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Generally speaking, the potential for large-scale hydrogen production, import, transport and consumption by and for industry is the most promising use case in Belgium. 5
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. In Belgium there are no less than 613 kilometres of hydrogen pipeline, with junctions around the ports of Ghent (North Sea Port) and Antwerp-Bruges, still one of the biggest networks worldwide anno 2023. 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.
Map of existing and planned Belgian hydrogen and related infrastructures (source: WaterstofNet, Cluster TWEED and Fluxys) 7
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).
As in most countries, for transportation, the focus is mainly on the electrification of cars. Nonetheless, for trucks and public transport (buses), hydrogen may be part of the solution as well. Belgian bus builders Van Hool and VDL are both actively building hydrogen buses and exporting them abroad. A lot of 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).8 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.9 The first pilot project powered by hydrogen was the (smaller) passenger ship Hydroville operating on the Scheldt between Antwerp and Kruibeke.10 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. Three more hydrogen-powered ships are currently being built in Flanders and the Netherlands and an H2 bunkering installation is being built in the port of Ostend, as part of the Implementation of Ship Hybridisation (IHSY) project.11 There is also a large potential for derivates such as ammonia in the maritime sector.
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.12
Because hydrogen can provide both electricity and heat, there is also increasing interest from the buildings and power sectors. The focus is on combined heating and power (cogeneration) installations for buildings (where electrification is less obvious) and on heat networks in the cities, on closed (industrial) sites and energy communities. Moreover, hydrogen has been proposed as a large-scale electricity storage solution (electricity stored in hydrogen and its derivates, as a supplement to batteries, can be an important tool to balance the grid). Notwithstanding all this, the buildings and power sectors currently seem to offer less important use cases for hydrogen in Belgium.13
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.14
On 14 October 2022, the Belgian federal government updated its hydrogen vision and strategy (originally published on 29 October 2021), unveiling its ambition to turn Belgium into a European (clean) hydrogen import and transit hub (the “Hydrogen Strategy”).15
The Hydrogen Strategy revolves around four sectors and four pillars. Industry, transportation, buildings and power generation are the four sectors identified as having potential for using hydrogen and its derivates as a decarbonisation lever, with the former two having the strongest use case (as also identified by BCG – see above).
Across these target sectors, the Hydrogen Strategy is built up around four pillars:
The Hydrogen Strategy recognises the limited potential for domestic green hydrogen production on the one hand, and the varying potential of the different use cases across economic sectors on the other. It therefore takes a pragmatic approach that is focused on import, transport over longer distances and use cases requiring the specific characteristics of H2 and derived molecules, in particular the (petro)chemical industry. This is reflected in the first pillar, which seeks to establish Belgium as an import and transit hub for renewable (hydrogen and derived) molecules in Europe.17
Three major import routes are identified, the most important of which, with the most immediate potential, being the so-called North Sea route. It aims at a combination of domestic green hydrogen production via power-to-gas (P2G) installations, coupling offshore wind power generation18 with hydrogen production in the North Sea, and developing an interconnected pipeline network, in particular with the UK and Norway. Hydrogen thus produced and/or imported offshore, could then transit through Belgium to neighbouring countries such as the Netherlands, Germany and France, all of which face similar constraints on domestic renewable hydrogen production and will need to import volumes of it.
As a secondary option for piped H2, the Southern route is considered, which is aimed at importing hydrogen from the Iberian Peninsula and Morocco (all countries with abundant renewables). In the short to mid-term, most of these volumes will however be consumed already along the way, notably in France. Further interconnections over land would be required is well. It is therefore considered a viable option only in the mid-long to long term (horizon 2040). Lastly, there is the Shipping route, which is mostly focused on importing hydrogen derivatives into Belgium by ship from locations across the globe, either to be used as direct feedstock or to be cracked back into hydrogen and injected into the grid (the latter being considered a less efficient and rather more expensive option than the other two routes for pure H2 imports). It could nonetheless be useful to diversify supply and build strategic stocks. The federal government has entered into memoranda of understanding with Oman and Namibia and is planning more with other countries (as part of the fourth pillar).
The Hydrogen Strategy recognises that electrolysis capacity to produce domestic green hydrogen in Belgium remains limited due to the limited renewable power generation potential (despite the offshore ambitions under the North Sea route, but the majority of renewable power generated offshore will be directed towards greening the grid and meeting growing electrification needs). It nonetheless considers the development of a minimum electrolysis capacity in the short term (150MW by 2026) of strategic importance, as a way to place a lever under Belgium’s technological leadership in certain crucial subsets of the hydrogen value chain (e.g. through companies like John Cockerill, which claims to account for 33% of the world’s supply of electrolysers19). Boosting national champions and exporting technology constitute the Hydrogen Strategy’s second pillar, and the federal government has identified a number of available funding instruments to be directed towards that goal.20
On the third pillar (building a robust hydrogen market), government action has mainly focused on getting the Hydrogen Bill22 through parliament, which aims at regulating the hydrogen midstream in Belgium. This is consistent with the first pillar goal of making Belgium a European import and transit hub by developing an open-access hydrogen transport network, part of a European backbone. In addition to that, to further unlock demand, the federal government is supportive of regional and European efforts to develop a market platform for hydrogen and derivatives, establish gas quality standards and a European (voluntary) certification scheme and register based on clear definitions, qualification criteria and calculation methods for establishing the green or low-carbon character of H2 and derived molecules.23
The choice of one vector over another will be driven by available technologies as well as availability and price of the different molecules. Both H2 and derived molecules will play a role. Under different scenarios depending on various sensitivities, H2 molecules are projected to account for 30-60% of total demand by 2050, with derived molecules (such as ammonia, methanol or e-fuels) projected to account for the remaining 40-70%.
Under the last pillar, the federal government wants to invest in cooperation with the regional governments, European and international partners, translating back to each of the other pillars. It also wants to build a hydrogen ecosystem involving all market players, including companies, research institutions and organisations. This collaboration is formalised via the Belgian Hydrogen Council24, which was established in March 2023. It combines all Belgian members of the Waterstof Industrie Cluster representing the Flemish and Dutch hydrogen clusters, coordinated by WaterstofNet since 2015, and all members of H2 Hub Wallonia representing the Walloon hydrogen clusters, coordinated by Cluster Tweed since 2020.25
Under its regional hydrogen strategy, published on 7 December 2020 by the Waterstof Industrie Cluster in response to the Flemish Government’s vision note26, the Flemish Region targets 200MW of green hydrogen production27 at its sea ports by 2025 and 500MW by 2030.28 It estimates to receive EUR 125m of funding as an Important Project of Common European Interest (IPCEI) for that purpose.29 The port of Antwerp-Bruges, with its LNG infrastructure in Zeebrugge (which in time could be repurposed for hydrogen imports) and its (petro)chemical cluster in Antwerp as a large industrial off-taker, 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 2030.30
WaterstofNet, a Dutch-Flemish, non-profit interest association, has been particularly active in driving and promoting pilot and demonstration projects in the past 14 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 Hydrogen Region (“Waterstofregio”), which ran from 2009 to 2013, and its successor Hydrogen Region 2.0 (“Waterstofregio 2.0”), which ran from 2016 to 2022. These projects brought together companies in the Flemish and Dutch regions across the hydrogen value chain around a number of unique demonstration projects, focused on the development of hydrogen powered vehicles (both via fuel cells for electric motors and combustion engines), hydrogen refuelling infrastructure in the Benelux region (also through H2ME31 and H2Benelux 32) and certain industry applications. 33 WaterstofNet also coordinated and held the pen of the Flemish Hydrogen Strategy for the Waterstof Industrie Cluster, published on 7 December 2020.
Green Octopus 2.0 (2023-2025), officially launched in February 2023, is an ambitious co-operation between the Benelux, France and Germany to establish a hydrogen market between them (and eventually within Europe) under the auspices of WaterstofNet, involving governments, producers, port authorities, gas infrastructure companies and large-scale users. 34 Its predecessor HyFLOW/Green Octopus project, launched in 2019, envisaged the construction (or repurposing) of a 2,000km hydrogen backbone connecting Belgium and its North Sea offshore cluster to its neighbouring countries (the Netherlands and Germany). It also supported its 12 project partners with their application processes for the Important Project of Common European Interest (IPCEI) calls Hy2Tech and Hy2Use. 35
HyPACT (“Hydrogen through Plasma Ammonia Cracking Technology”) (2022-2025) is a project supported under the Energy Transition Fund (see Chapter 4), for which WaterstofNet partners up with two Flemish universities to investigate whether an alternative process, based on plasma technology, can provide a more efficient method to convert ammonia to hydrogen.36
Within the Hydrogen Import Coalition (phase 2, 2021-present) a number of large industrial players team up with WaterstofNet to investigate the possibilities for large-scale import of hydrogen and derived molecules by ship from other continents (cf. the Shipping route under the Hydrogen Strategy’s first pillar). 37
Inn2POWER (phase 2, 2021-2023) is an Interreg North Sea Region project, aimed at supporting innovation, improving SME access to and building a green hydrogen economy by connecting offshore wind and green hydrogen businesses in the North Sea (P2G). 38
REVIVE/Waste-to-Wheels (2017-present) concerns the demonstration of Tractebel’s Waste-to-Wheels solution through the design, build and testing during a two-year period (between 2021 and 2023) of 15 hydrogen fuel cell-powered garbage trucks in eight regions across Europe. Waste-to-Wheels is a circular model designed and developed by Tractebel in 2017 to transform plant waste into renewable fuel, where hydrogen is produced near an incinerator and used locally for various mobility applications. The REVIVE initiative receives support under the EU’s Horizon 2020 programme. 39
H2BE (2021-present) is a joint venture between ENGIE and Equinor to investigate, select and develop projects for the production of low-carbon hydrogen from natural gas in Belgium. Following a satisfactory feasibility study, a joint development agreement was signed in 2023 to progress the development of a facility at ENGIE’s Rodenhuize site in Ghent.40 Discussions are also ongoing with North Sea Port and Fluxys on the facility’s integration with port infrastructure, as part of the former’s Connect 2025 strategic plan on hydrogen and CO2 infrastructure. 41
Fluxys has been granted direct participant status under the IPCEI Hy2Use for the development and construction of a backbone of pipelines and installations for the import and transport of hydrogen all across Belgium, including interconnections with neighbouring countries (the H2Backbone). The total investment is estimated upwards of EUR 1.5bn. If appointed the new single HNO under the Hydrogen Bill (when implemented), Fluxys will also be operating the backbone under an open-access regulatory regime (see Chapter 5).
ENGIE, Carmeuse (via TEC4Lime) and John Cockerill signed a joint development agreement for a carbon capture and utilisation (CCU) project in the Walloon Region (project Columbus). The sponsors of the EUR 150m project submitted an application for funding to the EU Innovation Fund and were also granted direct participant status under the IPCEI Hy2Use. The project will concentrate CO2 captured from a lime kiln and combine it with green hydrogen to produce e-methane, which could then be injected into the gas grid or used in transport or the industry. The green hydrogen will be produced by a 75MW electrolyser powered by renewable energy. Implementation of the project is ongoing and sponsors expect it to be operational by 2025.
Indaver, ENGIE, INEOS (via Inovyn), Oiltanking, Fluxys, Port of Antwerp and PMV (via VMH) are part of a consortium working on a power-to-methanol project in the Antwerp port area (Power to Methanol), 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.
Engie, Fluxys, ArcelorMittal and others are also working on a similar power-to-methanol project in the Ghent port area (North C Methanol), involving the production of green hydrogen by a 63MW electrolyser to then be used for an estimated annual 44,000 tonnes of green methanol production, resulting in an annual 1mio tonnes of CO2 reduction.
Fluxys, Virya Energy, 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 (scalable to 100MW) in the port of Zeebrugge.
Deme, PMV, Air Products and Port of Ostend are co-developing the HyPort project, aimed at realising a green hydrogen production plant in the Ostend port area, able to produce 50,000 tonnes of green hydrogen annually, the equivalent of 300 MW of power capacity, which should be operational by 2025.
John Cockerill, an established manufacturer of hydrogen electrolysers, has set up a JV with Dutch/French company Technip Energies, which will be headquartered in Belgium and provide integrated and competitive end-to-end green hydrogen solutions. The JV will draw on John Cockerill’s industrial knowhow and experience in manufacturing electrolysers, and will benefit from a capacity reservation and supply contract for pressurized alkaline electrolysers with John Cockerill Hydrogen.
Separately, John Cockerill has also formed the Hyve consortium with Bekaert, Colruyt Group, Deme, Imec and Vito to develop more efficient components and systems for electrolysers, and is planning the construction of a multi-site gigafactory for large-scale alkaline electrolysers for the European market in Seraing (Belgium) and Aspach (France), for which it was granted direct participant status under the IPCEI Hy2Tech.
John Cockerill is also teaming up with Liege Airport to equip the airport with installations for the production, distribution, and the use of green hydrogen both for airport and external vehicles. The project was greenlighted by the Walloon government in 2021 and planned to be operational in 2022.
Other interested players on the Belgian hydrogen scene (both on the demand and the supply side) include: BASF, Agfa-Gevaert, Borit, Breuer, Colruyt Group, Cummins, Infinium, Lhoist, Plastic Omnium, Aertssen, EDF Luminus, Jan De Nul, Nippon Gas and Air Liquide.
Currently, hydrogen production in Belgium is quasi 100% grey or yellow, but is expected to become gradually greener over the coming years.42 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.43 Blue hydrogen could therefore be a useful supplement, provided that CCS/U technology can be mastered and some existing obstacles44 to its development are cleared.
This is reflected in the Hydrogen Strategy, which expressly states that only renewable hydrogen will have a place in the country’s energy mix before 2050, and by the alternative Southern and Shipping routes. A phased approach is nonetheless put forward to ensure the lowest possible carbon emissions and a level playing field for various operators, taking account of the economic context. This means blue and turquoise hydrogen, respectively produced with CCS/U or via pyrolysis, amongst other things, will play a transitional role.
The industry and 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, broad support seems to exist among these players for a regulated asset base (“RAB”) model, pursuant to which the regulated network operators (in particular, the national gas TSO Fluxys Belgium, 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 hydrogen network,46 which will guarantee them open access to the (existing and future) infrastructure for the benefit of their own core businesses. The cost of this would be ultimately borne by consumers, through the (gas and/or hydrogen) transport and distribution tariffs.
The Belgian federal government has followed suit with its intention (under the third pillar of its Hydrogen Strategy47) to a appoint a single hydrogen network operator (HNO) to own, develop and operate a dedicated and interconnected hydrogen transport network (part of a European backbone) under an RAB model with open access and regulated tariffs. The Hydrogen Bill48, which was recently approved by Parliament and is expected to enter into force still this year (upon the appointment of a HNO), effectively introduces this model.
In addition to this, under the Hydrogen Bill, the federal Energy Minister is given the possibility, subject to an opinion of the federal energy regulator CREG, to grant investment subsidies to the HNO for the development of the hydrogen transport network. A number of conditions need to be fulfilled to justify issuing such subsidies. Amongst other things, the project(s) for which subsidies are requested must be compatible with the Hydrogen Strategy, including the (inter)connection with hydrogen networks abroad, to the terminals and storage facilities. Subsidies can only be applied against the investment cost and up to a maximum of 50%. They cannot be used to increase the HNO’s profitability nor included in the RAB (as to do so would lead to an increase in tariff revenues and therefore a double compensation). Subsidies must also be cleared under EU state aid rules. If a project for which subsidies have been committed does not obtain, or lose, its required permits, or the conditions (as documented in a subsidy agreement between the HNO and the government) are no longer fulfilled, the subsidies can be suspended, reduced, made subject to additional conditions, withdrawn or claimed back, as the case may be.
In addition, industry may be incentivised to invest in hydrogen infrastructure through other, indirect supply-side measures, such as carbon taxation (e.g. through the reformed EU ETS and carbon border adjustment mechanism, or carbon contracts for difference, 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.49 A number of Belgian hydrogen projects have been selected as Important Projects of Common European Interest (IPCEIs) under the Hy2Tech and Hy2Use IPCEI calls (see Chapter 2), meaning they can benefit from pre-approved state aid.
Direct funding is available for hydrogen (pilot) projects at various stages of the value chain, both under EU and Belgian instruments. The Hydrogen Strategy mentions the following Belgian (federal) funding instruments already committed across the first three pillars (more funding could yet be unlocked both at federal and regional level):
developing 100-160km of additional (new and/or repurposed) hydrogen pipelines by 2026 to be owned and operated by the HNO;
completing an interconnection with Germany’s hydrogen network by 2028, also to be owned and operated by the HNO; and
bringing at least 150MW of electrolyser capacity into operation by 2026.
The federal government in its Hydrogen Strategy has also put forward the possibility of indirect support through tax credits and exemptions from taxes, excise duties and surcharges.50 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: 51
Lastly, for the buildings and power sectors (based on their most likely use cases as set out in Chapter 2), support for hydrogen could be focussed, amongst other things, on measures to promote the development of electricity storage solutions for grid balancing and combined heat and power (cogeneration) applications for buildings. These can be incentivised through demand-side mechanisms, such as the already existing CHP certificates schemes in the three regions, as well as supply-side mechanisms, such as the federal 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.
The regulatory context in Belgium is layered given its federalist structure. As regards the energy policy, the federal government remains competent for large infrastructures for the storage, transport and production of energy, to the extent required to ensure the country’s security of supply.52 According to the Council of State53, hydrogen as an energy carrier falls under that provision. Consequently, large scale import, transport (at high and very high pressure), production and storage of hydrogen can be considered to fall under federal competency, whether the hydrogen is green, grey or anything in between.54 Everything else, including the public distribution (at medium and low pressure), supply (whether or not to household consumers and regardless the size of the infrastructure) and small-scale storage and production (not having a substantial impact on the security of supply) are a competency of the regions. The same holds true for the (re)production of electricity from green hydrogen as a renewable energy source, as well as most environmental rules and regulations (including the issuance of building and environmental permits).
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 across different sections of the value chain, applying different rule sets. While the various governments have attempted to address this through consultation55, considerable gaps and inconsistencies remain in both policymaking and its application around hydrogen.
Following the Alternative Fuels Directive56, 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 those sections of the hydrogen value chain that are federally regulated, that is to say, large-scale hydrogen infrastructure for and by the industry (i.e. large-scale production, storage, import and transport of hydrogen through high and very high-pressure pipelines and its use for industrial processes), one should ask at least the following questions, which are interlinked:
The answer to these questions will also have an impact on the permitting situation (see below).
Two potential pathways can be identified:
One should also distinguish between the option of H2 blending (i.e. allowing certain concentrations of hydrogen being injected, up to certain limited thresholds, into the natural gas transport system) and dedicated hydrogen networks (i.e. networks transporting high-quality grade hydrogen , which increases the economic value on the demand side).59
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 federal law of 12 April 1965 on the transport of gaseous products through pipes60 (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.61
Most provisions of the Gas Law currently applicable to natural gas (e.g. the obligation for operators to hold a valid transport license, rules on network access, security of supply, market monitoring and supervision, etc.) could be applied similarly to mixed natural gas and hydrogen networks. Nonetheless, as the H2 molecule is much lighter and less granular than a CH4 (methane) or a CO2 molecule, from a material-technical point of view, a much denser 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 H2 blending and mixed natural gas and hydrogen networks.62 This would need to deal, amongst other things, with defining common quality/content requirements (so called H2 blending limits63) 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. As it would 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 (natural gas) transmission tariffs, if these investments would go into the TSO’s regulated asset base for natural gas transport, which would immediately spurn new questions about whether all end consumers should contribute equally to that. For these and other reasons (including safety and the need to avoid getting locked into stranded fossil fuel assets), the federal government in its Hydrogen Strategy has dismissed the option of mixed natural gas and hydrogen networks as a viable long-term solution.
For the development of dedicated hydrogen transport networks and associated infrastructure, in line with and in anticipation of the EU’s Gas Decarbonisation Package64, a clear policy choice has been made to regulate this as a business similar but separate to natural gas transport today.
The Gas Law currently regulates the transport of gaseous products in Belgium, including amongst other things the obligation for operators to hold a valid transport license, rules on network access, security of supply, monitoring and supervision of the (natural) gas market by the CREG. Since hydrogen is considered a gas65, a number of general provisions of the Gas Law already apply to hydrogen today. These include most notably the transport license obligation, as well as rules on health and safety and the establishment and application of technical regulations (grid codes). Under the current framework, every market player holding the required transport license under the Gas Law, is allowed to freely develop and operate a hydrogen transport network, potentially competing with other hydrogen network operators.
Upcoming new legislation is set to change this.
On 10 January 2023, the federal government submitted a legislative proposal to Parliament to regulate the hydrogen midstream in Belgium (the “Hydrogen Bill”).66 The Hydrogen Bill lays out a proposed new regulatory framework concerning the transport of high-quality grade hydrogen67 through pipes. The Hydrogen Bill lifts the framework for dedicated hydrogen networks out of the Gas Law and subjects it to a more comprehensive and coherent stand-alone regime, subject to (i) a limited number of matters to which the Gas Law will continue to apply, as expressly stated in the Hydrogen Bill, and (ii) a derogatory regime for existing hydrogen networks.
The Hydrogen Bill is driven by the aim to provide legal certainty to hydrogen project developers, and emphasizing the importance of a speedy development of an integrated hydrogen infrastructure to establish Belgium as a future hydrogen import and transit hub, in accordance with the federal government’s Hydrogen Strategy. It is worth noting that the government did not wait for the approval and publication of the final Regulations and Directive of the EU’s Gas Decarbonisation Package.68 Among the reasons given for this, besides delays in the EU’s legislative agenda, are the desire to maintain the benefit of Belgium’s historic hydrogen network (one of the most developed in the world) and turn that into a first mover advantage by positioning Belgium as an import and transit hub with a fast and well-planned development and realisation of infrastructure, part of a European backbone, to which neighbouring countries can connect. In addition, an open-access hydrogen network is crucial for the successful implementation of a large number of other hydrogen (pilot) projects that are receiving government support (amongst others under Belgium’s national Recovery and Resilience Plan – RRP) and whose business case often counts on such open access.
The key pillars of the Hydrogen Bill are:
The Hydrogen Bill distinguishes between hydrogen transport installations generally, including the existing networks, all of which are brought within its scope, and a (future) hydrogen transport network, i.e., an integrated system of hydrogen pipelines that are interconnected or destined to be interconnected, which will be operated by the HNO. This hydrogen transport network is meant to become the backbone of the Belgian hydrogen market. In addition to general rules that will apply to all hydrogen transport installations, a specific set of rules will apply to the hydrogen transport network and the HNO on the one hand, and to existing hydrogen networks on the other (see below).
The installations for which a hydrogen transport license has been issued, their construction and operation will be considered of public use and license holders will enjoy the same special prerogatives as gas transport license holders currently do under the Gas Law 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), and they will be subject to the same safety prescriptions and technical codes as under the Gas Law.
Single HNO for dedicated hydrogen transport network
The Hydrogen Bill sets out a procedure and criteria69 for the appointment of a single hydrogen network operator (the HNO), which will become exclusively responsible for developing and operating an open access hydrogen transport network.
The HNO will be entrusted with tasks similar to those of the natural gas and electricity TSOs, including:
To guarantee its independence and the non-discrimination of network users, the HNO will have to respect stringent unbundling requirements, based on the existing regime for the natural gas and electricity TSOs:
Compliance by the HNO with the unbundling requirements will be established and monitored on an ongoing basis through a certification procedure run by the CREG, in a very similar way to what exists today for the gas and power TSOs.
Derogatory regime for existing hydrogen networks
A derogation from the general principle is given to undertakings other than the HNO that own and operate an existing network, which will be able to obtain a hydrogen transport license for expansions71 to that network, provided that the HNO has been asked to investigate the same investment and it is in the public interest to opt for the expansion, taking various elements into account.
While they can continue to own and operate their existing network (including any licensed expansions), the owners of an existing network can opt to transfer it to the HNO. The CREG will be tasked with developing a methodology for the valuation of those assets when they are brought into the HNO’s regulated asset base. The HNO will not be obliged to acquire any existing networks.
Alternatively, owners of an existing network can opt to appoint the HNO as an independent operator. The Hydrogen Bill sets out a specific procedure and conditions for such an appointment, as well as the respective rights and responsibilities of both the network owner and the HNO in such a set-up.72 In any event, the HNO will be responsible for granting third-party access to network users and for the network development plan.
With the derogatory regime, the government has sought to strike a balance between the demands of owners and operators of existing hydrogen networks to protect their property rights and honour their long-term commitments, and its desire to facilitate the gradual integration of these networks with the HNO’s hydrogen transport network. An initial time limit for the derogatory regime was taken out of the latest draft of the bill, as the government decided to await the outcome of ongoing negotiations on EU level regarding the Gas Decarbonisation Package. Such a time limit might yet be reintroduced on transposition of the new European rules when agreed.
Monitoring and supervision by the CREG
The CREG is designated as the independent regulator for hydrogen transport, monitoring and supervising the application of the new rules. It will have the same tasks and competencies as under the Gas Law to the extent relevant and required. It can take investigative measures and impose administrative sanctions also in accordance with its powers under the Gas Law.
Same as for gas and electricity, decisions of the CREG can be appealed before the Market Court of Brussels in accelerated proceedings. The Market Court has the power to suspend decisions until its judgment in case of urgency and for serious reasons, and can rule to temporarily or definitively uphold certain consequences of annulled decisions.
The Hydrogen Bill does not provide for detailed regulations which will only be set out through royal or ministerial implementation decrees, which have yet to be drafted. Moreover, further changes may result from the transposition of the EU’s Gas Decarbonisation Package proposals, once they will have been agreed and approved. In anticipation of this (and following heavy lobbying by the main operator of existing networks Air Liquide), in a series of last-minute amendments submitted to Parliament on 8 June 2023, the federal government walked back a number of important aspects of its proposal, including the initial end date of the derogatory regime for existing networks that was originally set on 31 December 2030 (this is now left open) and the regime of negotiated access that was supposed to apply to those existing networks, on the basis that there remains too much uncertainty surrounding the European negotiations on that point.
The scope of the Hydrogen Bill is limited to hydrogen transport installations. Due to uncertainty regarding the required or optimal infrastructure for the related terminal, storage and reconversion activities, the Hydrogen Bill does not (yet) cover the organisation of these activities in order to let the market determine the most appropriate model first. Nor does it cover any regional activities such as supply and distribution.
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. Unlike the federal government, the regions have not yet started working on a corresponding framework for hydrogen distribution.
Another important point is the need for a clear taxonomy for new gases and certain technologies (e.g. the different colours of hydrogen, CCS/U, biofuels/-gases and molecular energy). The ongoing review of the RED II73, on which political agreement was reached on 19 June 202374, addresses these items and, together with the Commission’s recently adopted delegated acts on RFNBOs75 and calculating GHG emissions savings76, will be of particular relevance for the future qualification and certification of pink (i.e. nuclear produced) hydrogen and hydrogen derivatives (RFNBOs77).
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).78 In addition, the different competency levels make the analysis more complex as different permits may need to be obtained from different competent authorities. When the Hydrogen Bill (and the Ministerial Decree appointing the HNO) enter into force, new hydrogen transport infrastructure will require a federal hydrogen transport license, while existing hydrogen networks (subject to exceptions) will remain subject to a federal gas transport licence under the Gas Law. Building and environmental 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 (in line with the new TEN-E Regulation79), 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.
Currently, the construction and operation of pipelines for the transport of gaseous and other products (not specifically referring to hydrogen)80 require a federal transport license in addition to the regional building and environmental permits.
The transport license 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 license for the natural gas transmission system. Further permits may be required for the construction and operation of dedicated hydrogen networks.
From the date of entry into force of a Ministerial Decree appointing the HNO, the construction and operation of all hydrogen transport installations will be subject to a specific hydrogen transport license (in replacement of the currently existing gas transport license), to be issued by the federal Energy Minister in accordance with a procedure and licensing criteria still to be established. As from that date, only the HNO will be able to apply for a hydrogen transport license under the new law and the operation of hydrogen transport installations will be exclusively reserved to the HNO, either as owner and operator (in a fully ownership unbundled set-up) or as an independent operator of existing hydrogen networks owned by a different undertaking, subject to certain specific rules (see above).
Nonetheless, under the derogatory regime, so long as an existing hydrogen network continues to be operated by an undertaking other than the HNO, it will remain subject to the “old” gas transport license requirement that currently applies to it under the Gas Law and its implementing decrees. If and when the network is acquired by and/or its operation is transferred to the HNO, it will come under the application of the new hydrogen license requirement (subject to a simplified licensing procedure).
Gas transport license holders currently 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. Similarly to this, hydrogen transport installations will be considered of public use and hydrogen license holders will enjoy the same special prerogatives as gas transport license holders currently do under the Gas Law.
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, an integrated building and environmental permit (“single environment permit” or “omgevingsvergunning”) 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: (i) the Flemish Government, (ii) the relevant province (deputation) or (iii) 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 environment permit.
The roughly estimated average timeline between filing a request for a single environment 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 and environmental permit. The same 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 an integrated building and environmental permit (“single environment permit” or “permis unique”), 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 environment permit.
For the sake of completeness, it can also be noted that there are specific sectoral conditions applicable to an installation for hydrogen.
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).
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