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Part 2

Hy-Politics – political considerations shaping the evolution of clean hydrogen policy

Summary of the use case in Belgium

Generally speaking, the potential for large-scale hydrogen production, transport and consumption by and for industry is the most promising use case in Belgium.

Belgium today is already an important user of hydrogen technology, mainly in its petrochemical and chemical industries. In 2019, it was estimated that about 6 billion m³ of hydrogen was processed by the Belgian industry, with the Port of Antwerp being a significant user.25 In Belgium there are no less than 613 kilometres of hydrogen pipeline, with junctions around the ports of Ghent (North Sea Port) and Antwerp, one of the biggest networks worldwide anno 2019. The first hydrogen pipelines in Belgium were constructed in 1938, before the Second World War. The Belgian network was mainly constructed in the 1960s and 1970s by Air Liquide, currently still active in the sector.

Belgium map









Map of the existing Belgian hydrogen pipeline network (source: VRT 26 February 2019)26

Industrially produced (grey) hydrogen flows through existing pipelines, which is separated during the processing of natural gas, or as the residual fraction of, for example, chlorine plants. As stated above, it is mainly used for processing chemical or petrochemical products.

The potential of (green) hydrogen for the industry, in Flanders particularly, has an estimated “penetration” rate of about 50% in the processing industry, 10% in the steel industry and 30% in the synthetics and chemical industries (lacking sufficient reference data from the (petro)chemical sector, the latter number is most likely an underestimation).

Under its regional Hydrogen Strategy, published in December 2020, the Flemish Region targets 200MW of green hydrogen production27 (representing 3% of the European target) at its sea ports by 2025 and 500MW by 2030.78 It estimates to receive EUR 125m of funding as an Important Project of Common European Interest (IPCEI) for that purpose.79 The ports of Antwerp and Zeebrugge will continue to play a key role in the further development of the green hydrogen use in these industries. The Hydrogen Import Coalition, consisting, amongst others, of DEME, ENGIE, Exmar, Fluxys and the respective ports, is studying the feasibility of the import value chain for green hydrogen, which should be fully established by 2030.80 

As in most countries, for transportation, more focus is currently placed on electrification of the cars. Nonetheless, for trucks and public transport (buses), hydrogen may be part of the solution. Belgian bus builders Van Hool and VDL are both actively building hydrogen buses and exporting them abroad. In fact, most hydrogen pilot projects to date have focused on the use of hydrogen in transportation, including upgrading the existing pipeline network with hydrogen refuelling stations for hydrogen-powered vehicles (mainly buses and trucks).28  Indeed, the existing network could become the backbone of a wide deployment of hydrogen refuelling stations across the country. They just need to be built.

In addition, there is interest from aviation and the maritime industry.29  The first pilot project powered by hydrogen is the (smaller) passenger ship Hydroville operating on the Scheldt between Antwerp and Kruibeke.30  This project was driven forward by the Belgian shipping company CMB, which is also interested in running freight ships on hydrogen in the mid-long term.

The potential of (green) hydrogen for transportation, in Flanders particularly, has an estimated “penetration” rate of about 30% for private vehicles, 50% for public busses, 50% for trucks and 50% for ships.31

Because hydrogen can provide both electricity and heat, there is also increasing interest from the energy sector. The focus is on combined heating and power (cogeneration) installations and on heat networks in the cities, on closed (industrial) sites and energy communities. Moreover, hydrogen has been proposed as a large-scale storage solution.32  Notwithstanding all this, heating currently seems to be the least important use case for hydrogen in Belgium.

The potential of (green) hydrogen for heating, in Flanders particularly, has an estimated “penetration” rate of about 10% for private households and 15% for the industry.33

Examples of demonstration/feasibility projects in Belgium
WaterstofNet, a Dutch-Flemish, non-profit interest association, has been particularly active in driving and promoting pilot and demonstration projects in the past 10 years. A number of these projects were realised in co-operation and with funding from the European Regional Development Fund for Flanders and The Netherlands (“Interreg Vlaanderen-Nederland”), through its project “Waterstofregio”, which ran from 2009 to 2013, and its successor “waterstofregio 2.0”, currently still running. These projects aim to bring together companies in the Flemish and Dutch regions across the hydrogen value chain around a number of unique demonstration projects.34 WaterstofNet also coordinated and held the pen of the Flemish Hydrogen Strategy for the Waterstof Industrie Cluster (WIC), published in December 2020.

Today, there are two publicly available hydrogen refuelling stations in Flanders, none of which are connected to the pipeline network. One, built and operated by Air Liquide, is located in Zaventem, supplied by tankers, and the other one is located in Halle, supplied by green energy generated from solar panels and wind turbines located on the Colruyt distribution centre site (publicly available to cars since October 2018). On the same distribution centre site electric forklift trucks have been driving around using green hydrogen since 2012 (a Waterstofregio project, which received an upgrade in 2017).35  VDL developed and built a heavy duty pull trailer combination powered by hydrogen, which is currently being tested on the Colruyt site. Preparations are ongoing for the construction of new hydrogen refuelling stations in Wilrijk (as well as Breda, in The Netherlands). Other demos in the pipeline involve mobile refuelling stations, forklift trucks in Ghent and a service and maintenance post for hydrogen fuel cell driven vehicles at E-Trucks Europe.36

In 2013, Umicore, together with Solvay and again with the support of WaterstofNet, opened the largest hydrogen power plant in the world.37 The plant consisted of a container full of fuel cells on the site of Solvay's former chlorine plant. The plant supplied electricity and heat to the Solvay plant. It was powered with surplus hydrogen from the same plant. The plant ran for around 10,000 hours. Sadly, the project was stopped, and its successor, built by the Dutch partner Nedstack is located in China. Umicore’s interest in hydrogen technology is linked to the precious metals it can supply for hydrogen fuel cells, which get the electricity and heat out of the hydrogen.

HyFLOW/Green Octopus is another ambitious co-operation between the Flemish and Dutch port regions under the auspices of WaterstofNet, involving producers, port authorities, gas companies and large-scale users. It envisages the construction (or repurposing) of a 2,000km hydrogen backbone connecting Belgium and its North Sea offshore cluster to its neighbouring countries. It is also an Important Project of Common European Interest (IPCEI).81
A number of concrete hydrogen projects are currently under development:
ENGIE, Carmeuse and John Cockerill (CMI) signed a joint development agreement for a carbon capture and utilisation project in the Walloon Region. The sponsors of the EUR 150m project submitted an application for funding to the EU Innovation Fund and IPCEI. The project will concentrate CO2 from a lime kiln and combine it with green hydrogen to produce methane, which could then be injected into the gas grid or used in transport or industry. The green hydrogen will be produced by a 75MW electrolyser powered by renewable energy. The sponsors are hoping to start implementing the project in 2022 to be operational by 2025.
Indaver, ENGIE, INEOS (via Inovyn), Oiltanking, Fluxys, Port of Antwerp and PMV (via VMH) are part of a consortium in the Port of Antwerp working on a power-to-methanol project, to produce green methanol (used as feedstock in industrial processes) by a combination of CCU and (green) hydrogen. ENGIE and INEOS are also planning to partially and gradually replace natural gas with hydrogen used by the INEOS gas turbine at its CHP Phenol site in Doel.
Fluxys, Eoly and Parkwind, who announced a partnership for sustainable developments in 2018, are co-developing the Hyoffwind project aimed at building a green hydrogen electrolyser of 25 MW in the port of Zeebrugge. They plan to start producing in early 2023.
Ørsted presented SeaH2Land, its ambitious vision for a Gigawatt-scale sustainable hydrogen plant in the Dutch North Sea. The electrolyser would be connected to the Dutch-Belgian North Sea Port cluster via a cross-border pipeline. The project should be operational by 2030.
Deme, PMV and Port of Ostend are co-developing the HyPort project, aimed at realising a green hydrogen production plant able to produce 50,000 tonnes of green hydrogen annually, the equivalent of 300 MW of energy capacity, which should be operational in the port area of Ostend by 2025.
CMI, an established manufacturer of hydrogen electrolysers, has also formed the Hyve consortium with Bekaert, Colruyt Group, Deme, Imec and Vito to develop more efficient components and systems for electrolysers.

Other interested players on the Belgian hydrogen scene (both on the demand and the supply side) include: BASF, ArcelorMittal, Agfa-Gevaert and Borit, some of which are represented by the “Power-to-gas” network, which includes 40 Belgian companies, together with WaterstofNet.

Green vs. blue

Currently, hydrogen production in Belgium is quasi 100% grey, but is expected to become gradually greener over the coming years.38  In the medium term, Belgium does not have enough surplus of renewable power to produce green hydrogen on a large scale. The use of electrolysis for hydrogen production would increase greenhouse gas emissions, because producing the required electricity would increase greenhouse gas emissions more than the emissions avoided by using the hydrogen as a fuel or feedstock in industrial processes (e.g. instead of natural gas). As a result, Belgium may have to import additional renewable energy to produce hydrogen, or the green hydrogen itself, from countries able to produce it more efficiently and cheaply.39  Blue hydrogen could therefore be a useful supplement, provided that CCS/U technology can be mastered and some existing obstacles40  to its development are cleared.

Part 4

Hy-Achieving – creating a suitable incentive regime

The industry and (private) transportation use cases in Belgium (i.e. use of hydrogen as a fuel and/or feedstock for the industry) could be incentivised through different supply- and demand-side measures.

While certain industry players (e.g. Air Liquide, with its historical network) may have some incentives to become or remain active in the business of transporting hydrogen, the overarching sentiment among large industrials to date has been to focus their investments on the supply or demand side of the chain, or even both sides, without necessarily making large investments into, e.g. the transport networks themselves (alone or in joint ventures with others, although certain such pilot projects do exist – see above).

Therefore, a strong preference seems to exist among these players for an regulated asset base model, pursuant to which the regulated network operators (in particular, the national gas TSO Fluxys, but also potentially the DSOs, for instance, to develop a network of refuelling stations for transportation) are tasked with the adaptation of their existing and/or the development of a new (dedicated) network,57  which will guarantee them open access to the (existing and future) infrastructure for the benefit of their own core businesses. If this route is taken, ultimately (both natural gas and hydrogen) consumers will pay the bill, through the transport and distribution tariffs. The different Belgian governments have yet to make the necessary policy decisions on this fundamental topic.

In addition, industry may be incentivised to invest in hydrogen infrastructure through other, indirect supply-side measures, such as carbon taxation (e.g. through a reform of the ETS and potentially a carbon border adjustment mechanism, which will make them more competitive if they invest in clean technology – these mechanisms are however decided on EU level). One could also think of direct subsidies and credit support that different regional governments in Belgium could offer under general economic development and expansion legislation.58

The industry itself has suggested a list of incentives and/or fiscal measures to be considered by the governments, including certain duty/tax exemptions and a broader tax shift from electricity to gas and fossil fuels. Examples of such measures are:59

  • the further deployment of low-emission zones for cars and other vehicles in the cities (which in turn will stimulate the development and distribution of low or zero-emission cars);
  • keeping hydrogen a duty-free fuel for a sufficiently long period;
  • tax cuts for zero-emission freight traffic;
  • quota for the implementation a hydrogen fuelled fleet of public transport vehicles;
  • exemptions or reductions of grid fees and other energy related costs and levies on (renewable) electricity used for the production of (green) hydrogen;
  • a harmonised system of guarantees of origin for green and blue hydrogen (which would ideally be developed at EU level to be aligned with neighbouring countries and allow for a liquid market and trading platform for such guarantees, e.g. using the CertifHy methodology and taxonomy); and
  • in the longer term, a broader tax shift from electricity (used to produce hydrogen) to natural gas and fossil fuels.

Lastly, for the energy sector, support for hydrogen would likely be focussed on measures to promote the development of combined heat and power (cogeneration) applications. These can be incentivised through demand-side mechanisms, such as the already existing CHP certificates scheme in Flanders, as well as supply-side mechanisms, such as the capacity remuneration mechanism in Belgium, which takes the form of a reliability options scheme (comparable to contracts for difference) and is supposed to be technology neutral.

Part 5

Hy-ly Volatile? making it safe, sustainable and transportable

The regulatory context in Belgium is layered given its federalist structure. The transport of gaseous products (including the construction and operation of pipelines) falls under federal competence, while the construction, production and/or operation of hydrogen facilities (ranging from building hydrogen refuelling stations to the production of green hydrogen) are a regional competence and requirements therefore differ between the three Belgian regions. As a consequence, different public authorities and government entities, regulators and regulated operators have a role to play, applying different rule sets. This of course creates a high risk of gaps and inconsistencies in both policymaking and its application around hydrogen.

Following the European Directive 2014/94/EU82, Belgium has set up a National Policy Framework “Alternative fuels infrastructure” in which the policies and ambitions of the different government levels are brought together. That said, progress towards a uniform and clear regulatory framework throughout Belgium relating to alternative fuels, including hydrogen, remains slow and complex.

In setting up an appropriate regulatory framework, looking primarily at hydrogen for industry (i.e. large-scale production, transport through high and very high-pressure pipelines and consumption for industrial processes), one should ask at least the following questions, which are interlinked:

  • who does what? I.e. which (type of) players will be in charge of the development and operation of hydrogen networks and other hydrogen infrastructure (including production/power to gas (“P2G”) facilities, storage and refuelling stations)?
  • would future hydrogen networks be mixed (i.e. use H2 blending) or be dedicated exclusively to hydrogen?
Who does what?

Two potential pathways can be identified:

  • one where the market will (further) develop the hydrogen infrastructure. This means letting competition play fully and leaving all of the initiative to market players such as Air Liquide with its existing network of 600km of pipelines and building on this (and incentivising these players to do so). It also means allowing these players to wrap the entire value chain and make bilateral arrangements as necessary regarding the use of their infrastructure; and
  • one where a single regulated operator would be exclusively responsible for building and operating an open-access network for hydrogen transport, which users on each end of the value chain could hook up to. This regulated entity would most likely be the existing TSO for natural gas, Fluxys Belgium. The regulated option means, in its essence, that open third-party access (TPA) to the network is offered to anyone who requests it and complies with the applicable rules, conditions and technical standards, on a non-discriminatory basis, against payment of the applicable tariffs, which are set for a certain period (usually 4 years) by the TSO and approved by the regulator (probably the federal energy regulator CREG), based on a predetermined tariff methodology.
Mixed vs dedicated networks

One should also distinguish between the option of H2 blending (i.e. allowing certain concentrations of hydrogen being injected, up to certain limits, into the natural gas transport system) and dedicated hydrogen networks (i.e. networks transporting 100% hydrogen, which increases the economic value on the demand side).68

For H2 blending, the regulated option seems in any case the most obvious, given that natural gas transport is already regulated today (meaning only the TSO can really do it, subject to the regulation, given that the activities would be strongly interdependent and it would not be feasible to allow competition for the one, but not the other activity on the TSO’s network). Article 2 of the Gas Law of 12 April 1965 (the “Gas Law”) allows its scope to be extended by Royal Decree to other installations than the ones currently captured by it, and to the construction and operation of pipelines for the transport of other products than (natural) gas.69 Most provisions of the Gas Law of 12 April 1965 (e.g. the obligation to have a transport permit, network access, security of supply, supervision, etc.) could be applied similarly to mixed natural gas and hydrogen networks. Nonetheless, as the H2 molecule is much lighter than a CH4 (methane) or a CO2 molecule, from a material-technical point of view, a much more granular material is required to transport it safely and efficiently, compared to the latter molecules. A specific chapter may therefore need to be added regarding safety and technical requirements (including potentially a separate grid code) specifically in relation to hydrogen.70  This would need to deal, amongst other things, with defining common quality/content requirements (so-called H2 blending limits) and measurement/detection standards (and at which level these should be set, i.e., at a national, regional or EU-wide level). Currently Belgium does not allow for H2 blending in the natural gas transport system and has not defined any requirements or standards, although there are plans to do so in collaboration with the Belgian gas TSO Fluxys. As this will require significant investment in fitting out the network to deal with H2 molecules (for the aforementioned reasons), there may also be a significant impact on the transmission tariffs, if these investments would go into the TSO’s regulated asset base (which would immediately spurn new questions about whether all end consumers should contribute equally to that).

For the development of 100% dedicated hydrogen networks, a policy choice will need to be made to regulate this as a business similar to natural gas transport today, or to leave this entirely to free market initiative. This choice will determine how these networks will be funded and who will pay for them (see above).

Further considerations

If a regulated route is chosen for hydrogen transport, it automatically raises the question of unbundling, and whether the regulated operator (the TSO) should be restricted in its ability to develop or participate in other activities along the hydrogen value chain, such as building production/P2G installations, storage solutions, rolling out refuelling stations and other commercial activities related to hydrogen. It is currently unclear whether similarly stringent unbundling rules as those applying to the TSO in relation to natural gas today are desirable with a view to realising the full hydrogen potential, and if so, subject to which exceptions (e.g. in relation to storage or P2G).

It is worth noting that the industry is more focused in its activities today than it was before (i.e. focusing on core activities rather than maintaining big conglomerate structures). As a result, few are interested in vertically integrating the whole value chain and paying (with or without incentives) for the huge investments that would entail. There seems to be a strong preference for an open access, and ideally cross-border interconnected, hydrogen (transport) infrastructure that everyone can hook up to, both for mixed and dedicated networks (see above).

In case the tasks of development and operation of hydrogen (transport) infrastructure are entrusted to the TSO, it can use its special prerogatives set out in the Gas Law (Art. 8/7 et. Seq) to perform works on the public domain or to obtain declarations of public utility (required to erect installations and perform works on private land, and perform expropriations if necessary – see below). The two questions above (on the division of roles and the type of networks) will also have an impact on the permitting situation (see below).

Similar considerations as the ones set out above apply in relation to distribution and the use of hydrogen for transport, district heating etc., i.e. whether this should be left to the market (or potentially government owned companies or vehicles) or regulated operators such as the DSOs, who are also subject to regulatory requirements (including on third-party access and unbundling) and enjoy specific prerogatives under regional legislation.

Lastly, whether the regulated framework be brought under the existing framework for natural gas, or a dedicated regulatory framework for hydrogen be developed, it will to a large extent be shaped by EU law. This will be true in any case for determining whether a regulated, open-access regime will apply to hydrogen transport (and possibly storage) in the future, and which activities (such as production/P2G) will be excluded from that regulated business (i.e. unbundling). It will be particularly interesting to see if hydrogen will be slid into the upcoming review of the Third Gas Directive (2009/73/EC). Another important point is the need for a clear taxonomy for new gases and certain technologies (e.g. grey, blue and green hydrogen, CCS/U, biofuels/-gases and molecular energy). It will be interesting to see how the ongoing discussions regarding the RED II (Directive (EU) 2018/2001) review will play out in this regard.83



The main bottle neck for anyone wanting to develop and/or operate hydrogen infrastructure in Belgium is that there is no streamlined permitting procedure tailored to hydrogen. As a consequence, interested players should base their permitting analysis for hydrogen-related constructions and activities on the existing rules and nomenclatures for a combination of infrastructures and operations, depending on the different uses of hydrogen (such as petrochemical activities, but also for example fuel stations).71 In addition, the different competence levels make the analysis more complex as different permits may need to be obtained from different competent authorities. Gas transport activities require a federal transport licence. Building and environmental or combined/single permits are a regional competency and will therefore depend on the geographical localisation of the infrastructures.

To the extent full permitting trajectories need to be completed, the nature of hydrogen pipelines (spanning the territory of several municipalities and presenting specific safety risks) may therefore complicate things. Simplified or fast tracked permitting procedures with uniform rules across the regions could be a solution, particularly where the infrastructure would span different regions (which hydrogen transport pipelines are likely to do). The same applies by the way in relation to interconnections with neighbouring countries.


The construction and operation of pipelines for the transport of gaseous and other products (not specifically referring to hydrogen)72 require a federal transport permit in addition to the regional building and environmental permits.

The transport permit is granted by a Ministerial Decree issued by the federal Energy Minister for a maximum period of 50 years, with an option to request a 30-year renewal. The national TSO for natural gas, Fluxys Belgium, currently has a transport permit for the natural gas transmission system. Further permits may be required for the construction and operation of dedicated hydrogen networks.

Transport permit holders enjoy specific prerogatives to conduct works and erect installations on the public domain. In case it is impossible to develop the pipeline network on public land, a declaration of public utility is necessary to develop it over, on or under (undeveloped) private land in the public interest. The areas over which the pipelines pass through private plots of land are then treated as easements. A declaration of public utility is issued by a Royal Decree.

The federal Public Service Administration for the Economy (“PSA Economy”) is in charge of the management and control of the hydrogen pipelines. The PSA Economy mainly supervise the proper enforcement of the abovementioned Royal Decrees of 14 May 2002 and 19 March 2017.



In Flanders, there is no tailored permitting procedure for hydrogen projects and there is also no fast-track procedure for test installations or temporary constructions such as, for example, mobile hydrogen fuel stations. Therefore, the general procedure must be followed.

For the construction (i.e. urban development actions) and/or operation (i.e. performance of certain activities) of a hydrogen facility, a single permit would be required.

Depending on how much hydrogen would be produced or stored, additional regulatory actions may have to be taken. Examples of such additional actions are environmental impact assessments (EIA) and ad hoc safety reports, which need to be executed by accredited external experts. For the hydrogen fuel stations in Zaventem (Air Liquide) and in Halle (Colruyt), for example, two ad hoc safety reports were necessary, which was complex, time- and money-consuming.

There are three authorities potentially competent for processing the permit application: (a) the Flemish Government, (b) the relevant province (deputation) or (c) the relevant municipality (college of mayor and aldermen). A cascade system is in place to determine the competent authority. Broadly speaking, the bigger the project or if it requires the co-operation of different municipalities or provinces, the higher up in the waterfall the project will sit. Public gas transport and distribution installations are mentioned on the exhaustive list of Flemish projects, meaning the Flemish Government will be competent to issue the single permit.

The roughly estimated average timeline between filing a request for a single permit in relation to a hydrogen project and receiving it is five months.


In Brussels, there is no tailored permitting procedure for hydrogen projects and there is also no fast-track procedure for test installations or temporary constructions such as, for example, mobile hydrogen fuel stations. Therefore, the general procedure must be followed.

An environmental permit would need to be obtained. Depending on the type of activity the operation of a given hydrogen facility would fall under, it may require only a declaration, or an in-depth review by the authority.

For any new construction, a building permit would also be required. If the requested building permit covers several municipalities in the Brussels-Capital region, either one or several permits can be granted. Where only one permit is granted, the different municipalities involved will co-operate to simultaneously arrange the public surveys and only one consultation committee will be held (in the municipality that is the most impacted), in which every municipality involved will be able to participate. A hydrogen pipeline project may also be subjected to an impact study or, if it fulfils certain conditions, an impact report, which is a lighter procedure.

The Brussels-Capital region does not have a system of combined permits. If the project is a “mixed project”, i.e. a project requiring both a building and an environmental permit, two distinct demands will have to be introduced and two permits will be granted. The specificity of a mixed project is that it needs to be introduced before the Delegated Officer, who will organise the review of both demands simultaneously. At the end of the procedure, the building permit is suspended until the final environmental permit has been obtained, and vice versa. The work can therefore only be carried out and the installations operated once both permits have been obtained.


In the Walloon Region, there are currently a few projects of hydrogen tank stations in the construction and permitting phase. We gather from the ongoing procedures that construction of a hydrogen tank station is subject to a building permit and an environmental permit. The same permits would apply in the case of a project for the construction of hydrogen pipelines.

As is the case in Brussels, the request and procedure for obtaining an environmental permit in Wallonia will depend on the type of activity the operation of a hydrogen facility would fall under. If the pipeline already exists, only an environmental permit would be needed, although it could be argued that a project for the construction of hydrogen pipelines does not require an environmental permit at all, based on a list of installations and activities which require an environmental permit, on which hydrogen pipelines are not explicitly mentioned.

If the pipeline needs to be built, the construction is also subject to a building permit. In this case, the Walloon Region has a single permit, which covers both aspects. It is therefore a joint procedure, with ultimately one permit being granted. Since it is most likely that hydrogen pipelines would span the territory of multiple municipalities, the Technical and Delegated Officer are competent to grant the single permit.

For the sake of completeness, it can also be noted that there are specific sectoral conditions applicable to an installation for hydrogen.

Health and safety regulations

General and specific health and safety regulations (as provided for in the Codex on Wellbeing) must also be considered. The Codex on Wellbeing provides for certain limit values for professional exposure for several types of chemical agents, including hydrogen. Hydrogen is categorised as "A" which means that it releases a gas or vapour that in itself has no physiological effect but lowers the oxygen content in the air. When the oxygen content drops below 17-18%, oxygen causes asphyxiation, which manifests itself without prior warning. The employer has the obligation to take all necessary preventive and protective measures to prevent that these limits are exceeded. There will thus be a particular need and obligation to take this element into consideration when performing risk analysis and introducing health and safety policies.

The Codex on Wellbeing also provides for the obligation to introduce health monitoring (by the company doctor) for (i) safety functions, (ii) functions with increased vigilance and (iii) functions with a certain risk, such as due to the exposure to chemical agents. Working with hydrogen can be regarded as such function with a certain risk. The purpose of this health monitoring is to increase the health of the employees involved and to prevent any health risks.

In addition to this, due to the specific characteristics of hydrogen (a wide ignition range combined with low ignition energy causes it to burn quickly), various content-specific safety and quality regulation applies (often based on EU legislation).


A few conclusions can be drawn in terms of what changes are required to the regulated framework to further the hydrogen use case in Belgium.

  • A more uniform set of (regional) legislation, regulations and permitting trajectories for hydrogen infrastructure projects, especially those spanning the territory of multiple regions. This could entail distinguishing between different types of hydrogen production (grey/blue/green) and between normal and fast-tracked or accelerated procedures for certain pilot projects or test installations, such as mobile hydrogen fuelling stations.
  • The development of additional legislation in relation to the use of natural gas pipelines for the transport (and possibly distribution) of hydrogen (H2 blending). This should include defining clear H2 blending limits and appropriate technical (i.e. measuring and detection), safety and quality requirements (as the case may be in the form of a separate grid code for mixed networks).
  • The development of a proper regulatory framework and role division for the development of dedicated hydrogen networks, taking into account EU law developments.
  • The development of specific rules for the type or design approval of hydrogen fuel cells vessels for the use of hydrogen in the maritime and inland navigation sectors.
  • The development of a tailored set of rules and guidance on health and safety in relation to hydrogen.


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