting position of the European Parliament and the Council where they differ from the Commission’s original proposal. In doing so, we will also try and have a look at the European Commission’s possible intentions behind the proposals.

The term third-party access refers to access to (energy) infrastructure by parties who do not control the relevant infrastructure. EU energy regulation traditionally differentiates between various third-party access regimes ranging from so-called regulated third-party access, whereby the national regulator sets the tariff and access conditions,⁴² to so-called negotiated access, whereby the network operator and its customers are principally free to determine tariff and access conditions through commercial negotiations.

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.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’.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.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.⁴⁶ This so-called hybrid negotiated third-party access regime, which will be a combination of a regulated and negotiated third-party access regime,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.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,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.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.⁵¹ The European Commission notes the following in the proposed preamble to the revised Gas Directive:

The availability of large-scale underground storage facilities is limited and distributed unevenly across Member States. In view of the potentially beneficial role for the functioning of hydrogen transport and markets, the access to such large-scale underground storages should be subject to regulated third-party access in order to ensure a level playing field for market participants.⁵²

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.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.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.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’.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.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.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.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.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.⁶¹ This provision is similar to one in the existing Gas Directive for new gas infrastructure.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.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.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.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.

17.5 Conclusion

The regulatory framework for hydrogen infrastructure in general and the rules on third-party access in particular are in full development. Conducting business in a (rapidly) changing regulatory framework creates (legal) uncertainty and this uncertainty generally comes at a cost. Gasunie has chosen an early development (and consequent operation) of hydrogen infrastructure in the Netherlands to try and help kick-start the Dutch and EU hydrogen economy. The early development of hydrogen infrastructure against the backdrop of an outdated national legal framework and rapidly developing and highly uncertain EU rules creates several challenges.

When looking at the development of a nationwide Dutch hydrogen transport network and third-party access to such infrastructure, we see a gradual approach chosen by the EU and Dutch legislators trying to fill in the blanks until the network as well as a regulated third-party access regime develops. In general, we believe this is a sensible and workable approach from the perspective of the development (and subsequent operation) of such a network. The biggest challenge for Gasunie and its initial customers will be to create sufficient (legal) certainty on both sides as well as clear respective roles and divisions of responsibility, while reserving leeway for changes and adjustments.

As far as the development of hydrogen storage infrastructure is concerned, a different picture emerges. In contrast to the hydrogen transport infrastructure, there will possibly be no gradual transition to a regulated third-party access regime. Instead, hydrogen storage infrastructure could be governed by a regulated third-party access regime once the amended Gas Directive has been transposed into national law by the Dutch legislator. On the one hand, such a regime seems to offer too little flexibility and commercial freedom for both hydrogen storage infrastructure developers and their customers to ensure early development of such infrastructure. On the other hand, it will still take some time until such an access regime is fully in force. The lack of clarity concerning the precise content of the future regulated third-party access regime creates doubts, which may delay the development of hydrogen transport infrastructure. The lack of a transition provision for exempting new hydrogen storage infrastructure only adds to this uncertainty. This raises the question whether it would not be better to provide EU Member States with the option for a negotiated third-party access regime, as this is currently the case with gas and CO₂ storage.