Part I - Current Hydrogen Regulation on the Continents

2 Hydrogen Regulation in Europe The EU’s ‘Hydrogen and Decarbonised Gas Market’ – Best Practice or Missed Opportunity?

Leigh Hancher and Simina Suciu

2.1 Introduction

The EU’s path towards net-zero carbon was triggered with the launch of the European Green Deal,¹ a comprehensive policy roadmap adopted in 2019 to transform the Union’s economy² and align it with the goals of the Paris Agreement of 2015.³ Major importance is attached to hydrogen (H2) in the ongoing energy transition and for the realisation of the EU’s ambitious and legally binding net-zero target.

Consequently, one of the two strategic pillars aimed at reaching the targets in the Green Deal’s roadmap focuses on H2.⁴ This roadmap spans twenty action points, including the design of the enabling market rules for the deployment of H2, based on a review of the EU’s existing gas legislation.

Hydrogen can be used as a direct energy carrier, it can support storage and transport, it can function as an alternative fuel for e-mobility and it can be used as a feedstock – that is, an input for oil refining/petrochemicals, ammonia and steel production.⁵ Today, renewable and low-carbon H2 gases are not yet cost competitive compared to fossil-based H2 gas. By 2050, the European Commission (EC) estimates that gaseous fuels, largely H2 and biogases, will make up a fifth of final energy consumption, and by 2030 Europe is expected to have a ‘pure’ H2 market in place.⁶

Building on the promise to make the EU’s climate, energy, transport and taxation policies fit for reducing net greenhouse gas (GHG) emissions by at least 55 per cent by the Green Deal’s intermediate target date of 2030, in July 2021 the EC adopted its first series of more targeted proposals (the ‘Fit for 55’ initiative). This promotes, inter alia, demand for and production of renewable and low-carbon gases, including H2.⁷

2.1.1 The Gas Package

In December 2021, the EC released its ‘Hydrogen and Gas Market Decarbonisation Package’ (Gas Package).⁸ This package, also sometimes referred to as the ‘Fourth Gas Package’, includes a proposal for a gas directive (GD) and a regulation (Regulation) establishing common internal market rules for renewable and natural gases and for H2, to foster decarbonisation, create the conditions for a more cost-effective transition and reach the EU’s goal of climate neutrality by 2050. It is a recast of the ‘Third Gas Package’ and extends its scope to cover H2 networks.

Both the GD and the Regulation contain provisions (set out in separate chapters) applicable to natural gas systems and to dedicated H2 networks. More specifically, the GD includes provisions on the unbundling of H2 network operators and their certification. It also addresses topics that are common to both natural gas and H2, including: (i) consumer protection; (ii) third-party access (TPA) to infrastructure and integrated network planning; (iii) rules for transmission, storage and distribution system operators; and (iv) rules on independent regulatory authorities.

Read in conjunction with the GD, the Regulation lays down rules on the organisation of the decarbonised gas and H2 markets, on H2 blends for natural gas systems and cross-border coordination on H2 quality. It also elaborates principles and rules concerning: (i) tariffs for network access and discounts; (ii) the separation of regulated asset bases (RAB), TPA services, principles of capacity-allocation mechanisms and congestion-management procedure; and (iii) the duties of regulatory authorities and regional cooperation between them.

With this Gas Package and the ambition to adopt a comprehensive system of regulation for H2 and decarbonised gases, the EU aimed at the time to be one of the world’s jurisdictions, along with the United States, to lead on H2 policy development.⁹ Belgium, probably one of the most developed H2 markets, adopted specific H2 transport legislation in July 2023.¹⁰ Some countries (such as Australia) have amended their existing regulations to include H2, while other countries (China, Republic of Korea) are developing H2-specific technical guidelines.¹¹

The launch of the Gas Package in 2021 was subsequently overtaken in March 2022 by the ‘RepowerEU’ Plan, which was triggered as a response to the global energy crisis. This initiative called for an acceleration of the roll-out of renewable energy to complete the energy transition and replace the use of fossil fuels, contributing to the further reduction of dependence on energy supply from Russia. This means, inter alia, building more renewable energy generation capacity and faster, as well as ensuring the enhanced integration of renewable energy sources into final energy uses.¹²

Nevertheless, a major pillar of the RepowerEU plan is the ‘Hydrogen Accelerator’, which sets out an ambitious strategy to double the previous EU renewable H2 target to ten million tonnes of annual domestic production, plus an additional ten million tonnes of annual H2 imports. Meeting these targets requires the EU to significantly upscale its manufacturing capacities, speed up development and retrofit infrastructure to allow for future H2 readiness.

There is increasing scepticism that these targets are realistic.¹³ This uncertainty impacts on the transportation, distribution and storage of domestically produced H2 and imported H2 from countries with adequate renewable energy resources.

This chapter will first describe certain concepts in the Gas Package, which – as we explain – have proved controversial in the ongoing EU legislative process. We question whether these concepts are ‘fit for purpose’ in the H2 market context given two main differences between the regulatory framework applied to natural gas versus H2.

2.1.2 Natural Gas and H2: The Main Differences and Challenges in Regulation

A first key difference between the implementation of the current natural gas regulatory framework (as enacted through the gas packages of 1998, 2003 and 2009) and the provisions in the new Gas Package is that the former rules were intended to regulate an existing, profitable and mature natural gas market with well-developed infrastructure. By contrast, there is currently no real H2 market, let alone any well-developed infrastructure, and the high costs of H2 production together with a lack of means for transporting renewable H2 have become a challenge for the development of this market.¹⁴

A second key difference between natural gas (methane) and H2 is that, while the former must be transported from point of production (an onshore or offshore gas field) to the point of use, the latter can be produced near input sources and then transported to the point of use. H2 is also more difficult and more expensive to transport over long distances compared to natural gas; thus, a European-wide H2 pipeline network or ‘H2 backbone’ may not necessarily materialise. This seems to have partially made its way into EU policy given the references to EU ‘H2 hubs’ and ‘H2 valleys’.¹⁵ With current technologies, transport often doubles the price of H2 for the end user. It is more logical to start with H2 clusters around Europe’s key port areas and experiment with different transport modes and carriers between them and production centres in third countries.

In view of these differences, this chapter analyses the key instruments to be deployed in the proposed regulatory exercise. We first focus (in Section 2.2.2) on the ‘regulatory holiday’ concept in the H2 market context, and whether, as developed in the Gas Package, this approach facilitates the inception of an H2 market.

Next, we turn to a detailed critique of three of the principal regulatory building blocks of the new Gas Package: unbundling (Section 2.3), tariff regulation (Section 2.4) and TPA (Section 2.5).

In conclusion, we question in Section 2.6 whether the ambitious timelines and targets envisaged by the new Gas Package, the mirroring of some parts of the existing framework for natural gas regulation in a dedicated H2 network and in renewable and low-carbon H2 used for injection into the natural gas systems, as well as the EC’s approach to a nascent EU H2 market, are realistic and appropriate to pursue its decarbonisation goals.

2.2 Overview and History of the Hydrogen and Decarbonised Gas Market Package

2.2.1 Scope and Definitions

In its 2021 Impact Assessment accompanying the Gas Package, the EC anticipated: (i) an H2-based infrastructure, which will complement and partly replace the current natural gas infrastructure and (ii) a methane-based infrastructure, which will evolve from the current natural gas-based system to one which uses primarily biomethane and synthetic methane.¹⁶

These two separate infrastructures are to be subject to similar but not identical regulatory principles. It is, therefore, immediately evident that certain definitions and regulatory concepts are central to understanding how these different sets of infrastructure will be developed and regulated.

The expansion in the new Gas Package to include other types of gas besides natural gas and liquefied natural gas (LNG) is already an improvement given the increasing lack of clarity around the scope and applicability of the Third Package to H2 or blended H2 – it is no longer reflecting market developments.

In this regard, the EC confirmed that ‘the Third Gas Package applies to all gases that can be safely injected into the gas network, which include hydrogen blended safely into the natural gas system’ but the Third Gas Package ‘does not apply to dedicated hydrogen infrastructure’.¹⁷

Pure Hydrogen What Is It?

Hydrogen is lighter than air, and can be transported, stored and transformed into other carriers. Based on the energy source and the means used for its production,¹⁸ as well as its greenhouse emissions, H2 is often categorised based on a colour code. Figure 2.1 matches the coloured H2 types (mainly green, grey and blue H2) with terms from the EU legislation to the extent possible.

Figure 2.1 The coloured H2 types¹⁹

Even if the EC proved reluctant to embrace this colour code, it could not totally avoid the controversy of whether H2 could really prove to be ‘the silver bullet’ for decarbonisation. The EU Hydrogen Strategy refers to different H2 categories, such as ‘electricity-based H2’ (which encompasses all categories of H2 produced with electricity irrespective of its source) and ‘low-carbon H2’ (which includes blue H2 and electricity-based H2 with reduced greenhouse gas emissions).²⁰ This categorisation reflects the EC’s ‘stepwise’ approach at the heart of the document.

Hence, the EC acknowledged that

“renewable hydrogen is the most compatible option with the EU’s climate neutrality and zero pollution goal in the long term and the most coherent with an integrated energy system. In the short and medium term, however, other forms of low-carbon hydrogen are needed, primarily to rapidly reduce emissions from existing hydrogen production and support the parallel and future uptake of renewable hydrogen.”²¹

In any event, and for a nascent market to take off, clear definitions for the types of gases that are to be regulated must be applied consistently throughout the Gas Package. In addition, given Europe’s H2 import dependency, a comprehensive terminology for different types of gases for inclusion in an EU-wide certification system will be necessary.²²

The Necessity for Clearer and More Comprehensive Definitions and Concepts

The preamble of the GD²³ makes a distinction between ‘low-carbon H2’ and ‘renewable H2’ produced mainly from wind and solar energy, but the latter concept is not defined in the GD – which only states that ‘renewable H2’ produced using biomass energy is captured under the term ‘biogas’.²⁴

‘Low-carbon H2’ is defined in the GD as H2 derived from ‘non-renewable’ sources producing at least 70 per cent less greenhouse gas emissions than fossil natural gas across its full lifecycle.²⁵ To ensure compliance with this threshold, the GD includes certification rules.²⁶

Although ‘low-carbon gases’, including ‘low-carbon H2’, are not all ‘renewable’, they are equated with ‘renewable gas’ in several provisions of the Gas Package. As ‘renewable fuels’ they could not be included in the proposal for the revision of the Renewable Energy Directive.²⁷ Their inclusion in the Gas Package is aimed to fill in that gap.

The definitions of ‘low-carbon H2’ and ‘renewable H2’are contained in two interrelated EU Delegated Acts (DA), as foreseen under Articles 27(3) and 28(5) of the Renewable Energy Directive.

The ‘Additionality DA’²⁸ defines under which conditions H2 and H2-based fuels produced from electricity can be qualified as renewable (or renewable fuels of non-biological origin – RFNBOs).

In the same DA, ‘low-carbon H2’ refers to H2 derived from non-renewable resources meeting a greenhouse gas emission reduction threshold of 70 per cent.²⁹ The Renewable Energy Directive requires RFNBOs to reduce emissions by at least 70 per cent compared to fossil fuels such as gasoline and diesel. This threshold is also captured under the terms ‘low-carbon gases’ and ‘low-carbon fuels’.³⁰

The calculation of the 70 per cent threshold is further clarified in the Methodology DA.³¹ This DA lists what emissions need to be captured under the lifecycle GHG emissions and what rules need to be considered for determining the emissions associated with each input.

To meet the 70 per cent threshold, operators need to provide information supporting its achievement to the national regulators through a voluntary certification process.³²

The methodology for calculating the 70 per cent threshold remains controversial and, as part of the public consultation process on the Gas Package, multiple stakeholders requested more clarity on the relationship among guarantees of origin (GO), certification and carbon intensity for renewable and low-carbon gases.³³

The rules on ‘blue’ H2 have not yet been finalised in the EU, although some progress is being made. The trilogue agreement on the new Package refers at Article 8(5)A to a further Commission DA on the methodology for assessing greenhouse gas emissions savings from low-carbon fuels. The proposed DA would include minimum carbon capture rates and upstream methane emissions performance standards. However, there are persistent doubts on whether carbon capture technology can consistently deliver capture rates of more than 70 per cent, as foreseen in the definition of low-carbon gas in the Gas Package. Although the first two DAs have met criticism,³⁴ they do bring further regulatory certainty. The provisional agreement on the Gas Package reached at the end of 2023 also recognises the EU’s focus to increase biomethane production.³⁵

Having established these distinctions between clean or pure H2 and low-carbon gas and fuels which may contain some H2, but which can still be co-mingled with natural gas, it is now possible to consider the different regulatory frameworks for dedicated H2 and natural gas networks.

2.2.2 The Gas Package in Detail

The Gas Package went through the EU ordinary legislative procedure. Multiple trilogue discussions³⁶ between the EC, the European Parliament (EP) and the Council of the European Union (Council) have taken place, and in the last trilogue³⁷ a provisional agreement was reached.³⁸ The Gas Package was formally adopted on 21 May 2024,³⁹ it was published in the EU Official Journal on 15 July 2024 and entered into force 20 days later.

Regulatory Objectives and Principles

The stated aim of the Gas Package is to prepare for the shift away from conventional fossil or methane gas to renewable and low-carbon gases, in particular biomethane and H2.⁴⁰ More specifically, in the EC’s views,⁴¹ this means the decarbonisation of gas consumption, the creation of cost-effective, cross-border H2 infrastructure and a competitive H2 market. This would also require the removal of barriers to decarbonisation, as well as the establishment of cost-effective conditions for the transition period – that is, to 2049.⁴² For instance, the GD foresees that long-term contracts for unabated fossil natural gas should not be extended beyond 2049 to avoid locking in fossil fuels.⁴³

The Gas Package provides several mechanisms to achieve these broad regulatory objectives.

First, ‘the main objective of this Directive is to enable and facilitate [the] transition by ensuring the ramp up of a hydrogen market and an efficient market for natural gas’.⁴⁴ As a result, the Gas Package includes separate provisions and chapters for (i) dedicated H2 systems (H2 networks, terminals and storage), which contain a ‘hydrogen of a high grade purity’,⁴⁵ and (ii) natural gas systems, which refer to gas composed mainly of methane and other gases that can be technically and safely injected into the natural gas system (such as biomethane, H2).⁴⁶

The creation of a new market design for (pure) H2 is based on the mirroring of some of the regulatory principles applicable to natural gas infrastructures. The various mechanisms provided for achieving this overall goal are linked specifically to the operation of dedicated H2 infrastructure networks, the repurposing of existing gas infrastructure for H2 blends and its transportation, and the designation of H2 network, storage and terminal operators. The Gas Package includes exceptions from some of its regulatory requirements in the shape of ‘regulatory holidays’ for H2.

Second, a new European Network of Network Operators for Hydrogen (ENNOH) would be created to promote a dedicated H2 infrastructure, cross-border coordination and interconnector network construction, and elaborate on specific technical rules. ENNOH’s tasks are therefore identical to those conferred on the European Network of Transmission System Operators (ENTSO)-E (electricity) and ENTSO-G (gas). ENNOH will be a separate entity from ENTSO-E and ENTSO-G.⁴⁷

Fourth, the scope of the Security of Gas Supply Regulation⁴⁸ is extended to H2 and to renewable and low-carbon gases.

Regulatory Holidays

The Gas Package contains several transitional provisions in the shape of ‘regulatory holidays’. During the initial roll-out period, dedicated H2 networks can enjoy temporary derogations from the default regulatory regime. This includes regulatory holidays from the obligation of granting TPA to the network, ownership unbundling and regulated tariffs. Historically, ad hoc derogations from these provisions provided in the earlier packages have been used to incentivise merchant investment in the natural gas and electricity sectors.⁴⁹ These derogations are usually granted for a period of up to twenty-five years by relevant national energy regulatory authorities, as endorsed by the EC, through an ‘Exemption Decision’.⁵⁰

Ad hoc exemptions are, however, not considered to be sufficient for creating a major impetus for the ramping up of an H2 market. For example, the exemption mechanism⁵¹ cannot be used for H2 networks within Member States, but only for pipelines which cross borders (interconnectors), for storage facilities and for import terminals. This exemption regime has been very successful in delivering new investments in the gas sector in the last twenty years. Nevertheless, a more structural approach to exemptions for H2 seems to be called for.

First, compared to electricity and gas, the H2 value chain will continue to be far more fragmented, with far more actors and with very different business models. Second, that market may be geographically dispersed. H2 could be piped, either blended with natural gas or through dedicated H2 pipelines, or it could be shipped, either in a condensed or liquefied state or via another molecule such as ammonia, methanol or liquid organic hydrogen carrier (LOHC). Third, with current H2 technologies, transport often doubles the price of H2 for the end user.

In the coming years, H2 transport from a terminal, an industrial facility or a cluster is likely to be made up of several different approaches, models and options, including transport by truck or rail. There is likely to be a mix of local H2 networks in industrial clusters and privately owned ‘direct lines’ serving to connect a single industrial user, H2 terminal or H2 storage facility to the nearest H2 transport network. A ‘national H2 grid’ linking key clusters might eventually make sense to benefit from economies of scale. However, it cannot be assumed that either supply of H2 or demand for it will evolve such as to justify the roll-out of national H2 networks in the coming years. Hence, and for all these reasons, the traditional approach to monopoly gas grid regulation cannot be transposed to the emerging H2 transport market. These essential differences between natural gas and H2 infrastructure are especially relevant in considering how to balance regulation versus investment incentives.

It is evident that over-regulation can therefore undermine investment in the H2 value chain during a period when the EU needs billions of euros in investment. But equally, ‘under-regulation’, or at least inadequate transparency on how the future regulatory regime will be applicable to a given investment, can have the same effect.

But ‘under-regulation’, the lack of effective TPA when an ‘essential facility’ exists, can also stifle investment in new H2 facilities. H2 suppliers or users will not be able to invest in new production or in decarbonisation of existing production unless they know that they will be able to access transport for H2. If an essential facility exists in this context – such as access to a central H2 grid – transparency with respect to if, when and how it will have access will be essential.

An additional advantage of the ‘regulatory holiday’ approach is that regulatory certainty can be provided. Investments in H2 would be undertaken on the assumption that regulated third-party access and unbundling, for instance, would be applied post-2032, again providing certainty.⁵²

To prevent an ‘over-’ or ‘under-regulation’ framework for H2, a solution could have been a ‘dynamic regulation’ as a basis, as proposed by the European energy regulators body, Council of European Energy Regulators (CEER), together with European Union Agency for the Cooperation of Energy Regulators (ACER) in 2021.⁵³ This included more intensive levels of regulation depending on the state of market development. The governance of this dynamic regulatory approach was inspired by the concept used in the existing EU regulation of the telecommunications sector, which gives regulators the power to intervene in a flexible and timely manner as a reaction to market dynamics. Regulators routinely assess if an operator is found to be dominant – that is, has significant market power (either individually or jointly) – in which case a specific regulatory obligation, proportionate to remedy the identified problem, must be imposed ex ante.⁵⁴

Furthermore, CEER/ACER argued that this would enable regulation to be implemented in an appropriate manner to the evolution of the H2 sector. The approach in the Gas Package is less nuanced. Article 6 of the Regulation mandates a specific deadline for the expiry of the regulatory holiday period, as from January 2033, without first allowing national regulators to assess the development of the H2 market to justify the imposition of full/default regulation.

The rationale for this approach was in part to provide legal certainty and to tackle ‘the expected disadvantages of the proposed approach of ex post regulation, in particular the lack of legal certainty for the required investments in hydrogen facilities and infrastructures with long life cycles and depreciation periods’.⁵⁵ But importantly the EC identified the ‘risk of regulatory fragmentation across different Member States [having] a detrimental effect on network interconnectivity and the integration of national hydrogen markets and, thereby, on cross-border trade and market development’.⁵⁶

The design of regulatory holidays for H2 investments must nonetheless be viewed alongside the introduction of rules to pursue the additional, parallel objectives of facilitating integration of renewable and low-carbon gas into the existing (methane) gas network. H2 can also be blended with natural gas up to a certain percentage at the interconnection points between EU Member States in the natural gas system.⁵⁷ As the transmission of all these gases are subject to full regulation, some form of competition between the existing and new gas networks may emerge. ACER and CEER also recalled that H2 and electricity transport companies are potential competitors, as both means could be used to transport energy from one place to another. This requires careful calibration of certain rules – for example to prevent cross-subsidisation by the users of existing system to the users of the new system. This also implies that potentially competing entities should not have decisive influence over certain investment decisions.⁵⁸

The next sections will assess several of the key building blocks of the Gas Package: unbundling, tariff setting and TPA. We will also consider the controversy surrounding the ‘regulated asset base’ or RAB, a controversy which has arisen in the context of the regulation of a market in which existing and new infrastructural assets will coexist.

2.3 How Much to Unbundle?

The ‘unbundling’ concept has been one of the main regulatory tools used by the EU institutions in the liberalisation of its gas and electricity markets, leading to the break-up of former vertically integrated monopolies.⁵⁹ The evolution of unbundling took several decades in the natural gas and electricity sectors and the adoption of three consecutive EU legislative packages.⁶⁰ The EC’s energy sector enquiry of 2007, together with the settlement of several competition key cases,⁶¹ had shown that competition concerns related to incumbents’ refusals to grant access to their networks to third-party suppliers persisted.⁶²

Each successive legislative package introduced different types of functional, management, legal and accounting unbundling of transmission and distribution assets in a vertically or horizontally integrated undertaking. In a ‘vertically integrated undertaking’, there is a combination of at least one of the functions of transmission, distribution, H2 transport, H2 terminal operation, LNG or natural gas or H2 storage activity, with at least one of the functions of production or supply of natural gas or of H2,⁶³ in one undertaking/group of undertakings. Therefore, ‘vertical unbundling’ is the separation of production and supply activities (areas of the market open to competition), on the one hand, from monopolistic network functions such as transmission and distribution, on the other. Under the current rules for transmission assets, Member States may opt for one of three models: independent system operator (ISO⁶⁴), independent transmission system operator (ITO⁶⁵) and ownership unbundling (OU) models.⁶⁶ Ownership unbundling is the default rule and the strictest form of unbundling for gas and electricity as network owners must relinquish any form of control over their production and supply assets and sell their shareholder rights to third parties.⁶⁷ In addition to the rules on ‘vertical unbundling’, the GD maintains the ‘horizontally integrated undertaking’ concept.⁶⁸ In a ‘horizontally integrated undertaking’, at least one of the activities of production, transmission, distribution, supply or storage of natural gas is combined with a non-natural gas activity.⁶⁹

This section focuses on the vertical and horizontal unbundling of dedicated H2 systems and the approach taken in the GD in order to avoid potential conflicts of interest and to promote competition along the value chain.⁷⁰ Yet it must be acknowledged that strict OU can prevent risk-sharing of the type that was common in the early days of the pipeline and LNG industries, when producers and buyers of gas and LNG took equity stakes in common infrastructure to share risk associated with the development of the market.⁷¹

2.3.1 Vertical Unbundling

Natural Gas Systems

For natural gas systems (pipelines, LNG terminals, storage facilities), the unbundling rules and models provided in the Gas Package remain essentially the same as those contained in the Third Package.

Dedicated Hydrogen Systems

The vertical unbundling rules as applicable to natural gas systems are to be expanded to dedicated H2 systems in the Gas Package.

Chapter IX of the GD in its Article 62 indicates that OU is to be the default rule for dedicated H2 systems and needs to be complied with by two years following the entry into force of the GD. There are two exceptions from this default rule in the GD.

The first is the ISO model, which may be applied by Member States if H2 networks belonged to vertically integrated undertaking (VIU). In earlier versions of the draft GD, the availability of this model was conditioned on its implementation at ‘the entry into force [of the GD]’⁷² or if applied to H2 networks ‘completed before 1 January 2031’.⁷³ These conditions have been removed.⁷⁴ This means that the ISO model may be applied for an H2 asset belonging to a VIU after the entry into force of the GD.

The second is the ITO model, which, if applied to H2 assets by Member States, was initially proposed as an option that would have expired by the end of 2030.⁷⁵ This cut-off date was removed in the provisional agreement on the GD at the end of 2023 and in the last adopted version of the GD.

Three main observations are noteworthy here.

First, the cut-off dates that were envisaged to be applied to the unbundling models applicable to H2 dedicated networks were considered unworkable. As the European Network of Transmission System Operators for Gas (ENTSOG) has flagged,⁷⁶ the unbundling options cannot be effectively utilised by H2 operators if subject to various restrictions. This approach could have prevented or delayed investment in H2 infrastructure (especially in retrofitted infrastructure).⁷⁷

Second, the possibility given to certified gas network operators to own and operate a H2 network is a significant improvement. An already ITO certified (natural gas or electricity) transmission system operator (TSO) can be certified under the same model and therefore operate as a dedicated H2 operator, and presumably this would be applicable to gas infrastructure assets ready for retrofitting as dedicated H2 networks.⁷⁸

Third, although the combination of natural gas system-related activities together with H2 supply/production activities in the same VIU has already been allowed, this has been subject to certain conditions. An OU unbundled natural gas TSO has been allowed to have passive investments, minority shareholding, purely financial rights (for example, rights to receive dividends) only, and no voting or appointment rights for the selection of members to company boards or other bodies legally representing a company active in H2 production/supply.⁷⁹

This outcome is now confirmed in Article 68 of the GD, with an additional clarification: if an undertaking engages in H2 production/supply, the OU-certified natural gas TSO shall comply with the same ITO requirements as for a certified H2 transmission network operator.

This clarification brings more flexibility. An OU-certified natural gas TSO can now apply an ITO regime to a dedicated H2 system and be part of the same VIU, with links to production or supply of H2 activities, but not with links to natural gas or electricity production or supply activities and therefore cannot circumvent the OU certification of the natural gas asset.

2.3.2 Horizontal Unbundling

Under horizontal unbundling, combining the activities of natural gas systems with the operation of dedicated H2 systems is allowed if two conditions are met: first, a dedicated H2 transmission network operator should be established in a separate legal entity from the activities of natural gas/electricity transmission/distribution and, second, to ensure transparency, there should be separate accounts applicable to different infrastructures.⁸⁰

The main regulatory concern related to horizontal unbundling is the eventual cross-subsidisation between different activities (such as natural gas activities subsidising H2 activities), to the advantage of the integrated undertaking.

However, criticism has been voiced that the requirement of legal unbundling went too far.⁸¹ Accounting unbundling through separation of RABs (monitored and approved by the national regulators) should be sufficient to monitor cross-subsidisation.⁸² It was argued that legal unbundling might create too much red tape.⁸³ In the final version of GD the regulatory approach is softened: legal unbundling could be realised through establishing a subsidiary/separate legal entity in the group of entities controlled by the natural gas TSO without further functional unbundling and separation of management/staff.⁸⁴ In addition, a limited derogation from legal unbundling could be granted if there is positive cost–benefit analysis and impact assessment, and separation of accounts and regulatory asset base.⁸⁵

The GD also confirms that the exchange of commercial information between the H2 network/terminal/storage operators and natural gas transmission or distribution operators, as part of the same VIU, is allowed given the synergies and benefits that may result.⁸⁶

2.3.3 Cross-Subsidisation from Existing to New Infrastructure Assets

Repurposing existing natural gas networks may prove to be the most cost-efficient option for the development of a dedicated H2 network on the assumption, amongst others, that the supply and demand of H2 will at least partially follow the current supply and demand for natural gas.⁸⁷

Given that the use of natural gas networks is expected to decrease only gradually so that the need for gas-only networks will remain, and that not all the existing gas infrastructure can be converted to H2, construction of new H2 infrastructure will be necessary. The required financing of H2 infrastructure investment cannot come from revenues from user tariffs alone as these will be insufficient during the initial years of the transition to H2 or would put overly high costs on the initial users. If natural gas tariff revenue were to be used to finance H2 infrastructure this could lead to households financing the decarbonisation of industry.⁸⁸ This has given rise to extensive debate on the merits of cross-subsidisation and the need to separate out relevant assets.

Unsurprisingly, the gas TSOs favour a common RAB since operating both gas and H2 networks in a joint asset base would support repurposing, and ‘network operators would have the option to finance and de-risk networks across users of both natural gas and H2 infrastructure’.⁸⁹ This common RAB ‘would enable operators to spread these costs to the larger group of network users and enable them to offer more attractive tariffs to early H2 network users, neutralising investment risks’.⁹⁰

The Gas Package facilitates limited cross-subsidies between the natural gas and H2 sectors. In principle, H2 networks must have separate regulated asset bases from gas and electricity networks. Cross-subsidies between regulated asset bases are allowed so long as they are via dedicated charges at offtake points in the same Member State as the beneficiary of the cross-subsidy. Cross-subsidies can only be for a limited period, cannot exceed one-third of the depreciation period for the subsidised infrastructure and must be approved by regulators.⁹¹ Transfers between RABs may be allowed if the national regulators established that, subject to certain conditions, the ‘financing of networks through network access tariffs paid by its network users [was] not viable’.⁹²

2.4 Tariff Setting

The current EU gas market is organised based on entry/exit zones, where the gas TSOs guarantee transmission and support its costs. There are general principles set at EU level regarding transparency of tariff setting, revenue collection, cost drivers and cost reflectivity⁹³ (through the EU Network Code on tariff structures – TAR NC).⁹⁴

2.4.1 Tariffs and Discounts for Natural Gas Systems

The Gas Package facilitates the integration of renewable and low-carbon gases into the existing natural gas network through (i) the reduction of injection costs and (ii) the access granted to the natural gas market.

Renewable and low-carbon gases will benefit from a 100 per cent and 75 per cent discount respectively at the entry points from renewable and low-carbon production facilities⁹⁵ and a 100 per cent discount at injection and withdrawal points into and out of gas storage facilities.⁹⁶ Until the end of 2025, the national regulators may in principle apply a discount of up to 100 per cent to capacity-based transmission and distribution tariffs at entry points from, and exit points to, underground gas storage facilities and LNG terminals.⁹⁷

2.4.2 Tariffs for Dedicated H2 Systems

The applicability of cross-border tariffs to dedicated H2 systems is probably one of the most debated points related to the Gas Package. From the beginning of 2033 (or even earlier if rTPA is applied) certain principles related to tariffs for access to natural gas systems apply to dedicated H2 systems.⁹⁸

2.5 Third-Party Access Regime

The introduction of TPA has been a fundamental regulatory instrument for liberalising the energy sector, and one which has evolved throughout the EU gas legislative packages. The new TPA-related provisions in the GD should also be read together with the justification of when refusals to provide access can take place.⁹⁹

2.5.1 Dedicated Hydrogen Systems

The Gas Package gives the flexibility to Member States to rely on regulatory holidays to apply negotiated third-party access (nTPA) to dedicated H2 networks up until the end of 2032.¹⁰⁰ After this date, the default rule shall be the regulated, non-discriminatory and objective rTPA.¹⁰¹

Access to H2 storage is based on similar TPA rules as for H2 networks, with more flexibility until the end of 2032.¹⁰² This regulatory approach contrasts with the regime applicable to gas storage, whereby either rTPA or nTPA can be applied and without a cut-off date.¹⁰³ For H2 terminals, however, the default rule is negotiated TPA.¹⁰⁴

At the same time, long-term H2 capacity contracts are permissible¹⁰⁵ and can have (i) maximum twenty years for infrastructures completed by 1 January 2028 and (ii) fifteen years for infrastructure completed after that date.¹⁰⁶

Hence the main differences are rTPA for H2 storage as opposed to nTPA for gas storage, and nTPA instead of rTPA for H2 import terminals. These differences are justified on the basis that H2 storage is likely to be more limited than gas storage for technical reasons but is also more crucial for the H2 system because of the intermittency of renewable electricity generation. H2 import terminals have more potential for competition because of the different means of transporting H2 (for example, ammonia, methanol, LOHCs, hydrogen).

2.6 Conclusion

An important starting point for making decarbonisation a reality is to have an appropriate regulatory governance system put in place that incentivises the uptake of renewable and low-carbon gases, but at the same time does not distort the already existing and well-functioning gas market, which is still seen as an essential ‘bridge’ to the energy transition. Replacing natural gas will be costly and will take time and effort, while the production of renewable H2 will require vast amounts of renewable electricity.

The Gas Package provides a framework to enable renewable and low-carbon gases to enter the market and contribute to decarbonisation, as well as security of supply. This package, which was introduced before the war in Ukraine, had received quite broad support in terms of its overall goals and ambitions, albeit that it has attracted criticism for its overly ambitious approach to an EU-wide H2 market that is yet to develop.

There is growing scepticism as to whether the Gas Package can deliver the desired decarbonisation objectives. Timing does not seem to be on its side. The legislative process was derailed by the war in Ukraine, which triggered an energy crisis in Europe and the EU co-legislators focused attention on emergency legislation to address security of supply issues, as well as rising gas prices.

It is questionable whether the ambitious timelines and targets provided are realistic given the Gas Package, even if now formally adopted, must still be transposed into national legislation of the Member States, which will take another 1–2 years. Based on the experience with the implementation of the 2009 Third Package, none of the Member States achieved the deadline of eighteen months for transposition at national level. It took another three years for nearly all Member States to have the package implemented. Seen in this light, the intended deadlines for the expiry of the various regulatory holidays in the Gas Package do not appear generous. It is highly debated whether the exercise of mirroring the regulation of a mature natural gas regulation to dedicated H2 networks and renewable and low-carbon gases is the right way forward for a nascent market.

Given the early stage of the H2 market and the growing uncertainties around its future development, why would stricter regulation be applied to the initial stages of the new H2 sector when compared with the regulation of the Third Gas Package? Unlike natural gas at the time of liberalisation, there is no well-established, mature H2 market and infrastructure.

Towards the finalisation of the Gas Package legislative process, some of its H2-related provisions have become more flexible in comparison with the EC’s initial proposal. Nevertheless, given the targets and cut-off dates in the light of the time required for national transposition, that flexibility may prove insufficient.

3 Hydrogen Regulation in the United States Will Government Financial Incentives Outweigh Regulatory Hurdles?

Donna M. Attanasio and Meghan Briggs

3.1 Introduction

The United States’ support for hydrogen shifted in 2021 and 2022. Rather than focusing primarily on research, development, and demonstration projects, as in past decades, laws passed in 2021 and 2022 authorized $8 billion in grants plus lucrative tax credits to stimulate private investment in clean hydrogen. Another $1.5 billion will continue to support research. Under this approach, costs of production and adaptation for new uses will be reduced by government support while market development will be strongly influenced by private investors’ decisions and interests.

In 2021, Congress also directed the US Department of Energy (DOE), the lead federal agency for hydrogen market development, to establish a national strategy and roadmap for hydrogen.¹ This was the first hydrogen strategy directive required by Congress since 2005.² The US National Clean Hydrogen Strategy and Roadmap (Roadmap), identifying the US government’s goals for the production and use of hydrogen and the strategies for achieving those goals, was released in May 2023.³

Implementation of the 2021 and 2022 legislation is proceeding, but as of the date of this writing, there are still substantial regulatory gaps, including with respect to four discussed in this chapter: the definition of ‘clean hydrogen’ as applied to the tax credits; permitting reforms; regulation of the construction and operation of interstate hydrogen pipelines; and safety laws and harmonization of standards. This uncertainty as to if, how, and when various regulatory gaps will be resolved, and the impact that uncertainty will have on costs and sector growth, is unknown.

This chapter focuses primarily on the 2021 and 2022 federal legislation due to its potentially profound impact on the development of the hydrogen market. Section 3.2 will introduce the recent laws and the complex regulatory challenge of defining ‘clean hydrogen’. Section 3.3 sets forth in more detail the policies and key laws through which the federal government intends to stimulate the hydrogen market. The private sector response to date to the hydrogen hub program is described in Section 3.4. Section 3.5 will discuss the regulation of hydrogen, with a focus on three areas of regulatory uncertainty that could impede market development.

Additionally, states can act independently from the US federal government to provide incentives or regulate in areas not pre-empted by the federal government. California, for example, has been a leader in promoting hydrogen use.⁴ However, state actions are beyond the scope of this chapter.

3.2 What Is ‘Clean Hydrogen’?

As referenced above, legislation passed in 2021 and 2022 provided significant financial support for clean hydrogen market development in the United States. The 2021 Infrastructure Investment and Jobs Act (IIJA, also called the Bipartisan Infrastructure Law) directed $9.5 billion to the DOE for hydrogen programs. The 2022 Inflation Reduction Act (IRA) included generous tax credits that could reduce the cost of investing in hydrogen production facilities or producing hydrogen by providing investors with a reduction in the income taxes they owe.⁵ The tax credits are administered through the Internal Revenue Service, which is part of the US Treasury Department.

These financial incentives are intended for ‘clean hydrogen’. But defining ‘clean hydrogen’ is not straightforward. The popular color-based hydrogen taxonomy has become increasingly complex as different technologies and fuel sources have sought their own hue, creating a rainbow of green, blue, grey, pink, brown, and turquoise hydrogen. The US government has eschewed the rainbow (or coloring-book) approach in favor of defining ‘clean’ by the kilograms of carbon dioxide equivalent emitted during production of a kilogram of hydrogen. This approach has the benefit of being both fuel and technology neutral, thus more easily accommodating new production methodologies. However, the statutes have different definitions for clean hydrogen.

The IIJA specifies that the terms ‘clean hydrogen’ and ‘hydrogen’ (as used in the IIJA) mean ‘hydrogen produced in compliance with the greenhouse gas emissions standard’ established by the DOE.⁶ Through the IIJA, the US Congress instructed the DOE to set ‘an initial standard for the carbon intensity of clean hydrogen production’⁷ that would:

• support clean hydrogen production from ‘fossil fuels with carbon capture, utilization, and sequestration; hydrogen-carrier fuels (including ethanol and methanol); renewable energy resources, including biomass; nuclear energy; and any other methods the Secretary [of DOE] determines to be appropriate’,⁸

• define ‘clean hydrogen’ as ‘hydrogen produced with a carbon intensity equal to or less than 2 kilograms of carbon dioxide equivalent produced at the site of production per kilogram of hydrogen produced’, and

• ‘take into consideration technological and economic feasibility’.⁹

Within five years after the initial standard for the carbon intensity of hydrogen production is set, the DOE must determine whether to lower the standard.¹⁰

The IRA defines ‘qualified clean hydrogen’ for use under the tax code as hydrogen produced in such a way as to result in lifecycle greenhouse gas emissions of no more than 4 kilograms of CO₂e (equivalent) per kilogram of hydrogen.¹¹ The IRA requires lifecycle emissions to be determined using the GREET (Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation) model developed by Argonne Laboratories.¹²

After receiving public comments, in June 2023 the DOE set the initial production standard for ‘clean hydrogen’ (often referred to simply as ‘hydrogen’) for the purposes of the programs it administers in a manner intended to harmonize with the IRA definition. The DOE’s Clean Hydrogen Production Standard (CHPS):

establishes a target for well-to-gate lifecycle greenhouse gas emissions of ≤4.0 kgCO2e/kgH2. The establishment of a well-to-gate target aligns with statutory requirements to consider not only emissions at the site of production but also technological and economic feasibility and to support clean hydrogen production from diverse energy sources … This target is also consistent with the IRA’s definition of ‘qualified clean hydrogen’. This target is likely achievable by facilities that achieve ≤2 kgCO2e/kgH2 at the site of production, which potentially have additional emissions from upstream and/or downstream processes.¹³

The well-to-gate boundaries, as illustrated in the DOE’s guidance document, includes the emissions at each step, from feedstock extraction through production, including fugitive emissions, plus those related to sequestration (if applicable), but excludes component manufacturing and end use.¹⁴ The DOE’s endorsement of the GREET model is consistent with the IRA definition and is ‘aligned with international best practices’ as established through the International Partnership for Hydrogen and Fuel Cells in the Economy’s Hydrogen Production Analysis Task Force.¹⁵

At the time of this writing, the Treasury Department, within which the Internal Revenue Service resides, has not yet issued its final regulations implementing a definition of ‘qualified clean hydrogen’ for use in the tax provisions it administers, although the IRA required it to do so by August 2023. Like the DOE, the Treasury has engaged in a notice-and-comment rulemaking procedure in which the public participates. A point of contention in the rulemaking is whether ‘qualified clean hydrogen’ that is produced from renewable resources must rely only on new renewable resources (referred to as ‘additionality’), renewable resources that generate power during the same hours (‘time matching’), and resources near the point of production. The underlying concern is that absent these constraints, the lucrative tax incentives will divert use of existing clean energy resources to hydrogen production, and thereby increase reliance on fossil fuels to meet other demands on the grid.¹⁶ Other details also need to be resolved by the regulations, such as the method for determining if a project started construction and became operational within the period to which the tax credits apply. Once all the regulations implementing the tax benefits in the IRA are decided, investors will be better able to assess the financial viability of their planned projects.

3.3 US Policy and Law Promoting Production and Use of Hydrogen

3.3.1 The Big Picture

The Biden administration’s hydrogen policy is part of its broader effort to stimulate the US economy through investment and job growth across a wide range of clean energy sectors. Concurrently, the Biden administration is implementing its Justice40 initiative, which promotes energy justice and economic equity.¹⁷ These cross-cutting themes of job growth, justice, and equity are reflected in the DOE’s Roadmap and its criteria for awarding grants and other government funding. They are also evident in the structure of the IRA laws, which provide enhanced tax incentives for investing in lower-income communities or communities that have lost jobs due to recent reductions in fossil fuel production and for paying ‘fair wages’ (typically union wages) and providing job training.

3.3.2 The DOE Roadmap: Hydrogen Goals and Strategies

The US National Clean Hydrogen Strategy and Roadmap, published by the DOE in 2023, states how the federal government foresees sector growth over the coming decades, obstacles that need attention, and goals and strategies to guide further government actions. The Roadmap projects that ‘clean hydrogen’ production and use will contribute 10 percent of the emissions reductions required by the US Long-Term Climate Strategy by 2050.¹⁸ Specific goals include: an increase in annual clean hydrogen production and use to 10 million metric tons (MMT) by 2030, 20 MMT by 2040, and 50 MMT by 2050; and creation of 100,000 new jobs by 2030 and 450,000 new jobs cumulatively by 2050.¹⁹ For context, as of 2022, the United States produced only about 10 MMT of hydrogen per year.²⁰ Ninety-five percent of that was produced with steam-methane reforming processes using natural gas.²¹

The Roadmap also sees the United States playing an ‘important role’ in creation of a global hydrogen market having ‘the potential for $2.5 trillion in annual revenue and 30 million jobs … along with 20 percent global emissions reductions by 2050’.²² Advances in the cost-effective production and deployment of hydrogen in the United States would provide leadership for other countries.

To facilitate the growth needed to meet the goals set forth in the Roadmap, the DOE offers three strategies:

1. 1. ‘Target Strategic, High-Impact Uses of Clean Hydrogen.’ These uses are primarily industries that require high-temperature processes that cannot be electrified, and thus are otherwise difficult to decarbonize, such as steelmaking and chemical manufacturing.²³

2. 2. ‘Reduce the Cost of Clean Hydrogen.’ Cost reductions are sought throughout the supply chain.

3. 3. ‘Focus on Regional Networks.’ Using IIJA funding (described below), the DOE’s strategy is to develop multiple clusters or ‘hubs’ of hydrogen producers and users in diverse regions of the country that over time would scale up and then spread into a nationwide network.²⁴ By clustering, participants would be better positioned to share infrastructure, and the region would offer multiple opportunities for job seekers in the hydrogen field at multiple companies.²⁵ Hubs would also help develop understandings at a regional level of potential synergies (or lack) between hydrogen and electrification, and electric sector evolution that takes into account regional resources and needs.²⁶

As envisioned in the Roadmap, industrial uses of hydrogen could expand to include steel and cement manufacturing, industrial heat, and production of bio or synthetic fuels.²⁷ In addition to hydrogen’s current use for forklifts, buses, and light-duty vehicles, the Roadmap points to potential uses for hydrogen in the transportation market for medium- and heavy-duty vehicles, rail, maritime, aviation, and offroad equipment used in mining, construction, and agriculture. Hydrogen could also be used for long-term storage of renewable energy²⁸ and to integrate renewable intermittent resources into the grid.²⁹ Blending hydrogen with other fuels in greater amounts than today opens other potential uses in power generation and buildings.³⁰ The Roadmap asserts that the potential for a significant use of electrolysis in hydrogen production would also simulate growth in clean energy.³¹ Cost-competition from dirtier fuels (in the absence of mandates to use clean fuels) remains a concern³² as does additionality.³³

The primary obstacles to market growth identified in the Roadmap, based on data collected in September 2021, are the cost to end-users and infrastructure development. The tax incentives in the IRA were not known at the time this data was collected, and therefore are not factored in. Specific issues with expansion identified by the DOE are the compatibility of hydrogen with materials and existing fuel transportation methods, such as pipelines and tube trailers, and delays in permitting³⁴ (which is of general concern in the energy sector). National standards for blending limits, and harmonization of codes and standards, are also important to establishing a national market.³⁵ Multiple other concerns were identified by the DOE that could affect market growth, including the need for technology advancement; competing technologies; safety concerns; and a lack of suitable end uses.³⁶ The Roadmap calls for a ‘whole of government approach’ to address these concerns and asserts the federal agencies will coordinate an efficient response³⁷ without specifying how that will be accomplished.

Importantly, demand for hydrogen must increase along with production. The Roadmap points to several demand-side measures needed to achieve the DOE’s goals for hydrogen, including standard terms for offtake agreements, price transparency,³⁸ and certainty of supply.³⁹

3.3.3 Research, Development, and Commercialization Programs

The US government has supported research and development for hydrogen since the 1970s.⁴⁰ Building on this history, the 2021 IIJA authorized several new programs encouraging development of hydrogen as an alternative energy source. While authorizations vary by program, generally the DOE is authorized to provide grants, contracts, loans, or cooperative agreements to eligible entities to carry out the work under its major initiatives,⁴¹ subject to the DOE’s standard cost-sharing requirements.⁴²

The centerpiece of the IIJA’s hydrogen support is a four-year, $8 billion grant program for Regional Clean Hydrogen Hubs.⁴³ These hubs would link hydrogen producers and consumers through connective infrastructure (for example, pipelines, truck routes) to demonstrate the potential for a national clean hydrogen network and accelerate its development. Each funded hub is expected to produce clean hydrogen as defined in the IIJA. The IIJA requires funding of at least four hubs and specifies that production facilities at the four initial hubs must include one fueled by nuclear energy, one from renewable fuels, and one from fossil fuels. End-use demonstrations must also be diversified across industry use, electric power generation, residential and commercial heating, and transportation, and the hubs are to be geographically diverse.⁴⁴ In September 2022, the DOE put out its first call for hydrogen hub proposals. The request and response are discussed in Section 3.4.

Another important DOE program that was revitalized with IIJA funding is the Clean Hydrogen Research and Development Program (formerly the Hydrogen Program Plan).⁴⁵ The IIJA provided $500 million for research, development, and demonstration of ‘clean hydrogen production, processing, delivery, storage, and use equipment manufacturing technologies and techniques’, including recycling of fuel cells⁴⁶ and a four-year $1 billion program for the commercialization and deployment of electrolyser for production of clean hydrogen.⁴⁷ The research enabled by the new IIJA funding complements the DOE’s work under another program, administered by the DOE in tandem with the Clean Hydrogen Research and Development Program but adopted as part of the 2021 American Rescue Plan, called Clean Hydrogen Energy Shot. Its objective is to reduce the cost of clean hydrogen production by 80 percent, to achieve the goal of $1 per 1 kg of hydrogen in one decade.⁴⁸ The IIJA also included funding for training programs for the hydrogen workforce.⁴⁹ Another IIJA allocation, directed to the Department of Transportation for alternative fueling infrastructure, could support hydrogen development, but is not earmarked exclusively for hydrogen.⁵⁰

3.3.4 Tax Incentives to Attract Private Investment

The Inflation Reduction Act of 2022 supports clean hydrogen by creating a new tax credit for hydrogen production and expanding existing tax credits for investment in clean hydrogen production facilities.⁵¹ Tax incentives to invest in complementary technologies, such as carbon capture and storage, are also included in the IRA. There is no limit to how many qualifying investments can be supported by the tax credits, although there are limits on stacking credits on a single project.

The new production tax credit (PTC) applies to ‘qualified clean hydrogen produced by the taxpayer … at a qualified clean hydrogen production facility’.⁵² The PTC is available for a period of ten years after the date the facility is placed in service. Construction of the facility must begin before January 1, 2033. The hydrogen must be produced in the United States (or its possessions) in the ordinary course of business, for sale or use, to qualify for tax credits. The maximum available credit is $0.60/kg (subject to adjustment for inflation),⁵³ but the applicable percentage a taxpayer may claim is scaled, as shown in Table 3.1.

Table 3.1 Applicable clean hydrogen production tax credit by emissions level

Kilograms of CO2e per kilogram of hydrogen		Applicable percentage of credit
Equal to or not greater than 4 kg	Not less than 2.5 kg	20
Less than 2.5 kg	Not less than 1.5 kg	25
Less than 1.5 kg	Not less than 0.45 kg	33.4
Less than 0.45 kg		100

Thus, lower emissions will result in a higher credit. The credit can be increased by a factor of five if construction of the facility complies with certain labor and wage requirements and Justice40-related criteria.⁵⁴

This PTC may not be combined with credits under 26 USC §45Q, which incentivizes carbon capture and storage.⁵⁵ However, investors may combine the PTC with a tax credit for clean energy or zero-emission nuclear power production.⁵⁶ Certain other limitations apply.

As an alternative to the PTC, investors in a hydrogen production facility can elect to take an Investment Tax Credit (ITC) under 26 USC §48(a)(15) of the tax code. This credit allows the taxpayer to reduce its taxes based on its initial investment in the production facility rather than on the annual production of hydrogen. Like the PTC, the ITC incentive uses a tiered approach, tying the tax incentive received to the level of lifecycle greenhouse gas emissions (Table 3.2).

Table 3.2 Applicable clean hydrogen investment tax credit by emissions level

Kilograms of CO2e per kilogram of hydrogen		Applicable percentage of eligible investment
Equal to or not greater than 4 kg	Not less than 2.5 kg	1.2
Less than 2.5 kg	Not less than 1.5 kg	1.5
Less than 1.5 kg	Not less than 0.45 kg	2.0
Less than 0.45 kg		6.0

The statutory language further indicates that energy properties are eligible for certain multipliers and additions, which, if made available, would increase the value of the investment tax credit substantially, potentially to a level of 50 percent of the investment.⁵⁷ Those multipliers and additions are granted if construction of the facility complies with certain labor and wage requirements;⁵⁸ meets certain domestic content requirements;⁵⁹ or is located in an ‘energy community’.⁶⁰ An ‘energy community’ is, generally speaking, a community adversely affected by the transition away from fossil fuels.⁶¹ These provisions promote the Biden administration’s Justice40 and US economic growth policies. The project may not claim the ITC and the PTC for the same facility or combine it with the credit for carbon capture and storage.

Subject to various limitations, the entity entitled to receive the PTC or ITC may transfer the credit for value, tax-free,⁶² or treat it as a direct payment of taxes.⁶³ This flexibility to monetize the tax credits is valued by entities that are tax-exempt, such as governmental bodies or non-profit organizations, or that otherwise are not yet profitable enough to owe taxes, and increases the number of potential investors.

3.4 Industry, Hydrogen Hubs, and Growth

As noted above, presently, production and demand for hydrogen in the United States is small compared to DOE goals for the sector’s growth. Hydrogen produced in the United States is used mostly in petroleum refining and ammonia production.⁶⁴ However, fuel cells, forklifts, and fleet vehicles are growing sectors (which the DOE has supported with funding under prior laws).⁶⁵ There is also a small but burgeoning use in the energy sector. As of October 2021, hydrogen fuel cells accounted for about 260 megawatts (MW) of electric generating capacity, and at least two companies were already planning to blend hydrogen with natural gas to fuel natural-gas-fired electric generators.⁶⁶ Industry, and state and local governments in California have been promoting the use of hydrogen vehicles since 1999.⁶⁷

The DOE’s $8 billion hydrogen hub program and the IRA tax incentives are critical to reaching the commercial scale and momentum needed to transform this small sector into one that fulfills the US goals for clean hydrogen.⁶⁸ In September 2022, the DOE issued a funding opportunity announcement offering $7 billion of the $8 billion authorized to fund between six and ten hubs.⁶⁹ The solicitation required a 50 percent non-federal cost share, meaning that the participants would have to place a significant amount of their own money at risk. The period for execution, expected to be 8–12 years, would depend on the complexity of the hubs proposed. Funding would be dispersed in four tranches, based on the work accomplished.⁷⁰ The DOE applied the following evaluation criteria: technical merit; financial and market viability; the workplan, including how quickly the hub would build out production and expand end-use markets; the management team and partners; and its community benefits plan, including workforce development, jobs, and support for Justice40 initiatives.⁷¹

In response to the funding opportunity announcement, the DOE received eighty expressions of interest. It encouraged thirty-three of the eighty to submit applications. In October 2023, the DOE selected seven projects for further negotiation. If all are successfully developed, the anticipated total investment would be nearly $50 billion; and they would produce 3 MMT of hydrogen annually and reduce carbon dioxide emissions by 25 MMT by displacing use of other fuels.⁷² The hubs alone will not fulfill the goals set forth in the DOE Roadmap, but they are expected to produce about 30 percent of the 2030 production goal and demonstrate the viability of hydrogen.⁷³

The participants in each hub vary, but typically consist of a consortium of private companies and state and local governments. The primary features of their proposals, as set forth in the DOE-issued descriptions, are summarized in Table 3.3.⁷⁴

Table 3.3 Summary of hub proposals selected for further negotiation, 2023

Hub	Fuel/technology	Consumers	Additional research goals
ARCH2(Appalachian region)	Natural gas with carbon capture and storage. Emphasis on hydrogen pipelines.	Fueling stations and other end-uses.	Reduce distribution and storage costs.
ARCHES(California)	Renewable energy and biomass.	Decarbonize transportation and ports and prepare ports for potential export of hydrogen. Generation.	Reduce carbon emissions in hard-to-decarbonize sections of the transportation system. Support tribal power needs.
HyVeloicty H2Hub (Texas)	Natural gas with carbon capture and storage and electrolysis from renewables.	Fuel cell electric trucks, industrial processes, ammonia, refineries and petrochemicals, and marine fuel.	Lower cost of distribution and storage to reach more users. Salt cavern storage.
Heartland Hub (Minnesota, North and South Dakotas)	The region’s ‘abundant energy resources’.	Co-firing for generation, clean fertilizer.	Decrease regional cost of hydrogen; use open-access storage and pipeline infrastructure.
Mid-Atlantic – MACH2 (Pennsylvania, Delaware, New Jersey)	Electrolysis using renewable and nuclear energy.	Heavy transport, manufacturing and industrial, CHP.	Repurpose oil infrastructure. Develop distribution and fueling infrastructure. Innovative electrolyser technologies.
Midwest (Illinois, Indiana, Michigan)	Mixed resources.	Strategic hydrogen uses including steel and glass production, power generation, refining, heavy-duty transportation, and sustainable aviation fuel.
PNWH2 (Washington, Oregon, Montana)	Electrolysis using renewables.	Heavy duty transportation, industry generation, fertilizer, seaports.	Coordinated with ARCHES to create a west coast hydrogen transportation corridor.

While the response of industry to the hydrogen hub solicitation is encouraging, there are still many points of contention. The industry is not yet mature enough to immediately begin producing hydrogen that accords with the DOE’s CHPS (the definition discussed in Section 3.2 above) and apply it in hard-to-decarbonize industries. As discussed above, advocates of additionality and hourly matching want users of renewable energy to build new renewable resources for hydrogen production, and match hydrogen production to periods of electricity generation from these resources. An industry group argues that such measures will ‘stop the clean hydrogen industry’ before it gets started. It points to the delays in permitting and interconnecting new renewable generation as an impediment to accessing enough clean energy fast enough to scale hydrogen at the rate needed to meet climate goals.⁷⁵ Other industry advocates have suggested that policies and law should encourage growth in sectors where hydrogen already has a foothold, such as forklifts, and phase in the CHPS and decarbonization of hard-to-decarbonize sectors over time.⁷⁶

In sum, the legislation discussed in Section 3.3 has elicited a positive response from industry and provides the United States with the potential for tremendous sector growth.⁷⁷ The varied goals of the hub applicants generally align with the Roadmap goals. However, industry members are concerned that some of the legal standards will be set too high to meet at the outset and will derail growth before it begins. As will be described in the following section, there are other regulatory issues as well.

3.5 Regulatory Concerns

3.5.1 Regulatory Overview

The DOE, acting through the Sandia National Laboratory, has evaluated the applications of hydrogen that are subject to, or potentially subject to, federal regulation under existing law.⁷⁸ The DOE found that hydrogen is covered by many existing regulations, and as many as fifteen different agencies may have jurisdiction at various points in the supply chain.

Emerging uses for hydrogen, including in the consumer sector, will test whether the regulatory framework is adequately comprehensive and flexible, and harmonized sufficiently to facilitate sector growth. A complete analysis is beyond the scope of this chapter. However, the DOE’s Roadmap references particular concerns with permitting, safety, and harmonization. Permitting and regulation for new pipelines, in particular, have been subject to vigorous public debate. Because permitting, pipeline regulation, and safety all raise critical and cross-cutting concerns and have been subject to recent study and discussion, they are addressed below.

3.5.2 Permitting Reform

Siting of infrastructure is frequently mentioned as critical to the advancement of the hydrogen economy. Infrastructure includes production facilities, pipelines, fueling stations, and transfer terminals. Siting decisions are also critical to the safety, health, and welfare of the public and to the health of the environment. While acceleration of the process for securing permits is important for meeting the aggressive timelines for build-out of the hydrogen sector and other infrastructure needed to reduce greenhouse gas emissions (such as transmission lines to move renewable energy to load centers), faster timelines can also have unintended and adverse impacts on the environment; cultural or historical sites; people, including environmental justice communities; navigation of aircraft or ships; or recreational areas.

With an important exception for certain pipelines, discussed in Section 3.5.3, decisions about where infrastructure may be placed is largely a matter for state and local jurisdictions. However, even where state or local entities are the primary decision-maker, the federal government has a role, since siting requires compliance with federal environmental statutes, where applicable. For example, where federal funds are used, as in the hydrogen hubs, the National Environmental Policy Act could be implicated.⁷⁹

Accelerating the timeline for permitting new infrastructure through federal action has been pressed in Congress for several years, with members both advocating for, and adverse to, streamlining the process. As of May 2023, there were at least six proposed bills in various stages of development in Congress.⁸⁰ One issue is whether only infrastructure for clean energy should be accelerated or all infrastructure. The permitting discussion, except as discussed in Section 3.5.3, is not exclusive to the hydrogen sector and it is unclear whether or if reforms will be forthcoming. However, it is one of the factors often cited as a possible obstacle to achieving the full potential of the hydrogen market.

3.5.3 Jurisdiction over Interstate Pipelines

Transportation of hydrogen is a critical link in the supply chain that affects how and where the hydrogen production and use markets will evolve, the cost, and the accessibility of hydrogen for projected uses. Pipelines are the most economic form of land-based transport for large quantities of hydrogen.⁸¹ Therefore the process for the development and regulation of a pipeline network is of great concern, and presently unresolved. The potential applicability of as many as three existing regulatory structures have been suggested as discussed in the following subsection, ‘Which Regulatory Structure Applies?’⁸² The burdens and benefits of regulation would vary depending on which scheme applies, are explained in ‘The Importance of the Debate’. The potential pathways forward are discussed in ‘Pathway to Resolution?’

Which Regulatory Structure Applies?

The United States has a comprehensive regulatory scheme for the transportation of commodities in interstate commerce by pipeline. The Interstate Commerce Act, as amended by the Hepburn Act in 1906 (ICA) vested authority to regulate all interstate pipelines, except those carrying natural gas or water, in a single federal agency, the Interstate Commerce Commission (ICC).⁸³ In 1938, the Natural Gas Act (NGA) placed regulation of interstate natural gas pipelines under the jurisdiction of the Federal Power Commission. That authority transferred in 1977 when the Federal Power Commission was replaced by the Federal Energy Regulatory Commission (FERC).⁸⁴

In 1977, authority over oil transportation under the ICA was also transferred to FERC, taking advantage of FERC’s deep expertise in energy markets.⁸⁵ The remainder of the pipeline regulatory authority that had been contained in the ICA was recodified, and in 1995 placed under the Surface Transportation Board (STB); and the ICC was abolished.⁸⁶ Because the federal regulatory regime is comprehensive, hydrogen must be covered, even though not explicitly singled out.⁸⁷ Where and how is less clear.

The question of which regulatory structure applies to hydrogen stems from its versatility. Natural gas has a specific yet ambiguous meaning under the NGA: ‘“Natural gas” means either natural gas unmixed, or any mixture of natural and artificial gas.’⁸⁸ Because hydrogen in a pure form does not often occur naturally, pure hydrogen is (arguably) not ‘natural gas’.⁸⁹ Further Congress understood ‘artificial’ gas as used in the NGA to have a very specific meaning that did not include pure hydrogen.⁹⁰ If hydrogen is not a natural gas, and if hydrogen is not blended with natural gas, then transportation of it by pipeline is (arguably) outside of FERC’s NGA jurisdiction. It would instead remain subject to regulation by the STB. This approach is consistent with the fact that hydrogen has uses other than as an energy carrier, for example as a feedstock.

But the issue is not that clear-cut. Reading ‘natural gas’ as excluding gases not primarily composed of methane may be unnecessarily narrow. For example, a 1960 act explicitly excluding helium from FERC’s NGA jurisdiction would have been unnecessary if the definition of natural gas had been read so narrowly.⁹¹ Further, one readily available use for hydrogen is blending it with natural gas. In some cases, natural gas pipelines and other equipment are believed to be physically able to tolerate blends of up to 20 percent hydrogen.⁹² A blend of hydrogen and natural gas would fit the NGA’s definition of natural gas and be regulated by FERC.

A third possibility is that FERC should regulate hydrogen under the same ICA authority under which FERC regulates oil. The ICA authority granted to FERC in 1977 extended to ‘pipeline transportation of crude and refined petroleum and petroleum byproducts, derivatives or petrochemicals’.⁹³ Proponents of this view argue that FERC’s authority over oil has previously been read broadly to encompass other energy products;⁹⁴ and hydrogen is often derived from petroleum products and fits well with FERC’s expertise because hydrogen is presently valued for its energy content.⁹⁵ From a policy perspective the ICA requires oil pipelines to be common carriers, ready to serve all comers, which would facilitate the emergence of this new market.⁹⁶ However, treating hydrogen as ‘oil’ under the ICA would lead to the problem of ‘bifurcated regulation’ because pure hydrogen would be regulated under the ICA, while hydrogen mixed with even a small amount of natural gas would be regulated under the NGA.⁹⁷

Another option is to wholly exempt interstate hydrogen pipelines from the regulatory schemes described above, just as water is exempt. That, however, would require congressional action because the regulatory sweep encompassing all interstate pipelines other than those carrying water suggests it must be regulated.

The Importance of the Debate

The importance of this question comes from the distinctions between the NGA and ICA regarding their scope, degree of flexibility, and control over entry and exit, and the expertise of the regulator. Both statutes grant the regulator authority over rates, terms, and conditions of service, but the NGA also provides FERC with authority over determinations of need, siting, and abandonment of interstate pipelines, storage facilities, and import/export facilities for natural gas, including liquified natural gas.⁹⁸ Under the ICA, siting and permitting of pipelines is left to the states.

Unlike oil pipelines, an interstate natural gas pipeline must have a certificate of convenience and necessity from FERC to proceed to construction.⁹⁹ Although this may seem burdensome, the certification of need takes into consideration the economic demand for pipeline capacity and therefore limits competition to support the economics of those pipelines that are built. That protection could be valuable to a nascent hydrogen pipeline industry. Further, consolidating jurisdiction under FERC would enable it to coordinate the approval for abandonment of a natural gas pipeline with conversion of the pipeline to use for hydrogen transportation (if technically feasible).¹⁰⁰

Further, once the certificate of need is issued, the pipeline developer is able to exercise a federal right of eminent domain enabling it to take private property (for fair compensation) that is needed for the pipeline right of way.¹⁰¹ State authorities are unable to deny access to a certificated pipeline that will cross the state, even if the state sees little benefit to its residents or has other parochial concerns. A rapid build-out of an interstate hydrogen pipeline system, if needed, might be facilitated by a similar federal siting authority.

However, the NGA permitting process can also be lengthy and at least one commentator takes the position that he has seen few issues with oil pipeline siting, despite the lack of federal authority.¹⁰² Further, the importance of federal siting authority depends very much on whether new hydrogen pipeline construction will be primarily interstate or for export (that is, potentially within the federal domain under the ICA or NGA) or intrastate (within state control).

Uncertainty itself is of concern. Whichever regime applies, the process for permitting and building a pipeline is lengthy and thus a false start under the wrong regime would be costly in terms of time as well as money.

Pathway to Resolution?

Given the ambiguity, the matter will likely require congressional action. In addition to the three options for federal regulation set out above, a fourth option could be a federal exemption from regulation (like water). A variation might explicitly bring hydrogen within the NGA’s federal siting regime, coupled with light-handed rate regulation.¹⁰³ If hydrogen is exempted from federal regulation (like water), then under the US federalism system, individual states would have discretion over regulation. Should Congress not act, the question could be posed to the agencies and then the courts to decide the ambiguity described.

The timing for resolution of this important issue is unknown.

3.5.4 Safety

The DOE Roadmap repeatedly recognizes additional attention to public health and safety is an important ‘enabler’ for achieving the US goals for hydrogen.¹⁰⁴ It also endorsed a recommendation from the IEA Future of Hydrogen Report, stating that ‘[a]ddressing safety codes and standards is necessary for a harmonized global supply chain’.¹⁰⁵ But the pathway for gaining this clarity is unclear. The Roadmap does not include a plan for doing so.

The current US laws include safety standards applicable to hydrogen, but they are dispersed across different agencies depending on the point in the supply chain and the activity involved. For example, six different administrations within the US Department of Transportation regulate some aspect of hydrogen transport.¹⁰⁶ Protecting the health and safety of workers in the private sector and some public sector workers is entrusted to the US Occupational Safety and Health Administration (OSHA).¹⁰⁷ The OSHA identifies nine standards that ‘may’ apply to hydrogen (and cautions that the list is not exhaustive).¹⁰⁸ Proper labeling can also affect safety, including in the workplace. Labeling of alternative fuels, which includes hydrogen, is the responsibility of the Federal Trade Commission.¹⁰⁹ Thus, regulation is already pervasive, but in some instances unclear. Further, it is important that the requirements are appropriate to new uses of hydrogen and facilitate its transport and use across multiple places and jurisdictions. Inconsistencies can create issues of noncompliance or limit market penetration.

Standard setting, often by industry, can play an important role in resolving some of these issues. For example, ‘The National Fire Protection Association (NFPA) is a global self-funded nonprofit organization, … devoted to eliminating death, injury, property and economic loss due to fire, electrical and related hazards’.¹¹⁰ The NFPA is not a government agency but its primary work is developing and disseminating codes and standards. It has developed several standards applicable to hydrogen. While these standards do not inherently have the force of law, they are sometimes incorporated into local building codes which are binding. Creating standards through industry groups can facilitate uniformity across jurisdictions, where no single law would be applicable.

The Energy Policy Act of 2005 required the DOE to support the development of ‘safety codes and standards relating to fuel cell vehicles, hydrogen energy systems, and stationary, portable, and micro fuel cells’.¹¹¹ That effort was funded from 2005 to 2020 and during that period the DOE developed the ‘H2 Tools’ website to help others.¹¹² However, the resources on the H2 Tool website are now dated and the project is unfunded.

Consistent with the Roadmap, attention to safety and the harmonization of standards is important to market development. Industry can help, but the government needs to act too.

3.6 Conclusion

The market for hydrogen in the United States is poised for growth. The infusion of federal funding and favorable tax provisions are intended to bring government and industry together as partners in its development. The strong interest in hydrogen hubs indicates the potential for success. However, industry is concerned that emerging regulations will set standards it cannot yet meet, thus stymying growth before it begins; and there are areas of regulatory uncertainty that must be resolved to facilitate rapid growth. The question of permitting reform and pipeline regulatory-authority are particularly vexing and may require congressional action to resolve. Both government and industry have important roles in updating and harmonizing safety codes and other standards. As long as these regulatory hurdles remain unaddressed, the potential for rapid growth is uncertain.

4 Hydrogen Regulation in Latin America From Promise to Production

Howard James Foy

^*

4.1 Introduction

Hydrogen is anticipated to play a central role in the global energy transition towards decarbonized economies.¹ With demand for clean hydrogen² projected to surge in the coming decades, particularly in Europe and north-east Asia,³ Latin America finds itself well positioned to capitalize on this market opportunity.⁴ With its vast energy resources, both proven and untapped, the region has the potential to become a production epicentre in the impending hydrogen economy.⁵ This ability to produce large quantities of low-cost clean hydrogen and its derivatives can not only catalyse new export sectors for many Latin American countries; it can also contribute to their domestic decarbonization efforts.⁶ Indeed, hydrogen’s versatility as an energy carrier, storage medium and industrial feedstock makes it a vital component in addressing the challenges of hard-to-abate sectors like heavy industry and heavy-duty transport.⁷

This chapter examines the emerging policy and regulatory frameworks for hydrogen in Latin America by focusing on three regional leaders, Chile, Colombia and Brazil.⁸ These countries, endowed with solar, wind, hydro and/or fossil fuel assets, all aim to become major clean hydrogen producers. To achieve this vision, they have each outlined ambitious hydrogen strategies, setting the stage for the industry’s growth.⁹ In order to keep pace with the increasing interest from policymakers and the private sector, their legal regimes are undergoing a period of significant transformation to scale the hydrogen value chain beyond scattered pilots. While Chile, Colombia and Brazil have made positive strides, as this chapter explores, critical regulatory challenges must be addressed before this promise of a thriving regional hydrogen market can fully materialize.

As a note to the reader, in view of the rapidly evolving nature of the hydrogen legal landscape, the information presented in this chapter is current as of 15 June 2024, unless otherwise noted.

4.2 From Promise to Policy: Parallel Ambitions, Divergent Approaches

Seeking to harness clean hydrogen’s power, Chile, Colombia and Brazil have each articulated important policy documents reflective of their ambitions. These documents, while providing insights into their strategic priorities and approaches to hydrogen development, also serve as the foundation for shaping their regulatory environments. In this regard, to properly contextualize the following regulatory discussions, this section will briefly explore some salient aspects of these policy initiatives.

4.2.1 Kickstarting the Hydrogen Endeavour

Chile’s foray into hydrogen has been a comparatively recent affair, largely motivated by studies that highlighted the country’s immense renewable potential.¹⁰ Against this backdrop, swift decision-making coupled with international collaborations, notably with Germany,¹¹ led Chile to publish its National Green Hydrogen Strategy in 2020, the first of its kind in Latin America.¹² More recently, Chile released its Green Hydrogen Action Plan 2023–2030,¹³ intended to serve as the actionable roadmap for the industry’s development for the remainder of the decade.¹⁴

Colombia, for its part, saw potential in hydrogen as early as 2007, recognizing its capacity to transform the transportation sector.¹⁵ Nonetheless, this interest only matured into a concrete plan with the publication of its Hydrogen Roadmap in 2021, under which the country similarly aims to exploit its natural resources for clean hydrogen production.¹⁶ Unlike Chile’s two-pronged approach, Colombia’s Roadmap includes the several lines of work on which the different national and regional bodies will work over the current decade.¹⁷

As for Brazil, its hydrogen endeavour can be traced back to at least the 1990s, with early initiatives focused on exploring hydrogen’s energy applications.¹⁸ However, it was only in 2022 that these initiatives fully crystallized with the establishment of its National Hydrogen Programme.¹⁹ As part of this programme, Brazil published its 2023–2025 Three-Year Work Plan, the country’s short-term blueprint for its hydrogen ambitions.²⁰ Like its neighbours, it also plans on capitalizing on its extensive natural assets to become a major hydrogen producer.²¹

This overview reveals a unified vision amongst Chile, Colombia and Brazil to tap their natural resources for clean hydrogen production. Yet, as we will analyse next, their ultimate goals vary in fundamental ways, casting light on the strategic priorities of each country.

4.2.2 Setting the Goals and Targets

In the case of Chile, its Strategy outlines particularly ambitious goals. By 2025, the country aims to be the lead recipient of green hydrogen investments in Latin America with $5 billion, have 5 gigawatts (GW) of electrolysis capacity installed or under development, and produce 200 kilotons (kt) of green hydrogen a year.²² By the end of the decade, Chile aspires to become the global leader in exporting green hydrogen and its derivatives ($2.5 billion), produce green hydrogen with the lowest levelized cost worldwide ($1.5/kg) and establish itself as the global leader in green hydrogen production through electrolysis (25 GW).²³ By mid-century, Chile aims to lower its levelized cost of hydrogen (LCOH) to $0.8/kg.²⁴

Colombia’s Roadmap also lays out ambitious goals, though comparatively smaller in scale. By 2030, Colombia aims to develop 1–3 GW of electrolysis backed by 1.5–4 GW of renewable energies, reach green hydrogen costs of $1.7/kg, and produce at least 50 kt of blue hydrogen via CO₂ capture.²⁵ Colombia’s Roadmap also aims to deploy a fleet of 1,500 to 2,000 light-duty vehicles, 1,000 to 1,500 heavy-duty vehicles, as well as 50 to 100 hydrogen re-fuelling stations.²⁶ To achieve these goals, the country plans to mobilize $2.5–5.5 billion in investments over the decade, mainly from the private sector.²⁷

Brazil’s Work Plan contrasts with less defined goals and targets, perhaps owing to its nature as a triennial plan and not a long-term strategy. The main objectives set forth therein are to disseminate low-carbon hydrogen pilots nationally by 2025, become the most competitive global producer of low-carbon hydrogen by 2030 and to establish low-carbon hydrogen hubs by 2035.²⁸ However, the Plan stops short of specifying detailed figures for these objectives.²⁹

When juxtaposed, the hydrogen strategies of these countries exhibit diverse (and even rival) goals and ambitions. Chile sets the bar high, aspiring to global leadership in green hydrogen production and export, as evidenced by its goal to achieve the world’s lowest LCOH – a benchmark Brazil also aims to surpass. Colombia, in comparison, while also intent on becoming an important player in the hydrogen market, sets more modest but concrete goals. This includes, like Chile, specific targets for investment, electrolyser capacity and LCOH. Unique to Colombia’s strategy, however, is the inclusion of detailed goals for the transport sector and blue hydrogen production. These distinctions not only illustrate the individual ambitions of Chile, Colombia and Brazil, but also hint at the unique policy choices underpinning their hydrogen initiatives, to which we will turn to next.

4.2.3 Defining the Strategic Approach

Chile’s hydrogen policy distinctively focuses on ‘green’ hydrogen, bypassing mentions of ‘blue’ hydrogen or other variants.³⁰ This is not surprising if one considers that Chile imports nearly 98 per cent of the fossil fuels it uses, while it boasts an estimated renewable energy generation potential that exceeds 2,300 GW – seventy times its currently installed electrical capacity.³¹

In contrast to Chile’s green-centric model, Colombia adopts a more inclusive approach which includes both ‘blue’ and ‘green’ hydrogen. Explicitly mentioning its abundant reserves of oil, natural gas and coal,³² its Roadmap emphasizes the potential for harnessing these resources for hydrogen production when coupled with carbon capture, utilization and storage (CCUS) technologies.³³ In this regard, while it recognizes green hydrogen’s significance in the longer term, the strategy assigns blue hydrogen a key transitional role.³⁴

Brazil’s Work Plan, for its part, deviates from a previously heralded and even more eclectic ‘rainbow’ hydrogen approach, which included ‘grey’ hydrogen,³⁵ steering its strategy towards ‘low-carbon’ hydrogen production.³⁶ Interestingly, in opting for this terminology, Brazil forwent the traditional ‘colour-book’ classification, adopted by Chile and Colombia in their initiatives, echoing the preference of the International Energy Agency (IEA) for an emissions intensity-centric framework instead.³⁷ Under this classification, Brazil’s Plan includes hydrogen derived from a wide variety of processes with low lifecycle emissions, including the equivalents of both ‘green’ and ‘blue’ hydrogen.³⁸

While these documents reflect a unified movement towards integrating clean hydrogen into their national energy mix, Chile, Colombia and Brazil chart distinct strategic pathways reflective of their unique strengths and goals. The success of these ambitious policies hinges on the creation of enabling governance frameworks that keep pace with the momentum set. The following section examines the regulatory regimes of these countries, analysing how each is tackling the legal complexities of turning their hydrogen aspirations into tangible realities.

4.3 From Policy to Regulation: Status Quo, Challenges and the Path Ahead

Across the national strategies of Chile, Colombia and Brazil, a common theme threads the discourse: the need for a regulatory infrastructure that can enable the widespread deployment and commercialization of hydrogen technologies.³⁹ Hydrogen’s multidimensional nature, straddling the lines between a fuel source, a storage medium and an industrial feedstock, necessitates a legal framework that can adapt to its unique characteristics and uses. Indeed, adequate regulation has been recognized as the primary enabler for the industry, providing the foresight and stability needed to invest and scale up hydrogen initiatives.⁴⁰ To this extent, the particularities of regulation are not merely peripheral considerations; they are central to the entire developmental narrative. As this section will examine, classifications, definitions, regulatory competences, safety protocols and certification procedures are all key facets that require precise legal crafting to adequately support the sector’s growth.

4.3.1 Chile

In Chile, significant efforts are underway to align its hydrogen regulatory framework with policy aspirations. Central to this task is the reassessment of hydrogen’s legal classification.⁴¹ Under Chilean law, molecular hydrogen has historically been (and continues to be) classified as a ‘hazardous substance’.⁴² As such, a suite of standards apply, including safety protocols for its storage and transportation, and occupational health rules.⁴³ Nevertheless, as hydrogen expands its applications beyond traditional industrial uses, these existing standards prove inadequate for its broader energy-related roles.⁴⁴ This discrepancy between legacy regulations and new applications emphasized the need for a more appropriate framework.

The call for a regulatory realignment to this effect found its legislative response through the enactment of Law 21,305 in 2021.⁴⁵ This legislation marked a significant turning point in hydrogen’s governance by officially classifying it as a fuel, a measure aligned with Chile’s Strategy.⁴⁶ In doing so, it conferred oversight of hydrogen to the Ministry of Energy, enabling it to pursue a regulatory agenda in line with hydrogen’s new roles.⁴⁷ As part of this agenda, the development of safety standards across hydrogen’s value chain has been a priority.⁴⁸

This legislative progression has led to a regulatory conundrum: under Chilean law, hydrogen is recognized both as a hazardous substance and as a fuel.⁴⁹ While dual classifications are not inherently problematic, the practical implications in this case extend beyond theoretical discord.⁵⁰ As exemplified by the Ministry of Health’s Supreme Decree 43/2016, they manifest in the potential for regulatory overlap and conflict.⁵¹ In particular, this Decree sets forth safety requirements for hydrogen storage, mandating tank conditions, safety distances and maximum storage capacities.⁵² However, it explicitly carves out ‘liquid and gaseous fuels’ from its scope of application.⁵³ This exclusion casts uncertainty over the operational parameters within which hydrogen must be managed: tanks storing hydrogen solely for industrial use might be subject to this Decree, whereas those for fuel purposes might not. This becomes more complex when hydrogen’s end use might span across both energy and non-energy domains. Considering that the risk profiles and mitigation strategies for hydrogen remain invariant throughout its lifecycle, regardless of its final application, this bifurcated governance paradigm risks disrupting regulatory consistency and sowing confusion.⁵⁴

Despite this lack of clear and specific safety regulations for hydrogen installations, interest in pilot projects did not stall. To this extent, Chile introduced a support guide outlining the authorization procedure for hydrogen projects,⁵⁵ a requirement all energy facilities must fulfil.⁵⁶ This guide plays a crucial role in bridging the regulatory gap, allowing pilot projects to import safety standards dictated by foreign standardization institutes such as the American National Standards Institute (ANSI), the International Organization for Standardization (ISO) and the National Fire Protection Association (NFPA).⁵⁷ Since then, there have been attempts to approve an official set of safety regulations for hydrogen installations, which include safety requirements across design, construction, operation, maintenance, decommissioning and other stages.⁵⁸ However, despite the decree containing these regulations having been signed by former President Piñera in 2022, they have yet to enter into force.⁵⁹

Another regulatory development in furtherance of Chile’s Strategy has been the enactment of Law 21,505, which allowed for the inclusion of green hydrogen technologies into the country’s electricity matrix.⁶⁰ This law formally recognized ‘generation-consumption systems’, a classification that includes green hydrogen production facilities.⁶¹ Amongst other provisions, it allows these systems to both draw energy for electrolysis and contribute surplus power back to the grid.⁶² This, in turn, allows green hydrogen to play a key role in optimizing the use of excess electricity from intermittent renewable sources, effectively managing power supply during peak demand periods.⁶³ Also noteworthy, the above classification explicitly extends to water desalination facilities,⁶⁴ of relevance as desalinated seawater is expected to be used in the hydrogen production process.⁶⁵ As Chile faces acute water scarcity challenges,⁶⁶ this inclusion reflects a potential move towards sustainable water usage in hydrogen production in line with public concerns.⁶⁷

While the above analysis demonstrates concrete progress, it simultaneously highlights the need for further legal refinement and comprehensiveness. For instance, in addition to the aspects previously described, Chile still has not formally defined what constitutes ‘green hydrogen’, nor has it established a system for certifying the sustainable pedigree of the hydrogen produced.⁶⁸ As the country positions itself to be a major exporter, addressing these issues is of paramount importance, particularly for hydrogen destined for the EU.⁶⁹

In response to these and other concerns, and as part of its Action Plan, Chile has recently published the latest version of its hydrogen regulatory agenda, shown in Table 4.1.⁷⁰

Table 4.1 Chile’s hydrogen regulatory agenda

Area of focus	Period	Regulatory action
General regulatory enablement	2024–2030	Approve the Hydrogen Installation Safety Regulations
		Initiate studies for the regulatory proposal of hydrogen quality and hydrogen refuelling stations
		Present the regulatory strategy for hydrogen derivatives
		Enact the Law on the Use of Seawater for Desalination
Certification system	2024–2025	Develop a strategic proposal for establishing a sustainability certification system for hydrogen
	2025–2030	Strengthen the National Electric Coordinator’s National Registry of Renewable Energies (RENOVA), which will serve as the main platform for hydrogen certification
Permitting system	2023–2025	Strengthen the dependencies that grant critical permits for the proper development of the hydrogen industry
	2023–2024	Update the Guide for the Submission of Hydrogen Projects to the Superintendency of Electricity and Fuels (SEC)
	2023–2026	Implement a comprehensive reform of sectoral permits
	2024–2026	Develop and establish the technical criteria for the environmental assessment of projects related to the value chain of green hydrogen and its derivatives
	2024–2030	Strengthen the Environmental Assessment Service (SEA) and the services involved in the environmental assessment process

Source: Author’s own work based on Chile’s Action Plan.

Simultaneously, Chilean lawmakers are actively pursuing legislative initiatives to address these gaps. Bill 14756-08 stands out amongst them, aimed at establishing a broad legal framework for promoting the production and use of green hydrogen in Chile.⁷¹ Following the Strategy’s green-centric approach, the bill only addresses ‘green hydrogen’, which it defines as hydrogen produced through renewable energy sources utilizing water electrolysis or other approved technologies.⁷² Also of importance, the bill incorporates provisions for establishing a hydrogen certification system, essential for verifying the renewable origins of green hydrogen.⁷³ As of the time of writing, Bill 14756-08 is, however, still in the early stages of consideration within its originating chamber.⁷⁴

As this analysis shows, Chile finds itself in a transitional phase as regulations play catch-up to policy ambitions, displaying the inherent complexities in this hydrogen transition. Nevertheless, the country’s regulatory environment is evolving steadily, as evidenced by the number of hydrogen regulations already enacted, those being developed and those planned for future development. Patient persistence in seeing these efforts through will determine whether Chile seizes the opportunities this new energy paradigm presents.

4.3.2 Colombia

Like its neighbour, Colombia is also deeply immersed in a regulatory overhaul. It too recently reclassified hydrogen, defining it as an energy vector suitable for energy storage, fuel or industrial applications.⁷⁵ This development, contained in the Ministry of Mines and Energy Decree 1476 of 2022, lays the groundwork for the creation of safety and technical standards better suited to its emerging roles.⁷⁶ Despite this reclassification, hydrogen continues to be regulated as a hazardous substance,⁷⁷ necessitating compliance with existing safety and technical regulations.⁷⁸ These, however, are considered insufficient and technologically outdated for hydrogen’s new roles,⁷⁹ with Decree 1476 calling for their review and update, in particular those governing hydrogen transport.⁸⁰ As of the cut-off date, no updates have been announced. Regarding other elements of the hydrogen value chain, specific safety and technical standards remain undefined.⁸¹

Shifting focus from classifications to definitions, Colombia’s legal delineation of ‘green hydrogen’ has undergone successive refinements that both expand opportunities and introduce complexity. Initially, Law 2099 of 2021 defined green hydrogen narrowly as produced exclusively from listed non-conventional renewable energy sources, such as wind, solar and biomass.⁸² In 2022, this definition was de facto broadened by Decree 1476, which allows green hydrogen projects to also utilize grid-sourced electricity for their production processes, provided the electricity is verified through bilateral contracts and renewable certificates.⁸³ Subsequently, Law 2294 of 2023 formally expanded the definition of Law 2099, introducing another layer to green hydrogen’s evolving concept. According to this expanded definition, the green label can also be achieved by balancing a facility’s self-generated renewable injections to the grid against any extracts for hydrogen production.⁸⁴ As long as injections meet or exceed production draws, the produced hydrogen retains its green designation.

Consequently, as it stands, three different definitions of green hydrogen coexist in Colombia’s legal framework. While purely self-generated renewable energy serves as an unambiguous pathway for green hydrogen production, the differing grid-reliant models that have emerged introduce legal uncertainty in determining the compliance and sustainability credentials of green hydrogen projects. Creating further overlap, Decree 1476 also defined ‘low-emission hydrogen’, tying its designation to a to-be-determined emissions threshold.⁸⁵ As of the cut-off date, rules for the verification and operationalization of the two grid-based alternatives remained pending, as did the emissions threshold for ‘low-emission hydrogen’.

In contrast to the multi-conceptualization of green hydrogen, the definition of ‘blue hydrogen’ under Colombian law is more straightforward. In particular, Law 2099 defines it as hydrogen produced from fossil fuels, incorporating a CCUS system within its production process.⁸⁶ This formal incorporation of both green and blue hydrogen into Colombia’s legal regime represents a foundational step towards fulfilling its hydrogen commitments as outlined in its Roadmap. More recently, building upon this initial taxonomy, Colombia broadened its hydrogen narrative by also legally defining ‘white hydrogen’,⁸⁷ a move in line with its intention to explore for natural hydrogen deposits within the country’s geology.⁸⁸

Despite these advancements, important gaps remain in Colombia’s regulatory framework, such as the absence of a hydrogen certification system and the lack of comprehensive technical and safety standards for the hydrogen value chain.⁸⁹ Addressing these and other challenges, however, is part of Colombia’s regulatory agenda, outlined in Table 4.2.⁹⁰

Table 4.2 Colombia’s hydrogen regulatory agenda

Phase	Goal	Regulatory action
Phase 1	Promote institutional articulation and assign responsibilities on hydrogen issues	Establish working groups to identify and allocate institutional competencies amongst different ministries
		Articulate the Hydrogen Roadmap with the implementation instruments of the national climate change policy
	Establish the concepts of green and blue hydrogen in line with the national legal framework	Consolidate the definitions and taxonomy of green and blue hydrogen considering associated CO2 emissions
	Design a system of guarantees of origin and certifications for hydrogen	Involve Colombia in international working groups
		Design a system of guarantees of origin through working groups with industry and other stakeholders
		Develop a monitoring tool for the system of guarantees of origin and certifications
	Develop and update technical and safety regulations for hydrogen	Review current national regulations through working groups and identify uses where new technical regulations need to be incorporated
		Adopt international standards in the technical regulation of hydrogen in Colombia
Phase 2	Adapt regulation for new applications such as ‘blending’	Revise and update the Single Transport Regulation to allow for ‘blending’
	Simplify and adapt administrative procedures	Review permits and procedures for the implementation of hydrogen projects including environmental aspects and land use
		Reduce the administrative red tape for low-emission hydrogen projects
	Adapt the regulation of the electricity system to better match hydrogen production	Analyse the participation of electrolysers in grid flexibility services
		Analyse electricity cost reduction in hydrogen production

Source: Author’s own work based on Colombia’s Roadmap.

In line with this agenda, Colombian legislators have drafted several legislative proposals, including Bill 275/2022C. Designed as a comprehensive umbrella legislation, the bill’s primary objective is to bridge existing regulatory voids while promoting the growth of, interestingly, ‘low-emission’ hydrogen.⁹¹ In line with this taxonomy, the bill defines it as hydrogen produced from hydrocarbons with CCUS technologies, as well as from renewable energy sources, amongst other methods.⁹² In all cases, however, it must meet the greenhouse gas (GHG) emission threshold set by the relevant ministries. This new emissions-based classification, however, does not replace the current ‘blue’ and ‘green’ definitions, but rather explicitly covers them, potentially creating further definitional overlap.⁹³ Also of importance, the bill directs the relevant government bodies to establish the emissions threshold for low-emissions hydrogen, and to formulate regulations spanning technical specifications, safety protocols, certification systems and integration into the country’s energy matrix, alongside other aspects.⁹⁴ Status-wise, Bill 275/2022C had been approved by the Chamber of Representatives in early 2024 and was awaiting treatment in the Senate.⁹⁵ However, the bill has since been shelved, requiring a complete restart of the legislative process.⁹⁶

As evidenced by the preceding analysis, Colombia’s hydrogen governance is undergoing a period of important evolution, in many respects reflecting the process also underway in Chile. Colombia’s path through this regulatory transformation thus far shows its commitment to seeing its policy ambitions through, as well as the challenges along the route towards maturation. While recent developments serve as crucial legal implementations of the country’s Roadmap, the regulatory environment remains underdeveloped, with key areas still awaiting further definition and operationalization. Like Chile, continued efforts in addressing these gaps will be essential in establishing a robust hydrogen ecosystem in Colombia.

4.3.3 Brazil

Brazil’s hydrogen regulatory framework, in a more nascent stage compared to Chile and Colombia, is marked by a dynamic parliamentary scene teeming with activity. As acknowledged by the Brazilian Energy Research Company (EPE), the country lacks adequate institutional and regulatory governance to support the deployment of hydrogen’s diverse applications and usage scenarios.⁹⁷ This situation presents challenges in addressing concerns such as hydrogen’s oversight, definitions and classifications, safety and technical standards, and certification processes.⁹⁸

In this regard, under Brazilian law, hydrogen retains its traditional classification as a hazardous good, which encompasses both flammable gases and liquids.⁹⁹ This subjects hydrogen’s handling to, inter alia, the Brazilian Norm NBR 14725:2023 and the resolutions issued by the National Land Transport Agency (ANTT).¹⁰⁰ Specifically, NBR 14725:2023 outlines hydrogen’s labelling requirements in line with the Globally Harmonized System of Classification and Labelling of Chemicals (GHS),¹⁰¹ while ANTT Resolution 5998/2022 sets forth requirements for the identification, packaging, marking and documentation for the transport of hydrogen.¹⁰² While these regulations provide a safety baseline consistent with its current uses, they fail to address the specialized needs of hydrogen’s new applications across its value chain, mirroring the challenges that Chile and Colombia also face.

In view of these shortcomings, Brazil has outlined a broad regulatory agenda within its Three-Year Plan.¹⁰³ This agenda, as shown in Table 4.3, spans a wide spectrum of measures, ranging from defining low-carbon hydrogen and assigning oversight to establishing adequate safety and technical norms for its novel applications.

Table 4.3 Brazil’s hydrogen regulatory agenda

Goal	Regulatory action
Improve the institutional, legal and infra-legal frameworks	Draft regulation establishing the definition of low-carbon hydrogen
	Propose text amending Law 9.478/1997 in order to provide for activities related to low-carbon hydrogen and confer relevant competences on the National Agency of Petroleum, Natural Gas and Biofuels of Brazil (ANP)
	Draft report mapping the regulations that establish existing competences and gaps
Develop the codes, norms, standards and certifications in line with the timetable and development of international rules Create carbon-intensity certification mechanisms for hydrogen and ethanol chains derivatives	Propose certification governance model
	Propose product coverage and scope
	Analyse and interact with international organizations for certification systems
	Propose a certification standard for the carbon-intensity bands of the hydrogen and derivatives produced in Brazil
Foster interrelationships between sectors, and bolster harmonization and cooperation between government agencies	List governance instruments for interrelations between sectors, harmonization and cooperation to be improved or drawn up
	Propose new governance instruments and/or revise existing governance instruments between government agencies
	Study the possibility of blending hydrogen into the existing natural gas network
Enact additional safety standards	List additional safety standards or revisions to standards
	Propose new additional safety standards or revisions to standards
Develop regulations, codes, norms and standards for new hydrogen uses and technologies	Draft National Electricity Agency (ANEEL) normative resolution(s) for the insertion of storage systems in the grid, including via hydrogen
	Develop ANP technical note on international specifications for hydrogen as a transport fuel
	List regulations, codes, norms, standards for new uses and technologies
	Propose regulation, codes, norms, standards for new uses and technologies

Source: Author’s own work based on Brazil’s Work Plan.

In line with this plan, several concrete actions are already underway, such as studies on low-carbon hydrogen certification schemes.¹⁰⁴ In parallel, as mentioned, Brazilian lawmakers are currently drafting and deliberating upon various hydrogen bills aimed at legally enabling its policy ambitions. Amongst these, three proposals have garnered particular attention.

Bill 2308/2023, originating from Brazil’s Chamber of Deputies, sets out to establish the legal framework for hydrogen in the country.¹⁰⁵ In line with Brazil’s Work Plan, it focuses primarily on ‘low-carbon hydrogen’.¹⁰⁶ Unlike the Plan, however, it defines it using a fixed emissions intensity threshold – four kilograms of carbon dioxide equivalent (CO₂e) per kilogram of hydrogen produced.¹⁰⁷ This numerical approach, while improving legal certainty in the short term, raises concerns about its adaptability to evolving market dynamics and technological advancements.¹⁰⁸ In fact, in line with the latest EU-delegated acts, the emissions threshold for hydrogen to be considered low-carbon is 3.38 kilograms of CO₂e per kilogram of hydrogen.¹⁰⁹ To this extent, Brazil’s potential adoption of a higher threshold could impact its alignment with international standards, particularly as the EU moves towards more stringent GHG emission benchmarks.¹¹⁰ The bill also refers to ‘renewable hydrogen’, a terminology not present in Brazil’s Plan, defining it as hydrogen produced from listed renewable sources.¹¹¹ Also deviating from the Plan, the bill’s latest amendment added the definition of ‘green hydrogen’, which covers hydrogen produced by electrolysis of water, from wind and solar energy sources.¹¹² Beyond definitions, the bill also includes risk management guidelines and seeks to establish a hydrogen certification system, amongst other aspects.¹¹³ Regarding competences, it grants the ANP the authority to oversee hydrogen production activities.¹¹⁴

Bill 5816/2023, which comes from Brazil’s Senate, likewise aims to lay certain regulatory foundations for hydrogen’s development in the country.¹¹⁵ To this extent, it also includes several important definitions, in particular those for ‘low-carbon hydrogen’ and, intriguingly, ‘green hydrogen’.¹¹⁶ In line with its counterpart from the Chamber of Deputies, it defines ‘low-carbon hydrogen’ using the same fixed carbon emission threshold, with the ensuing issues mentioned above.¹¹⁷ ‘Green hydrogen’, on the other hand, is defined as hydrogen produced exclusively from listed renewable energy sources, and serves as this bill’s equivalent to ‘renewable hydrogen’.¹¹⁸ By adopting this colour taxonomy, however, this bill deviates from the Work Plan’s recommendations regarding hydrogen classifications as well.¹¹⁹ Besides these definitional aspects, and similar to the previous proposal, Bill 5816/2023 also contains risk management guidelines and enables the creation of a hydrogen certification system, along with other measures.¹²⁰ As it relates to oversight, it bifurcates competences, assigning regulatory authority over hydrogen production to either the National Electricity Agency (ANEEL) or the ANP depending on the technological pathways.¹²¹

The third bill, the legislative initiative of the Brazilian Federal Government, also seeks to lay the groundwork for its hydrogen plans.¹²² This bill exclusively addresses ‘low-carbon emission hydrogen’, with its definition adopting practically the same language as Brazil’s Work Plan.¹²³ Namely, it defines it as hydrogen produced via technologies and energy sources with low lifecycle GHG emissions or utilizing carbon removal technologies – thus encompassing ‘renewable’, ‘green’ and ‘blue’ hydrogen.¹²⁴ While this approach circumvents the potential limitations of a fixed emission threshold, the bill does not otherwise define what constitutes ‘low lifecycle emissions’, requiring eventual clarification. Definitions aside, the bill also seeks to establish a hydrogen certification framework, with much of its text dedicated to this purpose.¹²⁵ Unlike the previous bills, however, it does not contain safety or risk management guidelines, nor does it assign regulatory competences over hydrogen production activities, except as it relates to naturally occurring hydrogen.¹²⁶

In terms of legislative progression, Bill 2308/2023 represents the most advanced of the three. At the time of writing, the bill cleared the Chamber of Deputies, and is being analysed in the Senate.¹²⁷ Bill 5816/2023 has also made headway, securing approval from the relevant Senate commission and being consequently sent to the Chamber of Deputies for deliberation.¹²⁸ Trailing these proposals, the Federal Government’s bill was presented to the Sustainable Economic and Social Council for further consideration.¹²⁹ As of the time of writing, it has yet to be formally submitted to the Brazilian Congress.

As we can see, while Brazil lacks hydrogen regulations formally in force, it exhibits a flurry of legislative activity across chambers and ministries seeking to enable the industry’s ascent. Still, it simultaneously reveals a universe of conflicting definitions, competences and paths towards certification systems, evidencing the complexity and diversity of views in the country. These varied proposals, each with its unique focus and regulatory approach, emphasize the dynamic and fragmented nature of Brazil’s pursuit of a hydrogen economy. Until the fog of competing visions clears, the precise contours of Brazil’s soon-to-be hydrogen legal framework will remain uncertain.

Overall, the regulatory environment for hydrogen in Chile, Colombia and Brazil reveals an evolving terrain. Each country, dealing with its unique complexities, has set out on a path to establish frameworks conducive to clean hydrogen development. While appreciable progress has been made, significant work remains ahead to truly match policy ambitions. Even so, as the following section will discuss, these regulatory imperfections have not stopped the number of clean hydrogen projects in Chile, Colombia and Brazil from growing considerably.

4.4 From Regulation to Production: On-the-Ground Deployment under Existing Governance

Despite this evolving character of the hydrogen regulatory frameworks in Chile, Colombia and Brazil, the pace of on-the-ground project development is continuing. Developers are forging ahead, undeterred by the gaps and inadequacies in existing governance.¹³⁰ This section briefly explores these tangible developments, highlighting how, even amid a backdrop of regulatory uncertainty, the industry is making strides in turning policy visions into concrete projects.

This apparent paradox between incomplete regulation and robust project activity stems, at least in part, from these countries’ constitutional provisions enshrining a principle of freedom of enterprise. Namely, in Chile, Colombia and Brazil, business activity can proceed freely absent explicit prohibition, thus requiring no prior authorizations or permits except as provided by law.¹³¹ In this context, hydrogen-related activities across the value chain are, by default, free to be pursued and developed, provided they adhere to any applicable rules. This backdrop of flexibility has provided latitude for the hydrogen industry to advance even under transitional governance.

In this scenario, absent specific legal provisions, hydrogen ventures remain subject to the same permitting obligations and licensing protocols imposed universally across infrastructure projects. Thus, hydrogen undertakings, akin to hazardous chemical production plants in many respects,¹³² require an array of permits to break ground and eventually become operational. This process typically entails adherence to a diverse range of mandates, including but not limited to site planning, construction compliance, environmental impact assessments, water resource management, waste disposal protocols and observance of health and safety guidelines.¹³³

Pragmatically leveraging the existing frameworks, over 100 hydrogen projects across different phases have been logged across these countries as of late 2023, spanning from initial feasibility studies to fully operational plants.¹³⁴ More than half of these are in Chile, with at least three projects under construction and six already operational.¹³⁵ Amongst these, the Cerro Pabellón microgrid pilot project, operational since 2019, has been utilizing solar energy to generate 10 tonnes of green hydrogen per year.¹³⁶ Of larger scale, the Haru Oni demonstration plant is capable of producing 130,000 litres of e-fuels per year, making it the first operating e-fuels facility in the world.¹³⁷

Colombia’s hydrogen sector includes twenty-seven projects across various stages, with three in construction and four operational.¹³⁸ Notably, in early 2022, the Ecopetrol Group launched a three-month pilot project with the aim of producing 20 kg daily of high-purity green hydrogen for refinery usage. While small-scale, the pilot’s objective was to assess the technical and environmental feasibility and performance of green hydrogen generation at the Cartagena Refinery.¹³⁹ Capitalizing on this experience, Ecopetrol is set to start the construction of two green hydrogen ‘megaprojects’ in 2024, expected to be amongst the largest in Latin America.¹⁴⁰

Following closely behind, Brazil accounts for the remaining twenty-four projects, with two operational and a third under construction. In particular, White Martins has launched a green hydrogen production project with a yearly output of 156 tonnes destined for the local market.¹⁴¹ Importantly, this project has been certified by TÜV Rheinland, making it the first plant in Latin America certified to produce green hydrogen.¹⁴² The second operational undertaking is EDP Brazil’s pilot project, part of a larger R&D initiative, which can produce 250 normal cubic metres of hydrogen gas per hour – operational hours determining annualized output.¹⁴³

This overview reveals a significant trend: although the regulatory structures may still be in a state of flux, they have not impeded the practical progression of hydrogen pilot projects. Still, reliance on (permitting) frameworks not specifically designed with the particularities of hydrogen projects in mind poses risks and increases stakeholder uncertainty. The varied nature of hydrogen undertakings, shaped by diverse technologies and processes, stresses the need for a tailored regulatory approach. This requires not only the adoption of hydrogen-specific regulations, as previously discussed, but also a thorough review and amendment of existing permitting structures in line with the characteristics of hydrogen projects. Recognizing this imperative, the strategies of Chile, Colombia and Brazil all include actions towards adapting their permitting procedures.¹⁴⁴ As the industry shifts from scattered pilots to widespread commercialization, these countries’ continued regulatory efforts remain integral to realizing hydrogen’s potential across the region.

4.5 Conclusion

The hydrogen landscape in Latin America, as exemplified by the endeavours of Chile, Colombia and Brazil, is marked by promise and challenge. Driven both by growing global demand and the motivation to decarbonize their economies, their initiatives represent a regional shift towards embracing clean hydrogen. These resource-rich countries have quickly progressed from articulating ambitious strategies to dealing with the complexities of designing enabling regulatory frameworks. While distinct in approach and execution, their policies converge on a common goal: to position themselves as major players in the impending hydrogen economy.

However, as their experiences reveal, the path from promise to production is fraught with challenges. Indeed, creating a regulatory environment that accommodates hydrogen’s multidimensional nature is proving to be a demanding task, with governance structures struggling to match the pace of technological developments and market demands. Yet, despite these regulatory uncertainties, interest in clean hydrogen projects continues to grow, with pilot ventures forging ahead undeterred.

As Latin America looks to the future, the hydrogen promise appears compelling, even if exacting. The experiences and lessons emerging from Chile, Colombia and Brazil offer valuable insights for other countries, highlighting the critical role of coherent policy and regulatory frameworks in the transition towards a hydrogen future. While the full realization of Latin America’s hydrogen potential remains to be seen, the current momentum offers reasons for optimism.

5 Hydrogen Regulation in Oceania Enabling Renewable Hydrogen Licensing on Complex Land Uses

Madeline Taylor

5.1 Introduction

Hydrogen and its derivates are widely touted as an essential component in the quest for global decarbonisation. Hydrogen is a versatile and dynamic energy carrier that can be harnessed as an alternative feedstock in industrial processes, transportation, and storage, and may be blended with natural gas as an alternative to fossil fuels, amongst other potential applications.¹ More than forty countries have released hydrogen strategies, and the International Energy Agency (IEA) has predicted the low-emissions hydrogen sector value may increase from $1.4 billion in 2023 to $12 billion by 2030.² To reach these projections, it is widely recognised that ‘the emergence of a clean hydrogen economy depends on regulation’.³ Planning and licensing hydrogen with concurrent land uses is a piece of the hydrogen regulatory rubric. Licensing and permitting procedures to assess and manage hydrogen land uses must be efficient, transparent, and coordinated to minimise planning assessment lead times and ensure sustainable siting of hydrogen coexisting with other land uses.⁴

The Oceania region is increasingly targeting the production and export of renewable hydrogen, also referred to as ‘green hydrogen’, which is typically produced by separating hydrogen from oxygen via electrolysis of water to harness renewable energy.⁵ Other than water requirements for electrolysis, considerable amounts of land are also critical for large-scale renewable hydrogen production. Land access and use are required to host the suite of renewable hydrogen infrastructure supporting its generation and further infrastructure to enable export. For example, the co-location of wind and solar farms to efficiently produce renewable hydrogen requires an estimated land area of about 168,000 square kilometres (km²). This positions countries with large amounts of cleared land situated in proximity to existing energy infrastructure and ports, like Australia, at an advantage. Up to 11 per cent of Australia (872,000 km²) has been estimated as highly suitable for renewable hydrogen production.⁶

Countries with existing high penetration of renewable energy into their electricity generation mix, coupled with ample water reservoirs without the necessity for desalination,⁷ may also enjoy advantages in establishing a renewable hydrogen sector. In New Zealand, renewables provide 82 per cent of electricity generation, primarily comprising its significant hydropower capacity representing 55.6 per cent,⁸ coupled with accessible fresh water basins, and between 600 and 10,000 mm of rainfall per annum across the country.⁹

Renewable hydrogen development consequently requires strategic planning due to the land use footprints of projects, requiring renewable energy generation, electrolyser siting, and export and transportation infrastructure. Without a clear regulatory approach for renewable hydrogen siting, licensing, and development assessment, communities may contest renewable hydrogen projects based on conflicting land uses and the preservation of existing land rights.

This chapter examines renewable hydrogen policies and regulatory trends in Oceania. Specifically, it analyses the regulatory approach taken by two of the most proactive Australian states with renewable hydrogen ambitions, Western Australia and South Australia, and their recent regulatory reforms for renewable hydrogen licensing on pastoral land. In so doing, it surveys the emerging challenges and opportunities for renewable hydrogen siting by exposing crucial legal processes to avoid land use conflict for the renewable hydrogen sector.

The chapter is structured as follows. Firstly, it first explores the different national hydrogen strategies in Australia and New Zealand (Section 5.2). Secondly, it analyses and compares the new regulatory amendments and new hydrogen licensing regulation on pastoral land uses in Western Australia and South Australia (Section 5.3). Finally, it concludes by charting the challenges for the development of renewable hydrogen regulation to realise hydrogen licensing coexistence with pastoral land uses in both Australia and New Zealand (Section 5.4).

5.2 The Oceania Region as a Potential Hydrogen Powerhouse

New Zealand and Australia aim to become the leading hydrogen production powerhouses of the Oceania region. Existing renewable hydrogen strategies in both New Zealand and Australia rest on their innate advantages – increasing renewable energy¹⁰ penetration and proximity to Asian energy markets.¹¹ Both countries hold federal Commonwealth systems of government regulating overarching hydrogen strategies with subnational states, territories, or provinces regulating planning and land use.¹² Hence, consideration of existing federal strategies for the production and potential export of hydrogen is examined in Sections 5.2.1 and 5.2.2 below before an analysis of hydrogen licensing and land use systems at the state level.

5.2.1 New Zealand’s Hydrogen Roadmap

Renewable hydrogen will play a crucial role in shaping New Zealand’s energy landscape as the nation works towards achieving its legislated target of net zero greenhouse gas (GHG) emissions (excluding biogenic methane)¹³ by 2050.¹⁴ More than twenty hydrogen projects stretching from Marsden Point in the North Island to Invercargill in the South Island are in development or being considered in New Zealand’s early-stage hydrogen ecosystem.¹⁵ However, New Zealand does not hold a finalised national hydrogen strategy, with its first Hydrogen Roadmap due for release in late 2024.

The lag in creating a national hydrogen policy in New Zealand is due to several factors, including the low projections of hydrogen reaching just 8 per cent of total energy demand domestically.¹⁶ Such low projections are in stark contrast to Australian demand projections for hydrogen, which may represent 20 per cent of total energy demand in 2050.¹⁷ The low demand estimate and delayed delivery of a national hydrogen in New Zealand has created a regulatory and policy environment ‘at least three years behind Australia’,¹⁸ particularly in terms of secured capital investment and hydrogen standards adoptions. To date, New Zealand’s developing hydrogen policy position has focused on hydrogen applications to decarbonise industrial processes, evident in an over NZ$ 30 million budgetary commitment to accelerate the adoption of renewable hydrogen to decarbonise energy in hard-to-abate sectors, particularly ammonia manufacturing.¹⁹

The first national response to hydrogen in New Zealand was the 2019 Vision for Hydrogen in New Zealand (‘2019 Hydrogen Vision’).²⁰ The 2019 Hydrogen Vision targeted New Zealand’s 84 per cent renewable electricity penetration,²¹ representing the fourth highest in the Organisation for Economic Development and Co-operation (OECD), with a goal to transition to 90 per cent renewable energy by 2025 and 100 per cent by 2030.²² However, as a consultation Green Paper rather than a finalised national policy, the 2019 Hydrogen Vision produced feedback to inform the creation of a national hydrogen strategy.

Following the 2019 Hydrogen Vision, the Interim Hydrogen Roadmap was released in 2023 to provide another stocktake of policy options and invite another round of consultation to support renewable hydrogen development in New Zealand.²³ Similarly to the 2019 Hydrogen Vision, the Interim Hydrogen Roadmap is seeking feedback on the overarching potential policy focus to optimise hydrogen to contribute to New Zealand’s domestic emissions reduction goals, stimulate economic development, and, interestingly, bolster its energy security and resilience. New Zealand’s decision to prohibit new petroleum permits outside Taranaki onshore²⁴ and become more reliant on petroleum imports has seen energy security become a new potential policy pillar for hydrogen. A focus on hydrogen to create energy security exists in contrast to Australia, where energy security is not evident in hydrogen policymaking to date. In emphasising the importance of domestic use of hydrogen at the household and industrial levels, the Interim Hydrogen Roadmap rules out the case for government incentivisation and support to scale-up a hydrogen export industry.²⁵ A domestically focused hydrogen roadmap in New Zealand represents another point of comparison to Australia’s export-orientated hydrogen policy focus.²⁶

Consistent with the previous 2019 Hydrogen Vision, a similar emphasis in the Interim Hydrogen Roadmap is placed on the potential for renewable hydrogen to decarbonise industrial production of fertiliser-based chemicals, particularly as New Zealand is largely dependent on the importation of urea.²⁷ For example, the Balance Agri-Nutrients Plant in Kapuni is New Zealand’s only ammonia-urea manufacturing facility, producing 730 tonnes of urea per day with an annual natural gas consumption of 7 petajoule (PJ).²⁸ The Balance Agri-Nutrients Plant is cited as a key project to develop a green hydrogen production facility to enable the production of lower-carbon urea and offset up to 12,000 tonnes of domestic emissions.²⁹ Agriculture represents 48 per cent of the gross GHG emissions for New Zealand and a legislated price on emission from agricultural activities to meet its Emissions Trading Scheme will likely commence on 1 January 2026.³⁰ In preparation for an agriculture-sector-specific emissions price and reporting scheme, the opportunity to decarbonise ammonia processing to create ‘green ammonia urea’³¹ specifically targets hydrogen as an important potential alternative feedstock to natural gas.³² This policy position fundamentally differs from Australia’s approach prioritising hydrogen exports as an initial policy platform with industrial feedstock usage for hydrogen as a secondary policy priority.

To support the development of a national energy strategy, Standards New Zealand completed its review of the current gaps in existing natural gas standards for hydrogen in 2023. The Standards New Zealand review identifies the overlapping regulatory regimes spanning gas safety, electrical safety, land transport, and other hazards and the six existing standards relevant to hydrogen for possible revision.³³ In particular, NZS 5442:2008 – Specification for reticulated natural gas – has not been holistically updated since 2008, with the most recent interim revision to permit blending of biomethane. However, the blending of hydrogen with natural gas is currently not permitted under NZS 5442:2008.³⁴ The resulting review advocates for a safety-focused guidance handbook and support for coordinated cross-agency action to implement standards amendments as a preliminary step to support a domestic hydrogen sector.³⁵

The 2023 New Zealand Hydrogen Regulatory Pathway review similarly analysed forty-four Acts and ninety-three regulations and rules that may be relevant to hydrogen based on safety, use, markets, measurements, infrastructure, and resources to support a hydrogen sector. The Hydrogen Regulatory Pathway review critiques prescriptive rule-based regulatory requirements for gas usage resulting in regulatory gaps or uncertainty over hydrogen transportation. For example, the Hazardous Substances and New Organisms Act (1996) (NZ) prohibits the production of refrigerated liquefied hydrogen and exposes policy opaqueness as to whether hydrogen blends would fall under the Commerce Act (1986) (NZ), which currently does not define or incorporate the regulation of blended gases. The Hydrogen Regulatory Pathway review recommends similar policy developments completed in the EU, particularly in Germany and the Netherlands, including ‘the development of dedicated small–medium scale renewable generation for direct connection to electrolysers to be used as hydrogen “hubs”’.³⁶

An additional differing policy juncture between New Zealand and Australia is New Zealand’s emphasis on supporting just transition goals for communities hosting hydrogen. Supporting landholders and communities in proximity or hosting hydrogen projects has been emphasised since the 2019 Vision. A focus on creating just outcomes for communities associated with hydrogen production is reiterated in the Interim Hydrogen Roadmap through the establishment of the $100 million ten-year Regional Hydrogen Transition Initiative.³⁷ The Regional Hydrogen Transition will provide governmental rebates to support first-mover hydrogen projects through long-term contracts between government and commercial hydrogen consumers.

In awarding long-term contracts, the Regional Hydrogen Transition Initiative targets creating a ‘Just Transition’ for key regions, including Southland, traditionally an oil and gas region, and Taranaki to support the transition of workers within the New Zealand Aluminium Smelter at Tiwai Point. To access the Regional Hydrogen Transition Initiative rebate, proponents must demonstrate how their proposal meets the four elements of the Regional Hydrogen Transition benefit sharing model: (1) selecting a just transitions region; (2) Iwi (meaning cultural, environmental, social, and economic opportunities must be reflected in contractual applications) and the community; (3) renewable energy generation; (4) contribution to the development of the hydrogen economy. Community benefit funds, regional skills and training commitments, and contracting with new renewable energy generation may be conditions to satisfy the four outlined criteria.³⁸

Overall, New Zealand’s comparatively domestic and justice-focused hydrogen strategy represents an interesting approach to support key hydrogen projects that aim to help build and test early-stage projects while engaging directly with communities. Australia’s National Hydrogen Strategy takes a more responsive, interventionist, and export-focused policy and regulatory approach to establishing its hydrogen ambitions, as explored below.

5.2.2 Australia’s National Hydrogen Strategy

Australia’s hydrogen export objectives are evident in its pioneering of the first liquified international trade of hydrogen to Japan in 2022. The Suiso Frontier shipped 75 tonnes of liquified hydrogen to Japan as part of the Hydrogen Energy Supply Chain (HESC) project. The HESC project positions Australia as a key exporter of hydrogen to Japan to 225 kilotonnes (kt) per year in the 2030s.³⁹ Although the potential for hydrogen exports first became a policy focus for Australia in 2019, developing a hydrogen economy was first highlighted in Australia in 2002 when the Renewable Energy Technology Roadmap labelled renewable hydrogen as having ‘huge future potential’.⁴⁰ Nearly two decades later, Australia’s first National Hydrogen Strategy was released in 2019 underpinned by three key policy goals to facilitate fifty-seven joint actions around seven themes⁴¹ targeting the renewable hydrogen pricing stretch goal of reaching AU$2 per kg (H₂ (hydrogen) under $2) originally set in the Low Emissions Technology Statement.⁴² This cost target is ambitious, with stand-alone wind and solar projects (financed over twenty years) utilising renewable electrolysis to produce renewable hydrogen currently projected to cost AU$4–12/kg.⁴³

To create the rapid reduction of hydrogen production costs, in 2023 the federal public renewable energy funding body, the Australian Renewable Energy Agency, announced the establishment of the AU$2 billion Hydrogen Headstart Fund with a further $2 billion announced in the 2024–2025 Australian Federal Budget.⁴⁴ The Hydrogen Headstart Fund will award production credits to support large-scale renewable hydrogen projects to cover the commercial gap between the cost of hydrogen produced and the sale price of the hydrogen, or its derivatives.⁴⁵ The Hydrogen Headstart Fund projects will be funded from 2026/27 for a maximum funding period of ten years.⁴⁶ While this funding is dwarfed compared to other hydrogen funding schemes in the European Union and United States,⁴⁷ it is likely to support the first large-scale renewable hydrogen export projects in Australia.

To become a ‘hydrogen production powerhouse’⁴⁸ by ‘shipping sunshine’ in the form of liquefied hydrogen to the world, Australia has adopted a responsive regulatory stance to ensure regulatory reform facilitating investment.⁴⁹ The responsive regulatory approach is built upon the proportional regulatory intervention required to meet regulatory objectives according to the responsive regulation pyramid, originally conceptualised and championed by Braithwaite.⁵⁰

The responsive regulation pyramid aims to promote voluntary compliance at the ‘base’ of the pyramid, through guidelines that are typically industry-led, with increasing severity of stations at the ‘apex’ of the pyramid. This responsive regulatory approach was also adopted within Australia’s East Coast Domestic Gas Market. For example, Australia created its leading global liquified natural gas export sector without any legislation mandating gas reservation for Australia’s largest gas market. In line with a responsive approach, Australia has adopted an industry-led agreement and code of conduct to prevent gas supply shortfalls and secure competitively priced gas for the domestic gas market with the LNG export sector.⁵¹ Similarly, five industry codes of practice are being developed with the hydrogen industry, as discussed below.

Australia has built its strategy around enabling ‘clean hydrogen’, rather than a narrower approach targeting renewable hydrogen only, as is the case in New Zealand. Clean hydrogen pathways are not restricted to renewable hydrogen but rather include gasification through thermochemical reactions with coal as a feedstock and steam methane reforming using natural gas coupled with carbon capture and storage. The responsive pathway to realise Australia’s position as a hydrogen exporter is divided into two phases. The first phase between 2019 and 2025 seeks to provide ‘foundations and demonstrations’⁵² of hydrogen by undertaking priority pilot, trials, and demonstration projects; assess supply chain infrastructure needs; build demonstration hydrogen hubs; and develop supply chains for prospective hydrogen hubs to scale-up supported by bilateral agreements, including with Germany, Japan, and The Netherlands.⁵³

From 2025 to 2030 the second hydrogen strategy phase seeks to create ‘large-scale activisation’⁵⁴ of hydrogen to scale up industry capacity for hydrogen supply chain to support export industry infrastructure and create a domestic market with explicit public benefits.⁵⁵ Overall, four key progress measures for the success of Australia’s hydrogen industry are mapped, ranging from Australia developing an internationally accepted certification regime to hydrogen providing jobs and economic benefits.⁵⁶ Yet no baseline data, data sharing, or demand and production targets have been set to assess progress towards these measures.

Since the development of the National Hydrogen Strategy, the interim 2022 State of Hydrogen report provides an update on the advancement and progress towards realising Australia’s overall goal of becoming a top three hydrogen exporter. The State of Hydrogen Report confirms ‘Australia has around 40 percent of all announced global hydrogen projects, with the Australian pipeline valued from $230 billion to $300 billion’.⁵⁷ To support the development of a hydrogen projects pipeline to support export, the federal Australian government is also developing a proposed Guarantee of Origin Scheme.⁵⁸ The Guarantee of Origin Scheme seeks to track and verify emissions associated with hydrogen production and its derivatives. The proposed Guarantee of Origin Scheme will also create a mechanism for renewable energy certification in direct response to the revised EU Renewable Energy Directive and supporting delegated acts defining renewable fuels of non-biological origin (RFNBOs).⁵⁹

In a similar vein to the EU-based CertifHY scheme,⁶⁰ an industry-led Zero Carbon Certification Scheme has been launched by peak industry body the Smart Energy Council to promote the creation of an Australian hydrogen export sector.⁶¹ The first renewable hydrogen project to receive pre-certification is Yara’s green ammonia plant currently being built in the Pilbara, Western Australia. While certification schemes are crucial, particularly to support hydrogen exports, to implement hydrogen initiatives and schemes, one of the key inhibitors to rapidly building up the Australian hydrogen supply chain is the need for consistency in ‘implementing standards, regulations, and certification’⁶² for hydrogen at the national and state levels in Australia. This has led the federal Australian government to conduct its current holistic review of the National Hydrogen Strategy with a revised strategy anticipated in 2024.

Since 2022, the Australian government has been undertaking a national Review of Hydrogen Regulation to ensure hydrogen safety⁶³ and development.⁶⁴ At the federal level, several regulatory amendments are being planned to support the development of the Australian hydrogen sector ranging from safety laws to hydrogen transportation. In a responsive approach, new standards will be co-designed with the industry under five codes of practice, on hydrogen production; ammonia production; hydrogen refuelling; hydrogen appliances; and ammonia appliances, and are likely to be finalised in 2024.

As an interim measure before the finalisation of the five codes of practice and to support immediate applications of hydrogen blending into the domestic East Coast Gas Market, the federal National Gas Law (NGL) and National Energy Retail Law (NERL)⁶⁵ have been amended to incorporate hydrogen. As the Australian Constitution makes no express reference to energy, responsibility for energy market regulation falls within the plenary legislative power of the states and territories. Exercising cooperative federalism, participating jurisdictions have adopted a ‘unitary regulatory system’⁶⁶ whereby each state adopts national laws mirroring the South Australian energy legislation. The NGL and NERL previously regulated third-party access to pipeline services and other services of ‘natural gas processable gas’ only.⁶⁷ Hydrogen did not fall under the definition of a naturally occurring gas and consequently the NGL and NERL are being amended pursuant to the recent passage of the Statutes Amendment (National Energy Laws) (Other Gases) Act 2023. Under the amendment, hydrogen is explicitly defined as a ‘relevant covered gas’ to enable low-level blends of hydrogen with gases within the domestic East Coast Gas network.⁶⁸

As the discussion above illustrates, enthusiasm and strategies are not lacking to develop hydrogen sectors in Australia and New Zealand. However, robust national regulatory frameworks providing the foundation for hydrogen production, processing, and potential export are evidently at differing states of maturity. Australia has enacted the first federal changes to permit the regulation of gas pipelines blended with hydrogen in amending the NGL and NERL. Developing domestic hydrogen capacity and infrastructure early is crucial to reaching export and decarbonisation goals for industrial processes such as ammonia in New Zealand. From an export perspective, the entire hydrogen production lifecycle must be effectively regulated to provide commercial investment certainty and conformity with international hydrogen certification and greenhouse gas calculation methodologies.⁶⁹ From a domestic perspective and to activate a hydrogen export sector, the planning, assessment, and licensing regime to rapidly scale up renewable hydrogen production is crucial, as explored below in Section 5.3.

5.3 Harmonising Hydrogen Land Use: Comparing Australian State Approaches to Renewable Hydrogen Licensing on Pastoral Land

Developing renewable hydrogen economies in Australia and New Zealand will require the planning and allocation of licences and the management of competing land uses. This regulatory need arises from the fact that renewable hydrogen infrastructure will require the industrial use of land which may conflict with existing non-industrial uses. One of the key land use competitions with hydrogen production, particularly in Australia and potentially in New Zealand, is on pastoral lease Crown land traditionally reserved for pastoral land uses. The cost of constructing transmission infrastructure and accessing large areas of cleared land in proximity to major energy load centres will likely increase the economic viability of renewable hydrogen. These elements are often evident in pastoral leasehold land, which covers 44 per cent of Australia⁷⁰ and 37 per cent of New Zealand,⁷¹ rendering it ideal to use for hydrogen production. However, this may lead to regulatory complexities over how hydrogen licences should be assessed and awarded by regulators in pastoral land use zones previously prohibited to utility-scale energy development.

This section will be confined to an analysis and comparison of the recent regulatory reforms to support hydrogen production facilities on pastoral lands in two Australian states, Western Australia and South Australia.⁷² Although New Zealand also holds a pastoral leasehold system, New Zealand has recently overhauled its previous environment and planning law, the Resource Management Act 1991 (NZ), and enacted two new pieces of legislation: the Natural and Built Environment Act 2023 (NZ) (NBA) and the Spatial Planning Act 2023 (SPA) (NZ), to be phased in over a ten-year period.⁷³ Neither statute currently contains any express reference to hydrogen. Consequently, this chapter will focus on the Australian state experience, representing a more mature regulatory environment with express reforms relating to hydrogen.

5.3.1 Defining Pastoral Leases

Following colonisation by Britain, and to prevent unauthorised settlement, the majority of Australia’s rural arid and semi-arid lands were granted as a Crown statutory estate called pastoral leases. Pastoral leases as a tenure system became formalised by the landmark 1847 Order in Council and ‘established 14-year leases in the unsettled districts and gave lessees renewal and compensation rights’⁷⁴ as a form of progressive land settlement requiring that land is held for ‘pastoral purposes’ only – traditionally sheep and cattle grazing. Pastoral leases are vast in Australia, currently constituting nearly half of Australia’s mainland (equating to 338 million hectares).⁷⁵

Unlike traditional common law or equitable leases, pastoral leases are purely a creature of statute to permit Crown-owned land to be leased for commercial grazing, agricultural, horticultural, or other supplementary pastoral use. Pastoral lease terms vary greatly within Australian states and territories. For example, in NSW pastoral leases are perpetually equated to a right to possess the land for an indefinite period.⁷⁶ In Queensland, the Northern Territory, and Western Australia pastoral leases are generally fixed-term agreements that expressly do not afford leaseholders a right to exclusive possession.⁷⁷ Eighty-seven per cent of Western Australia consists of rangelands and 38 per cent of the rangelands are held under pastoral leases.⁷⁸ Forty per cent of South Australia consists of land held under pastoral leases.

The high renewable energy potential, existing oil and gas infrastructure, and the need to access land to produce large-scale renewable hydrogen projects have led to Western Australia and South Australia either amending their pastoral lease regulation or creating new hydrogen licensing regulations to access pastoral land. Western Australia was the first Australian state to amend its pastoral leasehold regulation to accommodate renewable hydrogen siting, which will be discussed in more detail in Section 5.3.2.

5.3.2 Diversification Leases: The Western Australian Approach

Western Australia is the largest Australian state, covering 2.5 million km². One-third of the Western Australian state landmass is held under pastoral leases.⁷⁹ Pastoralism became the central socio-economic land use in Western Australia from the late 1890s, attracting settlers in the rangelands to farm. From the 1920s onwards, pastoral leases became increasingly popular, with cattle and sheep stations becoming a key sector of the Western Australian economy. In particular, pastoral leases have become common in the Pilbara region, one of nine regions located in Western Australia, the geographical size of Spain, with large rangelands and considerable endowments of iron ore, lithium, gold, copper, nickel, and offshore petroleum.⁸⁰

The Pilbara will become one of the most important hydrogen-producing regions in Australia. Its strategic geographical location close to Asian markets on Australia’s west coast coupled with existing mining and petroleum value chains and petroleum export infrastructure have created the ideal conditions for prospective hydrogen hubs. The five hydrogen production hubs planned in the Pilbara region to be connected by hydrogen pipelines are touted as strategic zoning areas ‘to provide common user infrastructure to support renewable hydrogen supply chain activity’,⁸¹ with the potential to produce from 3 to over 10 million tonnes of hydrogen per annum by 2050.⁸²

For example, the H2Kwinana Hydrogen Hub will host a 100 megawatt (MW) electrolyser to produce over 14,000 tonnes of green hydrogen per annum for industrial use, heavy transport, and export.⁸³ The development of hydrogen hubs in the Pilbara sparked the need to consider reform to permit hydrogen production facilities on pastoral land. As pastoral leases are Crown-owned and restricted to pastoral activities,⁸⁴ alternative land uses and planning approvals for hydrogen infrastructure were previously not permitted pursuant to the Land Administration Act 1997 (WA).⁸⁵ To unlock the potential for hydrogen in Western Australia, pastoral leases need to host multi-purpose industrial land uses.⁸⁶

The default statutory prohibition of any development activities other than pastoral for pastoral leases led to the first regulatory shift in Australia relating to hydrogen land use. While pastoralist landholders could previously apply for a diversification permit to undertake activities for non-pastoral purposes, such permits were only granted in limited circumstances and would not allow for the development of hydrogen and other renewable projects. The Crown could also acquire⁸⁷ and terminate pastoral leasehold interests for ‘public works’ land uses,⁸⁸ which holds a limited definition, including public infrastructure such as public schools and hospitals, and did not expressly include energy development. Consequently, a new non-exclusive land tenure type, the Diversification Lease, was proposed and enacted in the Land and Public Works Legislation Amendment Act 2023 (WA) (LPWLA Act).⁸⁹

The LPWLA Act amends the Land Administration Act 1997 (WA) (LAA Act) and the Public Works Act 1902 (WA) to permit the grant of a new Diversification Lease ‘for any purpose or purposes’⁹⁰ on unallocated Crown land or to enable existing and new pastoral leases to be transferred to diversification leases.⁹¹ In adapting existing pastoral land regulation to enable non-pastoralist activities supporting a hydrogen sector, Western Australia has adopted an ‘adaptive’ approach by amending its existing pastoral lands regulation.⁹² Adaptive management is often deployed in the context of natural resources regulation and aims to adapt legal frameworks to accommodate new technologies and monitor outcomes potentially requiring adaptive amendments to existing legislation.⁹³

The adaptive approach permits Diversification Leases to be applied for in a streamlined approach prospectively and retrospectively on unallocated Crown land, new pastoral leases, and existing pastoral leases to permit hydrogen production and other activities, including carbon farming and renewable energy. A Diversification Lease will be awarded by the Minister for Lands and will be an optional tenure type available to both pastoral lessees and energy proponents without the conferral of exclusive possession.⁹⁴ However, unlike pastoral leases, diversification leases are designed for diverse non-exclusive and concurrent land uses including, but not exclusive to, grazing livestock, horticulture, renewable hydrogen, and carbon farming.⁹⁵

Diversification lessees must maintain the condition of the pastoral land and prevent land degradation.⁹⁶ It remains unclear whether the diversification lessee must act in accordance with standards and guidelines that will be set under powers afforded to the statutory Pastoral Lands Board pursuant to Division 2A of the LPWLA Act.⁹⁷ Such standards are applicable for pastoral leaseholders, setting out benchmarks and objectives about the condition of land held under pastoral leases.⁹⁸ As leasehold rental payments will not be afforded to landholders but rather will be received by the Crown, an assessment regimen requiring environmental impact assessments to preserve pastoral activities following Pastoral Lands Board guidelines is crucial.

Diversification lessees must satisfy the relevant Minister, rather than the Pastoral Lease Board as the statutory authority for pastoral leases, that land under the lease will be treated ‘using methods of best environmental management practice appropriate to the area where the land is situated’.⁹⁹ Environmental management practices are currently undefined. Guidance for diversification lessees should be issued, particularly in consideration for water licensing, given water requirements for electrolysis and enduring water scarcity in the Pilbara region.¹⁰⁰

Diversifying pastoral leasehold land uses and conditions in Western Australia to permit renewable hydrogen development is crucial to support the development of hydrogen hubs. Pastoralists, rather than energy proponents alone, are permitted to apply for diversification leases to acquire additional income through new land use activities, such as carbon sequestration.¹⁰¹ Carbon management and sequestration activities often operate on at least a twenty-five-year project lifecycle, hence the amendment to permit pastoral leases and accompanying diversification leases to a maximum of fifty years via re-grant or extension is another important development.¹⁰² However, pastoralists must be adequately consulted and informed when considering the option to surrender pastoral leasehold lands in favour of a diversification lease. Arguably, the direct co-location of pastoralist activities alongside renewable energy production supporting renewable hydrogen, for example by way of agrivoltaics,¹⁰³ appears a missed opportunity as a mixed agricultural and renewable energy activity and land use does not appear to be expressly included within the LPWLA Act.

An alternative regulatory approach to extending the permissibility of renewable hydrogen within existing pastoral regulatory frameworks is to create bespoke and specific renewable hydrogen development principles, assessments, and licensing procedures. South Australia has taken this approach in its recently enacted Hydrogen and Renewable Energy Act 2023 (SA) (HRE Act).

5.3.3 Hydrogen Generation Licences: The South Australian Approach

South Australia is the vanguard of renewable energy success in Australia. It has transitioned its energy system from 1 per cent to 68 per cent renewable energy in a fifteen-year period and is forecast to reach 90 per cent renewable energy by 2025.¹⁰⁴ In 2022, South Australia became the first Australian state with 85.4 per cent of electricity demand being contributed by solar and wind.¹⁰⁵ With such high variable-renewable energy penetration, South Australia has set its policy sights on becoming a ‘world-class renewable hydrogen supplier’.¹⁰⁶ An initial hydrogen export feasibility study has projected South Australian renewable and blue hydrogen¹⁰⁷ could satisfy 10 per cent of Rotterdam’s hydrogen demand in 2050, forecast to reach 18 million tonnes per annum by 2050.¹⁰⁸ This policy aim seeks to be realised through South Australia’s Hydrogen Action Plan setting out twenty key actions across five areas to integrate hydrogen into its domestic energy system and scale up renewable hydrogen production for export.

Building on its success in regulating tight and shale gas as Australia’s leading onshore gas producer,¹⁰⁹ action two of the South Australian Hydrogen Action Plan is to establish a ‘world class regulatory framework’¹¹⁰ to build community and investor confidence as a key action. Similar to Western Australia, South Australia has also sought to amend its pastoral leasehold conditions to encourage renewable hydrogen development and ‘unlock land access to pastoral land’.¹¹¹

For example, the Planning and Design Code (SA), a statutory instrument representing the policies, rules, and classifications for land use planning, previously restricted renewable energy facility land uses, in Rural Land Zones where land is used wholly or mainly for primary production, such as pastoral leases.¹¹² Renewable energy facilities were defined to include solar, tidal, hydropower, biomass, and/or geothermal. However, hydrogen facilities were not recognised or defined under the Planning and Design Code (SA). This regulatory gap led the South Australian Productivity Commission in 2022 to recommend the Pastoral Land Management and Conservation Act 1989 (SA) (PLMC Act) be amended to enable renewable energy development and corresponding renewable hydrogen development on pastoral leases.¹¹³

Wind farm developments were previously the only utility-scale renewable energy developments permissible on pastoral land under s 49J of the PLMC Act with ministerial approval in South Australia. The PLMC Act governs land use and permissible development on pastoral land. As a pastoral lessee holds limited property rights to undertake pastoral activities only, applications seeking to access or use pastoral lease land for non-pastoral purposes are to be assessed by the Pastoral Unit and Pastoral Board and require ministerial approval. Applications are assessed according to their potential impact on the ongoing viability of pastoral activities, and their alignment with the objects of the PLMC Act to ‘make provision for the management and conservation of pastoral land’.¹¹⁴ Under the PLMC Act, all land uses apart from pastoralism and ancillary activities, mining, and wind farms are treated as ‘non-pastoral’ purposes or alternative land uses.

Despite advances in permitting wind farm development on pastoral land, other renewable energy activities were incompatible with pastoral activities under the PLMC Act. Thus, any application to develop pastoral land for renewable hydrogen production by co-locating would involve ‘excising the required land, changing the tenure and issuing of Crown licence(s) to facilitate land access and use’.¹¹⁵ This clear regulatory gap for renewable hydrogen development creating investment uncertainty and the need to access pastoral land has led to the enactment of the first bespoke hydrogen regulatory framework in Australia – the HRE Act.

The HRE Act provides a streamlined land use approvals and licensing scheme for hydrogen and renewable energy projects on pastoral leasehold land, other Crown land tenures defined as ‘designated land’,¹¹⁶ And some freehold land as ‘non-designated land’. The corresponding amendment of the PLMC Act upon the enactment of the HRE Act permits ‘renewable energy infrastructure and the undertaking of associated infrastructure activities’.¹¹⁷ The HRE Act is underpinned by the proposed legislative objective to ‘establish an effective, efficient and flexible regulatory framework for the constructing, operating, maintaining and decommissioning of renewable energy infrastructure and facilities for generating hydrogen for commercial purposes’.¹¹⁸ This objective represents a pivot away from a rules-based and adaptive approach to enact new regulation in the existing PLMC Act to a principle-based or goal-setting approach specifically for renewable hydrogen licensing to enable coexistence with other land uses in South Australia.¹¹⁹

Principle-based regulation is outcome orientated and describes the method of achieving a regulatory outcome by setting a general objective, standard, or duty without specifying the means of achieving that outcome in absolute terms.¹²⁰ Conversely, rule-based regulation places the proponent as an adversary, constantly testing and finding methods to check and reinterpret regulatory inconsistencies, requiring continuous amendments and updates to accommodate new legal issues. Principle-based regulation seeks to produce a regulatory system that is more effective and sustainable in the face of changing circumstances and complex technological developments in emerging sectors such as renewable hydrogen development.¹²¹ By taking a principle-based approach in South Australia, the HRE Act will permit regulators to actively participate in managing renewable hydrogen to encourage co-location with other land uses and activities, such as pastoral lessees, by regulating and enforcing the conditions of production and hydrogen development. This approach functions to ensure the activities of renewable hydrogen titleholders are aligned with broad regulatory principles. Similarly, France has also taken a goal-setting approach to the regulation of hydrogen transport.¹²²

The HRE Act provides the legal framework for Crown-owned land and waters, including pastoral leases to be identified and declared as suitable for the operation of renewable energy infrastructure and establish a competitive merit-based hydrogen generation licensing regime.¹²³ Where the release area comprises pastoral land, ‘occurrence of the Minister responsible for the administration of the Pastoral Land Management and Conservation Act 1989 (SA) is also required’.¹²⁴ Following the release of an HRE Act area, a competitive process for determining access to and use of pastoral land by the award of a hydrogen generation licence which authorises the construction, installation, operation, maintenance, and decommissioning of a hydrogen generation facility which must not exceed 5 km².¹²⁵

In contrast to Western Australia’s diversification lease, the environmental assessment and requirements for hydrogen production licences are clear. An Environmental Impact Report and Statement of Environmental Objectives¹²⁶ to assess and manage any adverse effects, the ‘risk of any significant long-term damage’¹²⁷ on the environment ‘as far as reasonably practicable’,¹²⁸ and ensuring rehabilitation of pastoral land will be required pursuant to the HRE Act. Finally, an operational management plan must be accepted and approved prior to the commencement of authorised operations.¹²⁹

In comparison to the Western Australian approach, the HRE Act expressly requires an access agreement to be entered into with a pastoral lessee before undertaking authorised operations under a hydrogen generation licence. Mandating an access agreement under the HRE Act explicitly recognises and protects the incumbent and persevering property rights of pastoralists. The access agreement must include an agreement as to any compensation that may be payable for the resumption of pastoral land for the purpose of a hydrogen generation facility or by associated infrastructure¹³⁰ and access conditions to the licence area or in the vicinity of the licence area.¹³¹ A process to mediate the negotiation of an access agreement is also stipulated within s 41 of the HRE Act including powers for the Minister to facilitate and assist in obtaining a land access agreement or determination by the South Australian Environment, Resources and Development Court. The South Australian government is currently finalising the HRE Regulations,¹³² which will include consultation requirements and criteria for the release area and licensing stages and the role of pastoralists and their interests during the negotiation of the land access agreement and throughout the hydrogen generation licence term.¹³³

As illustrated in the above discussion, the HRE Act not only creates the first hydrogen-specific planning and licensing regulation in Australia but also elevates the rights of pastoral leaseholders by expressly requiring access agreements and potential compensation to be negotiated prior to the award of a hydrogen generation licence. This position fundamentally differs from Western Australia’s diversification lease which expressly recognises pastoral leases retaining non-exclusive possessory rights over pastoral land and is silent as to whether pastoral lessees may receive compensation or require an access agreement. It is also notable that South Australia has chosen to implement hydrogen licensing interests in comparison with Western Australia’s approach to diversification leasehold interests. Consequently, hydrogen licences in South Australia may lead to challenges regarding the transferability of hydrogen licences between entities. In establishing a competitive tender process, the HRE Act seeks to uphold ‘environmentally sustainable and safe’¹³⁴ development of land use for hydrogen production by requiring an Environmental Impact Assessment including decommissioning and rehabilitation requirements.

Overall, the HRE Act, combined with its supplementary regulations currently in draft form, introduces a principle-based regulatory approach to the Australian hydrogen regulatory environment. It remains to be seen whether the HRE Act will enable an ‘effective, efficient and flexible regulatory framework’.¹³⁵ However, its principle-based requirements coupled with mandating access agreements provide enhanced regulatory certainty for hydrogen proponents and pastoral lessees alike.

5.4 Conclusion

Australia and New Zealand in the Oceania region have clear ambitions to become regional and global leaders in renewable hydrogen production. The federal Australian regulatory framework is actively being amended using a responsive regulatory approach commencing with the amendment to its National Gas Law and National Energy Retail Law and the current review of its National Hydrogen Strategy. However, many crucial aspects of the future renewable hydrogen supply chain and licensing systems will be regulated by states and territories. In practical terms, this requires measurable national strategies aligned with state and territory planning systems to design regulatory frameworks covering various aspects of the renewable hydrogen supply chain and, importantly, the siting of renewable hydrogen projects.

New Zealand is at the initial stages of mapping regulatory reform priorities to create its first federal hydrogen roadmap. Regulatory amendments will likely commence with amending natural gas pipeline standards and a rebate scheme to enable a just transition for hydrogen-hosting communities. The Regional Hydrogen Transition Initiative framework will likely stir a similar debate and suite of regulatory reform to permit the development of renewable hydrogen through a competitive licensing scheme on complex and overlapping land uses.

The differing approaches in Western Australia and South Australia to hydrogen regulation are apparent in regulatory amendments made to existing pastoral land legislation or the introduction of new hydrogen licensing regulations for renewable hydrogen facilities on pastoral land. As the renewable hydrogen regulatory landscape undergoes rapid changes in Australia, the effectiveness of South Australia’s principles-based approach encapsulated in the HRE Act and Western Australia’s adaptive strategy in establishing diversification leases is uncertain. The question remains as to which regulatory path will be more effective in encouraging renewable hydrogen development while maintaining and upholding pastoral land uses. Lessons from both states will be instrumental in shaping New Zealand’s approach to hydrogen planning and licensing within its recently enacted Natural and Built Environment Act 2023 (NZ) and Spatial Planning Act 2023 (NZ) and its Regional Hydrogen Transition Initiative.

Principles for renewable hydrogen development are crucial to guide and develop consistent and coherent licensing and planning regulatory regimes. Objectives and supporting standards to encourage the award of hydrogen production licences while preserving multiple land uses are becoming important in the hydrogen regulatory ecosystem. Realising Australia and New Zealand’s hydrogen aspirations undoubtedly raise evolving and persistent legal questions concerning the allocation of licences on complex and multiple land uses, particularly pastoral land.

Regardless of the differing approaches in Western Australia and South Australia’s hydrogen licensing regime, and the emerging hydrogen roadmap in New Zealand under development, it is crucial for both Australia and New Zealand to establish supportive legal frameworks for hydrogen development. Such frameworks must be crafted with careful consideration to maintain the balance between pastoral land uses and potential future complexities in land utilisation for renewable hydrogen.

6 Hydrogen Regulation in the Middle East and North Africa Region Trends, Limitations, and Ways Forward

Damilola S. Olawuyi and Mehrnoosh Aryanpour

6.1 Introduction

This chapter examines law and governance innovations required to integrate the production, distribution, and commercialization of hydrogen into the energy mix in the Middle East and North Africa (MENA) region. It examines current regulatory uncertainties and gaps in the design and implementation of hydrogen projects across the MENA region, and the legal pathways for addressing those challenges.

The development of low-carbon blue and green hydrogen has been identified as a national priority in several MENA countries.¹ For example, Qatar’s national oil and gas company, Qatar Energy – which already oversees one of the world’s most significant gas field and liquefaction facilities² – has signed an agreement with Shell to develop large-scale blue and green hydrogen projects.³ In particular, ‘Qatar plans to build a $1 billion plant to make blue ammonia, a fuel that can be converted into hydrogen’.⁴ Similarly, Morocco is pursuing green hydrogen studies and exploring policies to promote investment in the country’s green hydrogen economy.⁵ A Belgian engineering firm recently entered into a joint venture agreement with Morocco to create an electrolyser manufacturing plant, which can offer integrated green hydrogen solutions.⁶ Likewise, Saudi Arabia has already commenced work on the NEOM Green Ammonia project, a US$5 billion green hydrogen plant, and prospectively one of the world’s largest hydrogen facilities.⁷ Similarly, the United Arab Emirates has announced seven green and blue hydrogen projects.⁸ Efforts are also ongoing in Egypt to produce 20 million tons of green hydrogen annually by 2035, while Oman also signed a $3.5 billion deal for a green hydrogen plant.⁹

The MENA region is thus projected to become one of the world’s largest exporters of hydrogen by the year 2050, boasting significant proven reserves of natural gas – a key fuel for blue hydrogen projects – and a demonstrated track record of experience in managing complex logistics and infrastructure for the energy industry.¹⁰ However, while the proposed projects underscore increasing commitments across the region to diversify the energy mix and advance a low-carbon economy through the production of green hydrogen, the corresponding legal, governance, and institutional frameworks would need to be bolstered to keep pace with such hydrogen infrastructure investments.¹¹ A shift to a hydrogen economy in a region traditionally heavily reliant on fossil fuels will require the development of robust legal and governance frameworks that will provide a foundation for coherent implementation. The injection of significant amounts of hydrogen into the national energy networks comes with a wide range of logistical, infrastructure, and grid-balancing questions across the entire hydrogen production and supply chain. At the same time, health, safety, and environmental standards (HSE) for hydrogen infrastructure will need to be developed. Hydrogen is both complex to produce and store and capital intensive to distribute.¹²

After this introduction, Section 6.2 examines the drivers of the hydrogen revolution in the MENA region. Section 6.3 analyzes current regulatory uncertainties and gaps in the design and implementation of hydrogen projects across the MENA region. Section 6.4 proffers legal pathways for addressing those challenges. Section 6.5 concludes.

6.2 Drivers of the Hydrogen Revolution in the MENA Region

The growing emphasis on the transition to a hydrogen economy across the MENA region is due to four key drivers. First, there is an unprecedented rise in domestic energy demand in the region which will necessitate the diversification and expansion of supplemental energy supplies.¹³ ‘Intertwined with oil driven economic expansion is a geometric rise in population and energy consumption across the Gulf at a median rate of 5–10 per cent per year.’¹⁴ ‘Peak energy demand in the Middle East … is currently close to, and in some countries, slightly above installed capacity’, ‘especially during daytime in summer months when air conditioning use is highest’.¹⁵ For example, as of 2013, electricity demand in Qatar had steadily risen by more than 30 percent over the previous four years.¹⁶ ‘In Saudi Arabia, it is projected that peak-time electricity demand will almost triple to 120,000 megawatts by 2032, from around 46,000 megawatts in 2010.’¹⁷ Given these realities, investments in energy infrastructure for cleaner and potentially more efficient alternative supplies, including hydrogen grids, to meet the increasing peak demand for energy, and promote energy diversification, remains paramount across the region.¹⁸

A second driver of the increased interest in hydrogen investments in the region is the need for economic and energy diversification in preparation for the post oil and gas era. ‘Oil and gas resources across the region are not infinite and could be depleted within the next few decades’,¹⁹ at least to the point that marginal rises in costs render conventional hydrocarbons less competitive in the face of secular improvements in the economics of renewable/clean technology investments. The International Energy Agency (IEA) and BP both predicted a decline in global oil demand, ‘with demand falling by ten per cent this decade and by as much as 50 per cent over the next twenty years’,²⁰ as those cleaner sources expand their share of the energy consumption basket. Studies show that the Middle East could run out of oil by 2057, while natural gas supplies could be depleted by 2064.²¹ Given these statistics, MENA countries have embraced energy diversification through increased investments in hydrogen and renewable energy projects ‘as ways of mitigating the oil and gas depletion, while also preparing for life after oil and gas’.²² For example, the Pan-Arab Strategy for the Development of Renewable Energy (2010–2030) specifically sets a target of increasing installed renewable energy power generation capacity across the region from 12 gigawatts (GW) in 2013 to 75 GW in 2030.²³ Similarly, ‘Qatar expressly indicates in its [Qatar National Vision] 2030 the intention to invest in world-class infrastructure necessary to achieve “a diversified economy that gradually reduces dependence on hydrocarbon industries” by the year 2030.’²⁴ In recognition of the key roles that hydrogen will play in meeting the energy and economic diversification targets, MENA countries are coming together to expand joint initiatives and projects aimed at integrating hydrogen production into the energy mix.²⁵

Third and related is the increased emphasis on decarbonization and net-zero emissions across the world in response to the climate change emergency.²⁶ Efforts to mitigate climate change across the world sparked a gradual ‘shift away from carbon intensive fossil fuels, the bedrock of several MENA economies’.²⁷ Similarly, as signatories to the Paris Agreement and the United Nations Framework Convention on Climate Change, several MENA countries have already committed, via their intended nationally determined contributions (INDCs), to advance climate mitigation and adaptation efforts.²⁸ This includes ‘investing in climate-smart energy systems, ie structures and systems that lower greenhouse gas (GHG) emissions, and improve [national capacity] to adapt to, and cope with, the risks posed by climate change’.²⁹ Through investments in green hydrogen projects that leverage on, and repurpose existing natural gas infrastructure, MENA countries now aim to be at the forefront of the low-carbon hydrogen revolution.³⁰ Increased production and use of green hydrogen as a sustainable and low-carbon fuel can reduce the volume of GHG emissions in the region, while also advancing the availability, accessibility, and reliability of energy for the region’s growing population.³¹ This will go a long way in advancing the realization of the United Nations Sustainable Development Goals (SDGs) across the region, particularly SDG 13 on climate change and ‘SDG 7 on clean stable, and affordable energy for all by the year 2030’.³²

A fourth key driver of the hydrogen revolution in the MENA region is the effort by gas-rich MENA countries to leverage their comparative advantages as hubs for blue and green hydrogen projects. The global momentum to transition to a hydrogen economy is projected to increase demand for natural gas, a transition fuel needed to drive the hydrogen revolution.³³ With significant deposits of natural gas, great sunshine intensity for solar-powered green hydrogen projects, and significant experience in infrastructure repurposing, MENA countries have elaborated plans to become the new hydrogen superpowers.³⁴ Oman and United Arab Emirates (UAE) have released National Hydrogen roadmaps and strategies, while such strategies are already under development in Morocco and Saudi Arabia, amongst other MENA countries.³⁵ For example, the UAE’s Hydrogen Leadership Roadmap specifically aims to capture 25 percent of the global hydrogen market by leveraging the country’s solar potential to attract investments in green hydrogen, while also pursuing investment plans in blue hydrogen projects.³⁶

Given these main drivers, the appetite for hydrogen investments across the MENA region is currently very high and could remain so for the next decade. However, to ensure that hydrogen investments proceed in a safe, orderly, and sustainable manner, there is a need for a comprehensive legal framework on hydrogen that elaborates upon health, safety, and design standards for hydrogen infrastructure. Section 6.3 develops a profile of key legal issues and gaps in the design and implementation of hydrogen projects across the MENA region that must be addressed to support the safe, orderly, and sustainable transition to a hydrogen economy in the region.

6.3 Advancing a Hydrogen Economy in the MENA Region: Survey of Legal Barriers and Limitations

As can be seen in jurisdictions such as France, Sweden, Finland, Denmark, and Germany, where significant progress has been recorded in the transition to a hydrogen economy, investments in hydrogen infrastructure and technologies must be backed by a clear and transparent legislative framework, including licensing and permitting processes and standards for hydrogen production, storage, commercialization, and export. Governments should design financial incentives to encourage the development of hydrogen projects and to offset the higher capital expenditures and operating costs associated with both investing in and utilizing hydrogen technologies, particularly as compared to conventional means.

There is an urgent need for MENA countries to put in place robust and coherent law and governance frameworks to support the ambitious hydrogen economy goals. This section discusses legal barriers that must be promptly addressed if current national and regional goals to develop hydrogen production across the MENA region are to come to pass.

6.3.1 Unclear Legal Framework

One of the most important barriers to achieving the hydrogen economy visions of MENA countries is the absence of a clear and coherent legal framework on hydrogen. While there are several natural resource laws that may, directly or indirectly, apply to hydrogen projects in these jurisdictions, specific legislation or guidelines on the development, production, and commercialization of hydrogen has yet to come to fruition. For example, in the UAE, hydrogen investment may implicate the nation’s oldest laws (numbers 4 and 7 from 1971 and 1976, respectively)³⁷ which formed the Abu Dhabi National Oil Company and granted it certain exclusive control of the energy sector. While such existing laws provide a general legal framework that can guide investments in hydrogen technology, they do not adequately address specific requirements and questions on the functioning of a hydrogen market, as well as export of hydrogen for cross-border trade. Under a strict reading of the UAE law, it is unclear how it would support or regulate the development, licensing, and implementation of new energy technologies such as green and blue hydrogen (with both conventional and renewable power source utilization).³⁸

In addition to providing clarifications on what exactly is defined as green, gray, or blue hydrogen under the relevant laws of countries in the MENA region, a clear legal framework is required to clarify the standards to be complied with for the safe and reliable development and operation of hydrogen infrastructure and networks.³⁹ There are three relevant observations to be made. First, a clear regulatory framework should establish a licensing framework that will ensure the safe, orderly, and sustainable development of hydrogen. Second, given the need to attract foreign investment and technologies required to drive hydrogen expansion across the region, there is a necessity to integrate performance standards and financial incentives to increase the demand for hydrogen across the region, as well as the investments to meet such demand. Third, the integration of a significant amount of hydrogen into power grids requires substantial transformations of existing electricity laws to ensure coherence and remove barriers to achieving grid integration, balancing, storage, interconnection, and regional grid connection.⁴⁰ EU countries are also introducing sustainability and certification standards to ensure that the entire value chain of the production and distribution of hydrogen, including procurement practices, comply with all applicable laws, including ethical sourcing and respect for human rights.⁴¹ With increased emphasis across the world on business and human rights, as well as environment, social, and governance (ESG) risks in the energy sector, investors in hydrogen projects will seek clear legislative guidance to properly anticipate and mitigate legal, financial, and reputational risks associated with hydrogen projects.⁴² A selected review of some among those considerations are also treated within Chapter 10, ‘Sustainability Criteria for Renewable Hydrogen’. The adoption of clear and specific hydrogen laws and regulations could provide robust and tailor-made requirements to guide the industry going forward.

6.3.2 Barriers to Private Sector Participation

A key objective of the emerging hydrogen strategies across the MENA region is to promote participation of the private sector in hydrogen investments and projects.⁴³ The partnership approach adopted by several of the mentioned hydrogen development plans show the increased realization that government alone may not be able to meet the financial and technical requirements needed to finance, develop, and maintain capital-intensive energy infrastructure.⁴⁴ Despite this recognition, however, many MENA countries have yet to enact public–private partnership (P3) laws that set out ‘the requirements and process[es] for developing, financing and implementing P3 projects’.⁴⁵ Hydrogen presents an excellent opportunity to do so. Currently only Egypt, Jordan, Abu Dhabi, Oman, Qatar, Kingdom of Saudi Arabia, Kuwait, and Dubai have implemented P3 legislation and many of these are recent developments, which means their overall impact in terms of enhancing private investments in infrastructure projects is yet to be fully tested. As a matter of comparison: in the United States of America more than thirty P3 laws have been enacted at the state and federal levels,⁴⁶ whereas Dubai’s first P3 law was only enacted in 2015.⁴⁷ Even in those Middle East jurisdictions that have enacted P3 laws, ‘poorly functioning legal structures (including contract enforceability and governance), poor regulatory frameworks, [and] lack of standardized contracts’ are some of the impediments to effective deployment of P3s, according to recent research.⁴⁸

Additional barriers for the deployment of P3 include blurry apportionments between the interests of private parties and the government, which are common problems with investments in the Middle East and other jurisdictions. Direct or indirect state ownership and control of many of the private sector’s most influential actors is common. Contracts in the Middle East, therefore, often lack a precise risk allocation between a [P3’s] public and private sector parties, while also saddling operators with the burden of incompetency of the national institutions that promote P3.⁴⁹ The economics behind P3 is that the private sector participants stand to achieve material benefits in the event of project success, but are often left to face unclear permitting and approvals processes, resulting in delays while awaiting regulatory clarity, and, when things go wrong, an uncertain limbo until backstops from state coffers can be actionable. This was the case, for example, with the landmark default, restructuring, and recapitalization of Dubai Ports World that began in 2009 and was not functionally complete until 2020.⁵⁰ As this procedure, which saw a publicly traded company at the center of a major logistic initiative with tacit government backing file for bankruptcy, demonstrated: ‘[i]n the absence of a clear institutional and legal framework for the promotion of P3 investments’, wide-scale development of hydrogen projects may face longer-term structural challenges.⁵¹

6.3.3 Unclear Pricing and Financing Framework

Another key implementation gap is the lack of clarity on the pricing and financing framework for hydrogen in the MENA region. Unlike other hydrocarbons markets where prices are, to a large extent, set by global and local supply and demand, with broad presumptive fungibility between similar energy carriers, hydrogen is a unique commodity. Without the infrastructure to support its distribution and combustion, regardless of its production costs, hydrogen is – due to the limited outlets for consumption via fuel cell vehicles (FCVs) or in specialized power-generative and as yet comparatively narrow swath of industrial applications – a zero-value commodity, except for where it can be utilized. The vagaries of hydrogen pricing are also evident in the wide range of prices throughout the globe: Japan: ~$10 per kilogram;⁵² Europe: ~$20 per kilogram;⁵³ and North America: ~$7 per kilogram.⁵⁴

Yet it is not fair to compare geographic pricing in a vacuum without a commensurate assessment of demand stability and supply growth, particularly with the advent of hydrogen ‘clusters’⁵⁵ such as in Japan,⁵⁶ which boasts an expansive hydrogen mobility infrastructure worldwide.⁵⁷ Not only did Japan introduce a comprehensive Strategic Roadmap for Hydrogen and Fuel Cells in 2011, it also released a national Basic Hydrogen Strategy in 2017, a ‘Green Growth Strategy through Achieving Carbon Neutrality in 2050’, which was announced in 2020, and the 6th Strategic Energy Plan released in 2021.⁵⁸ These documents clarify the framework for the development and pricing of hydrogen in the country. Japan has taken, in a sense, a dual-track approach to pricing hydrogen at a level that can induce marginal supply with compelling producer economics while also stoking demand by getting consumers accustomed to using the fuel in everyday life at an affordable price. At present, this approach requires a number of subsidies.⁵⁹ As a consequence, raw hydrogen prices cannot, strictly speaking, be compared in an apples-to-apples fashion and must be taken in the context of other associated economics, including FCV rebates, hydrogen producer incentives, carbon credit frameworks, and other energy costs associated with the creation and distribution of the fuel.

The multifaceted nature of hydrogen economics has meant that the general ambition of sovereign state sponsors of hydrogen tends toward stable but gradually declining hydrogen pricing over time. By construction, such a scheme serves as an impetus for immediate investment in the sector given the implied higher future rates of return necessary to compensate for the incremental risks of allocating capital to a new energy carrier in the grids.

To provide a comparison, the US Department of Energy launched the Hydrogen Shot program in June 2021 with a goal of reducing green hydrogen costs by roughly 80 percent, to $1 per kilogram, within a decade.⁶⁰ ‘The Hydrogen Shot establishes a framework … for clean hydrogen deployment’, including the outfit of several dedicated offices and a total of approximately $400 million in financial year 2022.⁶¹ Astonishingly, commitments to back hydrogen infrastructure within the recently enacted Inflation Reduction Act are nearly 100 times this amount,⁶² attesting to the degree of priority attached to this energy source. Similarly, Japan has stated its ambition to reduce hydrogen pricing from the current level of 1,100 yen (~$100 per kilogram) to as little as 330 yen by 2030,⁶³ with billions in incremental funding to support cost reductions and further roll-out of the country’s orthodox cluster-based system.⁶⁴

Theoretically, notwithstanding the preemptive first-mover advantages enjoyed by the United States and Japan, MENA countries should be among ‘the cheapest producers of hydrogen in the world, second only to Australia in markets assessed by Platts’,⁶⁵ which makes a compelling case for a future MENA hydrogen hub. When it comes to the MENA region, moreover, hydrogen is likely to be a truly carbon-neutral proposition given that current expected cost prices for green hydrogen may underpin commercial competitiveness with the expected primacy of gray or blue fuel.⁶⁶ Bargain-priced renewable power has, in a sense, rendered the cost of both electrolysis and desalinization sufficiently marginal that the alternative of stripping hydrogen from fossil fuels and offsetting (or capturing) the embedded carbon emissions is not necessarily demonstrably advantageous on a carbon-equivalent basis.⁶⁷

Hence, the MENA region starts with better enabling conditions than other regions (such as Europe) for hydrogen, but it will still need to establish appropriate pricing frameworks that can mitigate risks associated with the high and uncertain costs of entering fixed-price supply contracts essential for attracting long-term competitive financing. Such mitigation will entail government support in the form of subsidies, grants, or preferential financing, as well as duly structured power-purchase agreements and access to clean water, even with low input costs to production, courtesy of some of the world’s most competitive renewables and large reserves of surplus hydrocarbons.⁶⁸ If a private sector appetite to provide financing via green bonds or other more innovative mechanisms such as securitization of future carbon credits⁶⁹ materializes, the need for state support may be reduced commensurately. One can imagine any number of enhanced mobility schemes in which fresh hydrogen demand is spurred via well-constructed P3 to mimic programs from the United States or Japan. The MENA region, especially the Gulf Cooperation Council, has shown that it can leapfrog rapidly in terms of technological progress and the rapid adoption of innovations (including but not limited to mobile device coverage, flying cars, or high-speed intranational transport⁷⁰) to create a cycle of hydrogen investment, production, and consumption for decades to come. To achieve this ambitious goal, clear and comprehensive legal frameworks that elaborate the pricing and financing framework for hydrogen, ranging from deliberate P3 programs to coherent incentive schemes and accommodative application of competition law, amongst other factors, would be essential to unlock a hydrogen economy in the region.

6.3.4 Institutional Gaps

‘The absence of [a] legally recognized national authority for [hydrogen regulation], coupled with the lack of coordination amongst existing government institutions and ministries, remains one of the serious institutional challenges [undermining] the successful implementation of [hydrogen] projects in the [MENA] region.’⁷¹ Despite the ambitious aims to transition to hydrogen economies, several MENA countries currently lack the dedicated institutional mechanisms to track the production, consumption, and sale of hydrogen.⁷²

Oman is one of the few countries in the region to have, in 2022, established a focal agency on hydrogen, the Hydrogen Oman (HYDROM), specifically to lead the country’s green hydrogen strategy.⁷³ HYDROM’s mandate includes the supervision of land allocation and licensing and structuring of associated large-scale, world-class green hydrogen projects in Oman.⁷⁴ While Oman’s example is expected to guide other MENA countries to put in place similar tailored institutional and governance structures to guide the coherent development of hydrogen projects, institutional development in this regard remains scarce. In addition to facilitating the coherent development and implementation of a country’s hydrogen strategy, a focal agency in countries of the MENA region will also play key roles in ‘serving as a one-stop shop’ that streamlines and simplifies the licensing processes for projects, including ensuring land access and promoting data collection to ensure that hydrogen production is accounted for in official statistics on energy production and consumption in a country.⁷⁵ Similarly, a focal agency can help to promote coordination and create synergies ‘between all government institutions, both new and old, to fast track and simplify the implementation of’ hydrogen infrastructure projects.⁷⁶

The progress made in hydrogen infrastructure development in France, Germany, and Denmark, amongst others, is due largely to the existence of regulatory bodies and industry institutions, both old and new, to guide and monitor the development of hydrogen projects. For example, German energy regulator the Bundesnetzagentur is now in charge of hydrogen infrastructure, while France in 2021 established a National Hydrogen Council (Conseil National de l’hydrogène) to monitor hydrogen development projects and policies. The French association for hydrogen and fuel cells (France Hydrogène, previously Afhypac) also plays a key role in promoting the sharing of knowledge and best practices amongst private sector operators and investors on hydrogen development. Similarly, in 2020 Germany also established the National Hydrogen Council (Nationaler Wasserstoffrat), a multidisciplinary body made up of experts in science, business, and law to facilitate the coherent implementation of the country’s National Hydrogen Strategy.⁷⁷ In addition to promoting public awareness about hydrogen projects, such focal expert bodies, agencies, or councils can play key roles in providing clarifications and guidelines to investors when proposing and developing hydrogen infrastructure projects in order to ensure that such projects ‘are in line with the country’s national vision[s]’.⁷⁸ This ‘can result in real, measurable and long-term [environmental and socio-economic] benefits’.⁷⁹ The lack of clear and coordinated governance structures in several MENA countries is a key barrier that must be addressed if hydrogen development and commercialization is to proceed in a safe, orderly, and coherent manner.

The gaps and barriers in ongoing efforts to transition to hydrogen economies in the MENA region must be addressed through holistic law and governance systems. Section 6.4 now discusses legal pathways for addressing those challenges.

6.4 Improving Law and Governance Frameworks on Hydrogen in the MENA Region

While setting national strategies and targets for hydrogen development reflects the political commitment towards a progressive transition to a hydrogen economy, the next step would be for national authorities across the MENA region to develop a ‘comprehensive and holistic legal framework’.⁸⁰ That framework should support and govern ongoing hydrogen projects while also attracting new ones. In the following, four recommendations to that effect will be made.

First, for hydrogen to play a substantial role in the future blend of energy consumption in the region – for mobility, consumer living, or industry – it must be viable for both investors and consumers. The cost dynamics of today’s hydrogen markets mean that everything from fuel distribution stations to hydrogen fuel cells in cars to public sector implementation of systems capable of integrating hydrogen use are not, at a baseline, financially viable. Thus, a starting point is for MENA countries to put in place clear, tailored, and comprehensive laws to streamline and incentivize large-scale investments in hydrogen projects.

Current natural resource laws should also be expanded to establish clear guidelines that specifically mention and cover hydrogen. Such laws should also clarify questions relating to permitting, licensing, and pricing and include mandatory performance standards, especially amongst state-owned entities to integrate hydrogen into their energy mix. Such a requirement will increase demand for hydrogen, which will then further boost investor confidence and stimulate a competitive and attractive investment climate for hydrogen projects.

Second, building that competitive environment will require a wide range of legislative reforms aimed at streamlining market access requirements, while promoting private sector participation in hydrogen projects. To streamline market access, MENA countries will need to expand the use of tax-free or special economic zones to allow for streamlined registration and formation of dedicated operational entities to import and deploy the energy carrier, related equipment, hardware, and capital necessary to build the desired hydrogen infrastructure. Exempting hydrogen projects from stipulations on the involvement of minimum percentages of local partners and/or domestic content requirements can also enhance market upscaling. Moreover, it is necessary to enact P3-specific laws⁸¹ or, if already enacted, to ensure that the local compliance regulations are structured to maintain the interest of international investors in pursuing projects in the MENA region. For example, P3 laws should include transparency measures to help with due diligence and equitable risk allocation so that the private sector does not have to carry all the risks associated with projects and to ensure that the finite delineation of responsibility between investor and state sponsor is clear.

Third, to promote the coherent development of hydrogen ‘projects, it is important to establish a focal institution or administrative unit that will coordinate the design, approval, and implementation of such projects’, including setting clear roles for different administrative entities.⁸² Depending on the specific situation of each MENA country, such an institutional framework can be in the form of expanding the mandates and budgets of existing energy agencies to enable them to regulate and monitor hydrogen investments and development or of establishing new and dedicated agencies on hydrogen. ‘Apart from serving as a one-stop shop that will streamline the approval processes for projects, such an institution would also provide capacity development opportunities for administrators to acquire technical knowledge about the methods, requirements, and challenges of’ the hydrogen value chain.⁸³ ‘By empowering and establishing a focal institution on’ hydrogen projects, a country can develop a systemic understanding, including statistical data analysis and gathering of the contributions of hydrogen to the energy mix and ways to further enhance hydrogen development and commercialization.⁸⁴

Fourth, regional collaboration and knowledge sharing between countries with experience and expertise on hydrogen can help to promote the adoption of hydrogen development and its efficiency across the Middle East. While countries such as Oman, the UAE, Saudi Arabia, and Morocco have some experience with hydrogen projects, ‘several other countries within the [MENA region] have little to no experience at all’.⁸⁵

It is therefore important to promote cooperation and knowledge sharing between regional networks and institutions, within and outside of the [region], on [hydrogen], low-carbon transition, and on how P3 models can help facilitate [hydrogen] development and integration. Regional centres and platforms can also enhance the exchange of ideas, best practices, and knowledge on existing [hydrogen] project opportunities, model contracts, and practical steps for planning and implementing [hydrogen] projects.⁸⁶

In Europe, the European Clean Hydrogen Alliance, founded in 2020, is part of EU efforts to accelerate the decarbonization and ‘support[s] the large-scale deployment of clean hydrogen technologies … by bringing together renewable and low-carbon hydrogen production, demand in industry, mobility and other sectors, and hydrogen transmission and distribution’.⁸⁷ The MENA Hydrogen Alliance is already filling a gap in this respect, although current membership is not very widespread across the region.⁸⁸ There is a need for more active engagement of the Arab League, national authorities, regulators, and research institutions across the region in this and other regional bodies that can strengthen knowledge sharing on hydrogen development. Finally, more active participation and engagement by policymakers in knowledge-sharing platforms can accelerate region-wide deployment of clean hydrogen technologies.

6.5 Conclusion

Endowed with conventional and renewable energy sources needed to drive the large-scale production and commercialization of green and blue hydrogen, MENA countries have increasingly announced strategic investments and plans to become hydrogen superpowers over the next decade. The wide-scale deployment of hydrogen can provide viable opportunities for countries in the region to diversify their economies, become less oil dependent, lower their carbon emissions, and generate a greater share of domestic energy from clean sources.

However, lack of regulatory clarity on the standards, certifications, and incentives to drive hydrogen production, especially to stimulate required hydrogen grid integration, distribution, and storage infrastructure in the region, is exacerbated by the absence of robust institutional frameworks to streamline and supervise hydrogen projects. Legal barriers that stifle the development of a coherent hydrogen market must be addressed to advance the comprehensive implementation of hydrogen visions and targets across the region.

To do so, there is a need for a robust regulatory framework that not only introduces transparency and certainty to the hydrogen market but also promotes and supports sustained P3 investments. Regulatory coherence and clarity can boost investor confidence on the economics of hydrogen, in terms of both profitability and long-term sustainability value. Promoting such clarity requires equilibrating risk-adjusted returns for hydrogen through focused incentives, guaranteed pricing frameworks, and, critically, a feed-in-tariff system, to offset the higher costs associated with producing energy from hydrogen or tax credits. The regional sharing of expertise, knowledge, and best practices could also provide an effective platform for MENA countries to identify unique challenges for hydrogen development in the region.

7 Hydrogen Regulation in Southeast Asia Steam Reforming from Biofuels as an Alternative to Electrolysis?

Piti Eiamchamroonlarp

7.1 Introduction

The ASEAN Center for Energy (ACE) highlights the potential for hydrogen to serve as an energy storage medium for intermittent renewable generation, especially from solar and wind energy.¹ It acknowledges the potential role of hydrogen, especially the contribution of hydrogen produced from biofuels from food crops, as an alternative to fossil fuel imports.² This chapter explains that, in spite of an absence of special legislation and regulations on hydrogen production, Association of Southeast Asian Nations (ASEAN) countries can rely on existing regulatory frameworks, especially manufacturing or industrial works and environmental protection regulatory regimes, for the regulation of the establishment and operation of hydrogen production plants. It uses Thailand as a case study to make a bigger point about regulatory techniques on hydrogen production in ASEAN countries, arguing that the current regulatory frameworks on energy production, for example, the one based on the Energy Industry Act BE 2550 (2007) (the Energy Industry Act), are too general in nature and incapable of sufficiently regulating production of green hydrogen.

This chapter starts by addressing the extent to which international climate policies have an impact on ASEAN countries’ regulatory frameworks on energy production as well as manufacturing activities and environmental protection, followed by an overview of hydrogen utilisation plans in ASEAN countries. Section 7.3 analyses how the current Thai government is incorporating hydrogen production activities into the general energy production framework, due to a lack of comprehensive or special hydrogen legislation. Section 7.4 looks at how electricity procurement procedures under the Energy Industry Act can allow unintentional subsidisation of grey electricity that was formerly only thought to be available for the generation of green and blue hydrogen. The chapter concludes with some observations on the potential of hydrogen in ASEAN countries considering the current lack of regulation and an outlook on future activities.

7.2 The Technicalities of Steam Reforming from Biofuels and ASEAN’s Laws and Policies on Hydrogen

Typically, green hydrogen is produced by water electrolysis,³ but few people are aware that it is also possible to use chemical processes such as steam methane reforming (SMR) for the production of green hydrogen. This is a process involving the endothermic conversion of methane and water vapour into hydrogen and carbon monoxide.⁴ SMR is a process by which natural gas or methane reacts with steam in the presence of a catalyst to produce hydrogen and carbon dioxide.⁵ Technically speaking, a catalyser such as nickel is used to facilitate the thermochemical reaction of feedstocks such as natural gas and liquid petroleum gas to heat water to a temperature of around 850 °C and a pressure of 2.5 megapascal.⁶ The methane found in natural gas reacts with steam to produce a syngas consisting of hydrogen and carbon monoxide.⁷

Depending on the fuels or energy carriers used for its generation, hydrogen produced via steam reforming itself can be categorised by colour. If it involves high greenhouse gas emissions, hydrogen produced by steam reforming of methane/natural gas is categorised as grey hydrogen.⁸ Blue hydrogen is a more environmentally friendly choice – it is produced through steam methane reforming of natural gas or coal gasification, but with carbon dioxide capture and storage.⁹ In any case, green and blue hydrogen are considered low-carbon hydrogen in Asia.¹⁰ Alternatively, hydrogen may also be produced from biogas via steam reforming, and this chapter will now discuss if this can be considered green hydrogen.¹¹

The exciting twist that ASEAN countries can bring to the table is to use biofuels to produce low-carbon hydrogen. Biofuels are defined by the Food and Agriculture Organization of the United Nations (FAO) as fuel produced directly or indirectly from biomass.¹² First-generation biofuels can be derived from agricultural crops grown for food and animal feed, including grains, starches, oil crops, sugarcane, sweet sorghum and non-food plants such as jatropha and pongamia pinnata.¹³ Second-generation biofuels can also be produced from agricultural residue or from dedicated ‘energy crops’ such as grasses and fast-growing trees.¹⁴ Organic waste, animal manure and sewage sludge can be used in anaerobic digestion to produce what is considered in ASEAN countries to be gaseous biofuels.¹⁵ Third-generation biofuels are produced from feedstock with better sustainability properties than second-generation biofuels, especially biodiesel produced from microalgae.¹⁶

Given the current and potential availability of biofuels, hydrogen produced from biofuels can serve as reliable inputs for the ASEAN countries’ need for low-carbon hydrogen. ACE and the International Renewable Energy Agency (IRENA) emphasised the potential roles of low-carbon hydrogen in industry sectors such as iron and steel, aluminium, chemicals and international bunkering for shipping.¹⁷ Later, ACE published the ASEAN Biofuel Research and Development Roadmap, highlighting that ASEAN countries boast immense agricultural goods that offer promising feedstock sources for biofuel production, such as sugar cane, crude palm oil and cassava.¹⁸

Biomass is defined by the FAO as material of biological origin excluding material embedded in geological formations and transformed into fossil form, for example, herbaceous biomass, fruit biomass and woody biomass.¹⁹ Biomass can be converted into biofuels, as discussed earlier. Classification of biofuels is based on their state (at room temperature) and includes the following: (a) gaseous biofuels, like biogas from different sources and syngas (coal gas); (b) liquid biofuels, including biodiesel, bioethanol, vegetable oil and bio-oil; and (c) solid biofuels such as wood, biomass briquettes, sawdust and charcoal.²⁰

Examples of different applications of hydrogen production are present in ASEAN countries. These countries recognised biomass as a renewable source of energy and its potential use as feedstock for hydrogen production in the ASEAN Strategy on Sustainable Biomass Energy for Agriculture Communities and Rural Development in 2020–2030.²¹ With the exception of Singapore, most ASEAN countries are strong agricultural countries.²² Agricultural products such as rubber, acacia and eucalyptus as well as waste products from production such as palm oil mill effluent (POME), cassava pulp, sugarcane molasses, cassava roots and starch are highlighted as potential feedstocks and as biomass energy resources in Indonesia, Thailand, Vietnam, Malaysia and Myanmar.²³ With the widespread presence of available biomass resources, ASEAN countries can rely in particular on the gasification process to produce hydrogen.

By extracting oil from oil palms, biodiesel and glycerol can be produced.²⁴ The produced glycerol can undergo a steam reforming process to produce hydrogen.²⁵ Biomass residue from rice paddies and the rice itself can undergo a gasification process to be converted into a combustible gas that consists of carbon monoxide, carbon dioxide, hydrogen and methane.²⁶ Biomass can also be used in the metabolic processes of microorganisms to produce green hydrogen, which is of particular relevance in Malaysia, for instance, as will be discussed further below.²⁷

Given the technical nature of hydrogen production processes, this gives rise to a legal question: how effective is a given regulatory framework in regulating the establishment and operation of such hydrogen production activities? This will now be answered by describing the main colours of hydrogen and the respective regulations thereof in selected ASEAN countries.

7.2.1 Grey Hydrogen: Abundant Fossil Fuels

ASEAN countries are blessed with fossil fuel resources and, at the current production rate, can continue producing coal for another half a century.²⁸ To give an example: coal is defined as an ‘industrial mineral’ by the Myanmar Mines Law (1994).²⁹ A person desiring to commercially produce coal must obtain a permit from the Ministry of Mines.³⁰ A coal production permit holder is obligated to, inter alia, comply with conditions specified in the permit, pay the royalty³¹ and other fees to the Myanmar government,³² and make provisions for safety and the prevention of accidents in the mine.³³

However, the Myanmar legal system lacks legislation to regulate the production of hydrogen from the extracted coal. The absence of hydrogen-specific regulations, however, does not mean that a hydrogen producer can freely produce hydrogen. A person desiring to use electricity generated from coal to produce grey hydrogen in Myanmar via a manufacturing process is subject to the Factories Act 1951. A manufacturing process in Myanmar is broadly defined as the creation of an article or substance with a view to its use, sale, transport, delivery or disposal.³⁴ In addition, this process also includes ‘generating power’.³⁵ The term ‘power’ refers to ‘electrical energy or any other form of energy which is mechanically generated and transmitted and is not generated by human or animal agency’.³⁶ Grey hydrogen produced from steam reforming of methane in natural gas is not considered a type of power under the Factories Act 1951 as it is not energy created by machines but thermochemical reaction of natural gas. However, the production of hydrogen from such a process can still be deemed to create an ‘article or substance with a view to its use or sale’. Consequently, a person wishing to use any premises to produce hydrogen through natural gas via SMR in Myanmar is required by the Factories Act 1951 to obtain a factory licence by submitting a written notice to the Chief Inspector.³⁷ Therefore, hydrogen production is indirectly regulated via the Factories Act 1951. Requirements include, for example, that a hydrogen production factory must be kept clean,³⁸ have adequate ventilation and be maintained at a steady temperature.³⁹

In Singapore, grey hydrogen is produced from the gasification of coal. There is also currently an absence of special hydrogen production regulation in Singapore, but this does not mean that hydrogen production is unregulated in Singapore. According to the Factories Act 1987, a factory means any premises in which, close to or within the precincts of, persons are employed in manual labour in any process for or incidental to the making of any article or part of any article.⁴⁰ Since the air separation plant, gas processing units and sulphur recovery plants can be used to produce hydrogen, these plants shall be deemed to be factories. Consequently, operators of these plants are required by the Factories Act 1987 to register them as factories.⁴¹ Regulatory requirements concerning cleanliness, overcrowding, ventilation, lighting, drainage of floors and sanitary conveniences apply.⁴²

7.2.2 Blue Hydrogen: Deployment of Carbon Capture Storage Technologies

In other parts of Southeast Asia, slightly different priorities are set with regard to hydrogen production. The example of Vietnam will be examined more closely here. According to the National Green Growth Strategy for 2021–2030, the Ministry of Industry and Trade of Vietnam, for example, shall formulate mechanisms to encourage the development of hydrogen as a fuel, in particular blue hydrogen.⁴³

Some words on the general regulatory climate in Vietnam are required before the next paragraph turns to blue hydrogen in Vietnam specifically. Similar to Myanmar, a regulatory framework on hydrogen production is absent in Vietnam. However, hydrogen production activities are governed by general regulatory rules concerning factory construction and fire prevention. A person wishing to construct a hydrogen production plant must obtain a construction permit from a competent state agency.⁴⁴ If the plant will be in an urban area, a construction permit can only be granted if an applicant can demonstrate that construction safety and environmental protection are ensured.⁴⁵ At the operational stage, a hydrogen facility, which can be deemed as a plant for producing flammable liquid or a gas station with total gas storage of at least 150 kg, is classified as an Appendix III facility and, therefore, is subject to fire safety requirements.⁴⁶ Consequently, a producer is required to use electrical equipment, spark-generating equipment, heat-generating equipment and fire sources and heat sources that comply with regulations and standards on fire prevention and fighting or regulations of the Ministry of Public Security.⁴⁷ However, it must be noted that to produce blue hydrogen, a producer must capture the emissions and permanently store them. Therefore, when it comes to blue hydrogen, a question on the permitting of carbon capture storage arises.

In other words, does carbon capture and storage (CCS) for blue hydrogen purposes require a separate permit and is it subject to any specific regulations? Comparable to Myanmar’s legal system, mineral exploration and mining activities in Vietnam require a permit that is handed out by a competent state agency.⁴⁸ Exploration and mining activities focus on exploration for and production of minerals from reservoirs,⁴⁹ and therefore no injection of captured carbon into pore space. The same finding can be applied to petroleum activities. A holder of a petroleum contract granted by competent agencies can lawfully explore for and produce petroleum from reservoirs.⁵⁰ It does not regulate activities relating to the injection of a captured carbon stream into empty petroleum reservoirs. Many environmental laws and regulations were enacted before carbon emissions became a concern.⁵¹ There are no regulations for land use and monitoring of long-term projects such as CCS.⁵² In a nutshell, the result is that the injection does not require a permit and can be used for blue hydrogen purposes (in principle) in Vietnam.

7.2.3 Green Hydrogen: Potential Roles of Biomass and Biogas

Among ASEAN countries, Thailand, Indonesia, Malaysia and the Philippines have the highest bioenergy potential.⁵³ The two major biofuels produced in ASEAN countries are biodiesel and bioethanol.⁵⁴ Indonesia’s biofuel industry mostly produces biodiesel made from palm oil.⁵⁵ In Malaysia, biodiesel products are also mainly produced from palm oil.⁵⁶ Biodiesel products in the Philippines are mostly produced from coconut oil and bioethanol from sugarcane.⁵⁷ In Malaysia, a hydrogen producer desiring to produce green hydrogen through metabolic processes of microorganisms or biogas reforming techniques is deemed to be a manufacturer under the Industrial Co-ordination Act 1975. Under this law, a manufacturer is a person who engages in making, altering, blending, ornamenting, finishing or treating any article or substance with a view to its use, sale, transport or delivery.⁵⁸ Since metabolic processes of microorganisms or biogas reforming techniques can be applied to produce hydrogen which will be used, commercially sold or transported, production of hydrogen from biomass or biogas shall be deemed to be manufacturing activities. Consequently, to lawfully produce hydrogen from biomass or biogas in Malaysia, a manufacturing licence must be obtained.⁵⁹ With a view to the occupational safety and health of workers in hydrogen production plants, a producer, as an employer, owes a duty under the Occupational Safety and Health Act 1994 to ensure the safety of a hydrogen production plant and operate it without risks to health.⁶⁰

A hydrogen producer in Indonesia is subject to the Law on Energy (Law of the Republic of Indonesia No. 30/2007 dated 10 August 2007) and the Industrial Affairs Law (Law of the Republic of Indonesia No. 5/1984). The Law on Energy allows business entities to exploit energy resources.⁶¹ Energy resources are defined as natural resources that can be utilised, both as energy sources and as energy directly.⁶² Energy resources can be used to produce energy, both directly and indirectly, through conversion or transformation processes.⁶³ A process converting or transforming biomass or biogas into hydrogen through a conveyor of energy shall be deemed energy resource exploitation. Therefore, the state can regulate hydrogen production, which is a kind of exploitation of energy resources, through the Law on Energy. For example, a hydrogen producer will become an energy business operator and is obliged to preserve and maintain the environmental sustainability function.⁶⁴

In addition, the conversion or transformation processes of biomass or biogas into hydrogen can be deemed industrial affairs under the Industrial Affairs Law. Industrial affairs refers to settings and all activities relating to industrial activities.⁶⁵ The term ‘industry’ is defined as an economic activity that involves the processing of raw materials, basic materials, semi-finished goods and/or finished goods into goods of higher value, and includes design activity and industrial engineering.⁶⁶ Biomass and biogas can serve as inputs for the SMR to produce hydrogen, which is a new product of higher value. Both biogas and hydrogen are gaseous substances and can be directly utilised as fuels for electricity generation and vehicles.⁶⁷ A question therefore arises as to why producing hydrogen from biogas can be deemed converting raw materials into goods of higher value.

Firstly, it has to be determined whether hydrogen is another kind of gaseous substance which is a byproduct of industrial processes. Like natural gas, biogas primarily consists of methane along with small amounts of carbon dioxide, hydrogen and hydrogen disulfide.⁶⁸ Biomass gasification and biogas reforming can serve as methods to produce syngas.⁶⁹ By manipulating the reforming process, the ratio of hydrogen and carbon monoxide in syngas can be optimised, and high-purity hydrogen gas can be produced.⁷⁰ Hydrogen produced from biogas is a cleaner fuel for vehicles⁷¹ and the gas turbine and fuel cell system for power generation.⁷² It can be said that the steam reforming process is a means of converting one gaseous substance into another more environmentally friendly gaseous substance.⁷³

Secondly, hydrogen will be the outcome of economic activity and can be deemed to be an industrial affair if hydrogen is a gaseous substance that has a higher value compared with biogas and biomass. Hydrogen has a higher value because of its usability and environmentally friendly qualities. Burning biogas, which primarily consists of methane, for electricity generation and combusting biogas for use in vehicles can produce carbon dioxide, thus contributing to climate change. However, biogas can be utilised to produce high-value products.⁷⁴ It can be upgraded through purification processes by removing some components such as carbon dioxide to increase its heating value or to standardise its quality to meet the requirements of gas appliances, for example, engines, boilers, fuel cells and vehicles.⁷⁵ Low-carbon hydrogen, which results from processing biogas and biomass, can be used to produce electricity that causes less environmental impact than the electricity from directly burning biogas. Given its enhanced usability and more environmentally friendly nature, hydrogen shall be deemed to have a higher value when compared with biomass and biogas that are used as inputs for hydrogen production.

When hydrogen production can be deemed an industrial affair under the Industrial Affairs Law, the state can regulate this economic activity through a licensing system. Under the Industrial Affairs Law, a person producing hydrogen from biomass or biogas must obtain an industrial business licence.⁷⁶ A hydrogen producer, being an industrial company, owes a statutory duty to prevent damage and pollution to the living environment resulting from the production processes.⁷⁷

7.2.4 Summary of Manufacturing and Environmental Permit Requirements in ASEAN Countries

To sum up, environmental protection plays an important role with regard to whether permission is given for the operation of a hydrogen production facility. However, the environmentally friendly nature of green hydrogen does not mean that its production is free from safety and environmental risks. Hydrogen is still a hazardous chemical and flammable substance.⁷⁸ This means that safety requirements are necessary for grey (and blue) hydrogen production, which can also apply for green hydrogen production. If the regulatory regime only regulates hydrogen production through gas separation operations, it will be unable to mitigate safety risks inherently associated with other hydrogen production procedures.

Thermal processes for hydrogen production typically involve steam – for example, steam reforming. If the fuel used for steam reforming is of hydrocarbon origin, such as natural gas or diesel, the hydrogen production facility will emit carbon dioxide, having a negative impact on the environment. In addition to the discussed manufacturing licence, the state can require a person who wishes to conduct activities potentially causing adverse impacts on the environment to conduct an environmental impact assessment (EIA) and submit a report thereon in ASEAN countries.⁷⁹ The requirements of the EIA report are subject to the discretion of the relevant competent national authority.⁸⁰ Environmental legislation or regulations can require a person seeking to produce hydrogen to conduct an EIA.

The particular requirements of the individual EIAs depend on the individual country. In Malaysia, a person intending to carry out any of the prescribed activities under the Environmental Quality Act 1974 shall, before any approval for the carrying out of such activity is granted by the relevant approving authority, submit a report to the Director General of Environmental Quality.⁸¹ The EIA regime in Malaysia makes no specific reference to hydrogen production; however, it categorises a ‘chemical’ factory with a total production capacity of each product or of a combined product that is equal to or greater than 100 tons per day as an activity that requires the submission of an EIA Report.⁸²

Taking these findings into account, it seems necessary to look more closely into a specific case from one of the ASEAN countries to understand the interplay of norms. The following section therefore provides a case study on how Thailand and its existing, relatively advanced, natural resources regulatory regime tackle hydrogen production.

7.3 Thailand as a Case Study

In Thailand, hydrogen is recognised as an alternative transport fuel.⁸³ In addition, the state mentions in the Power Development Plan (PDP) 2018–2037 that it will promote the establishment of biomass and biogas power plants having a combined capacity of 3,180 megawatts (MW) by 2037.⁸⁴ These goals trigger a question concerning how and to what extent Thai regulatory regimes can regulate the production of hydrogen. Regulatory requirements for hydrogen production cover at least operational safety, occupational safety and environmental safety. However, activities relating to hydrogen production in Thailand are not considered energy production under the Energy Industry Act or the Petroleum Act BE 2514 (1971) (the Petroleum Act). In the absence of specific hydrogen legislation, a hydrogen producer relying on machinery to produce hydrogen, including gasification and fermentation of biomass and the reformation of biogas, is subject to the factory licensing regime under the Factory Act BE 2535 (1992) (the Factory Act).

7.3.1 Hydrogen Production under Thai Energy Law

Unlike the Indonesian energy regulatory regime as discussed in Section 7.2.3 above, the Thai energy licensing regime does not recognise hydrogen as energy or an energy resource. The Energy Industry Act of Thailand only regulates the production of electricity.⁸⁵ Production of electricity as well as establishment of an electricity production facility are subject to a licensing requirement under the Energy Industry Act.⁸⁶ The law only limitedly applies to the production of electricity and not to the production of energy from other resources, including the conversion of biomass or biogas into green hydrogen.

Apart from producing green hydrogen from biomass and biogas, the production of grey hydrogen from natural gas via the steam reforming process is also conducted in Thailand.⁸⁷ Comparable to the situation in Myanmar, Thai energy law does not regulate the production of hydrogen from fossil fuels either. Production of natural gas is not governed by the Energy Industry Act but by the Petroleum Act. Any person seeking to explore for and produce natural gas is required to obtain a concession, production-sharing contract or service contract from the Ministry of Energy.⁸⁸ However, the law defines natural gas as ‘all kinds of gaseous hydrocarbons whether wet or dry, produced from oil or gas wells, and shall include the residue gas remaining after the extraction of liquid hydrocarbons or by-products from wet gas’.⁸⁹ Since hydrogen is not extracted from oil or natural gas wells and nor is it a by-product remaining after the extraction of liquid hydrocarbons, a hydrogen producer is not required to obtain a concession, production-sharing contract or service contract under the Petroleum Act.

7.3.2 Hydrogen Production under the Current Thai Industrial Works Regulatory Regimes

In line with Myanmar, Singapore, Vietnam, Malaysia and Indonesia, a person desiring to legally establish and operate a hydrogen production facility in Thailand, whether to produce grey, blue or green hydrogen, has the statutory duty to comply with general laws governing the establishment and operation of a factory, as well as environmental protection regulations.

Establishment of Hydrogen Production Factory

In the Factory Act, a ‘factory’ means buildings, premises or vehicles using machines with a total power output of 50 horsepower (hp) or more, or the equivalent, or which employ fifty workers or more with or without machinery to engage in the operation of a factory in accordance with the type or kind of factory as prescribed in the Ministerial Regulations.⁹⁰ These Ministerial Regulations do not specifically refer to hydrogen production but ‘gas production’.⁹¹ A plant with the capability of converting natural gas into gaseous hydrogen through the steam reforming process relying on a reactor with 50 or more hp, or the equivalent, is, therefore, deemed to be a factory. If these machines together with others that are used in a plant have 50 or more hp, or the equivalent, this plant will be deemed a factory under the Factory Act. Likewise, if machines with 50 or more hp, or the equivalent, are used in a plant for biogas reforming, whether dry reforming (DR), steam reforming (SR), catalytic partial oxidation (CPOX) or auto-thermal reforming (ATR), this plant will become a factory under the Factory Act.

The Minister of Industry has powers to categorise hydrogen production plants as a ‘group 3 factory’, which are factories of the type, kind and size that require a permit to be granted prior to creation and operation.⁹² The Minister of Industry is vested with regulatory power to enact a Ministerial Decree requiring a hydrogen producer to use particular types of machines and equipment for hydrogen production.⁹³ To ensure that a hydrogen producer, who holds a factory licence, will produce hydrogen from these second-generation biofuels, the Minister of Industry can exercise power under Section 8 para. 1(4) of the Factory Act to promulgate a Ministerial Decree requiring that hydrogen must be produced from agricultural residues.

Once regulated under the Factory Act, a hydrogen producer must adhere to the ministerial rules on production processes and provisions concerning other equipment or tools to prevent or stop or mitigate dangers that may be caused to the persons or property in the factory or its vicinity.⁹⁴ Hence, biomass gasification and biofuel reforming plants can be listed as factories that are subject to by-laws prescribing criteria relating to production processes⁹⁵ as well as standards and methods of controlling the discharge of waste, pollutants or anything affecting the environment as a result of the factory operation.⁹⁶

Occupational Safety and Health Management

A hydrogen production plant can be deemed as a working place under the Occupational Safety, Health, and Environment Act BE 2554 (2011) (the OSHE Act). The law primarily places statutory duties upon the employer to ensure the safety and hygiene of a working place for its employees.⁹⁷ In line with Malaysia, the OSHE can serve as a legal basis for the Minister of Labour to promulgate ministerial decrees imposing duties on hydrogen producers, as the employers, to manage and operate their hydrogen production plants in accordance with the prescribed occupational safety, health and environmental standards.⁹⁸

Environmental Impact Assessment

Under the Enhancement of National Environmental Quality Act BE 2535 (1992) (the Enhancement of National Environmental Quality Act), the Minister of Natural Resources and Environment is vested with the power to promulgate a ministerial notification prescribing which projects, business operations or activities require an EIA report.⁹⁹ If the establishment and operation of a hydrogen production factory is prescribed as a project, business operation or activity that requires an EIA report, the Permanent Secretary of the Ministry of Energy or a delegated official cannot grant a factory licence to the applicant unless the EIA report for the hydrogen factory is approved by the Environmental Expert Committee.¹⁰⁰

The Ministerial Notification concerning Projects, Operation or Activities that require an EIA Report and Criteria, Methods and Conditions on the EIA Report Preparation BE 2566 (2023) (the EIA Notification) does not specifically make any reference to hydrogen production. However, it imposes the EIA report requirement on industrial activities involving natural gas separation. Regardless of the size of the factory, a factory established for natural gas separation by conversion of natural gas from gaseous status into liquid status and natural gas separation by conversion of natural gas from liquid status by using seawater or water from natural water resources for heating the separation are subject to the EIA report requirement.¹⁰¹ It appears that the current environmental protection regime in Thailand places its focus on inputs used for manufacturing processes. Therefore, a person seeking to use natural gas as an input to produce hydrogen through the natural gas separation process will be required to prepare an EIA report.

The term ‘natural gas’ is not specially defined by the Enhancement of National Environmental Quality Act or its by-laws. However, natural gas is defined by the Petroleum Act as all kinds of gaseous hydrocarbons, whether wet or dry, produced from oil or gas wells; and also includes the residue gas remaining after the extraction of liquid hydrocarbons or by-products from wet gas.¹⁰² Moreover, the Ministry of Energy Notification concerning Criteria and Safety Standard of a Place where Natural Gas Is Used and Regulated by Department of Energy Business BE 2550 (2007) defines natural gas as gaseous hydrocarbon mainly consisting of methane.¹⁰³ Therefore, a person using biogas, which is a kind of natural gas, as an input to produce hydrogen will be required to prepare an EIA report. In practice, hydrogen production from natural gas is deemed a project that is subject to the EIA requirements. The Environmental Expert Committee, in its meeting No. 3/2561 of 16 July 2018, opined that the utilisation of natural gas to produce hydrogen is considered a kind of natural gas separation and transformation project.¹⁰⁴

However, the EIA Notification does not govern the utilisation of renewable sources as inputs for manufacturing or production. Production of green hydrogen does not use natural gas as an input for production, but electrolysis from renewable sources. In relation to energy projects, it only applies to a thermal power plant with an installed capacity of 10 MW and more.¹⁰⁵ Therefore, if a person is seeking to use natural gas to produce hydrogen, this is not a type of renewable source, so they are not required to submit an EIA Report.

7.4 (Re-)conversion of Electricity: Unintended Subsidisation of Electricity Generated from Grey or Blue Hydrogen

To support the energy transition, the state may create market demand for green hydrogen. In Thailand, demand for green hydrogen, such as hydrogen produced from biomass and biofuel, can be stimulated by the state through subsidisation of renewable electricity generated from green hydrogen. Hydrogen end users, such as renewable electricity producers, can be encouraged to purchase hydrogen from hydrogen producers or suppliers if the government is also allowing them to participate in subsidised electricity selling prices.¹⁰⁶ However, the Energy Industry Act of Thailand gives the Energy Regulatory Commission broad powers to procure renewable electricity generated from ‘hydrogen’ without specific reference to its colour.

7.4.1 Electricity Procurement under the Energy Industry Act BE 2550 (2007)

Thailand does not have a competitive wholesale electricity market, as the government gave a mandate to state-owned electricity enterprises to purchase electricity from producers based on the allocated quotas.¹⁰⁷ The Energy Policy Committee has the power to determine the amount of electricity that can be procured from the private sector as well as the purchase price, including the guaranteed price of electricity generated from hydrogen.

In practice, the Energy Policy Committee will instruct the Energy Regulatory Commission to take necessary steps for electricity procurement in accordance with its requests. This instruction will refer to the type of electricity to be procured, for example, electricity from renewable resources such as electricity from biomass and biogas.¹⁰⁸ This procurement announcement can invite electricity producers to sell electricity generated from renewable resources, including hydrogen, at a fixed subsidised price, thus stimulating demand for hydrogen consumption.

7.4.2 Current Practice on Procurement of Hydrogen-Based Electricity

Hydrogen that is used to fuel electricity generation can be grey, blue or green or have other colours. The current practice on electricity procurement is that the criteria that have been announced by the Energy Regulatory Commission feature hydrogen as a renewable resource that qualifies for subsidised electricity purchasing prices.¹⁰⁹ For example, in 2018 the Energy Regulatory Commission invited power producers with a generation capacity of not exceeding 10 MW to sell electricity generated from ‘renewable resources’ to the state-owned electricity enterprises.¹¹⁰ This regulation explicitly included hydrogen as a renewable resource.¹¹¹ After the competitive bidding process, a selected power producer will sign a long-term power purchase agreement that recognises subsidised electricity prices, based on the type of renewable resource. The state-owned buying enterprises will be responsible for paying the seller a fixed and subsidised wholesale price as announced by the Energy Regulatory Commission. This subsidy scheme is called the Feed-in Tariff (FiT) scheme.¹¹²

Notwithstanding, electricity producers are not prohibited from using grey or blue hydrogen for the generation of electricity and can nonetheless apply for subsidies from the scheme. This loophole exists because the Energy Regulatory Commission does not recognise any differences between types of hydrogen. Its regulations in the past simply featured hydrogen as automatically qualifying for the bidding process.¹¹³ Renewable electricity procurement announcements typically refer to ‘hydrogen’ as a kind of renewable resource which is qualified to gain benefits from the price guarantee scheme without making specific reference to green hydrogen, so all kinds of hydrogen can benefit equally.

This is an undesirable and possibly unintended outcome because hydrogen produced from natural gas – grey hydrogen – relies on the fossil fuel natural gas. Its production process involves the conversion of fossil fuels into another form of energy. Therefore, hydrogen produced from fossil fuels should not be deemed a renewable energy resource and the loophole needs to be closed.

7.5 Conclusion

In Southeast Asia no common approach towards hydrogen regulation has evolved so far. ASEAN countries are mainly at the initial stages of hydrogen production and there is currently little utilisation of hydrogen. However, in the absence of such legislation in Myanmar, Singapore, Vietnam, Malaysia and Indonesia, a hydrogen producer does not necessarily have full freedom to produce hydrogen without being subject to regulations. These ASEAN countries can rely on factory or industrial affairs legislation to impose a duty upon a hydrogen producer to obtain a factory or manufacturing activity licence before operating a hydrogen production plant. These regulations mainly focus on ensuring the safety of the factory establishment and operation and do not always specify how hydrogen is produced.

The existing environmental impact assessment requirements in Malaysia and Thailand can serve as regulatory bases to require certain types of hydrogen production plants, including biomass gasification and biogas steam reforming plants, to be activities that need to conduct an EIA prior to their operation. Like most other ASEAN countries, except Indonesia, activities relating to hydrogen production in Thailand are not deemed to be energy production under the Energy Industry Act or under the Petroleum Act.

However, a hydrogen producer relying on machines to produce hydrogen, including the gasification and fermentation of biomass and the reformation of biogas, can be considered an industrial operator who is required to obtain a factory licence. Production of blue and grey hydrogen from natural gas including biogas through the SMR process is considered natural gas separation activity and needs an EIA report. Once a hydrogen producer becomes a factory licensee, the Minister of Industry can regulate how hydrogen is produced through ministerial rules concerning machines, equipment or other things used for engagement in a factory business. On the grounds of avoidance of conflict between food security and energy security, the Factory Act can be utilised by the Minister of Industry to require a hydrogen producer, who is a holder of a factory licence, to produce hydrogen from these second-generation biofuels.

The Thai government could stimulate demand for electricity produced from biogas. The stimulated demand for biogas as inputs for electricity to be purchased by the state at a subsidised price could contribute to the formulation and development of hydrogen markets in Thailand. The problem arises of possible diversion of subsidies that are intended to promote green hydrogen and electricity produced from green sources. In spite of the ability to regulate safety and mitigate environmental impacts, the Thai legal system faces challenges arising from unintentionally subsidising grey or blue hydrogen through electricity procurement legislation. This is an issue because the Energy Industry Act of Thailand gives the Energy Regulatory Commission broad powers to procure renewable electricity generated from ‘hydrogen’ without specific reference to its colour. This loophole demonstrates a general issue with the current stage of hydrogen regulation in ASEAN countries: the existing regulations have not been created with hydrogen in mind and if they are amended there can be a lack of technical understanding that could lead to unintended side effects. It therefore remains a challenge for ASEAN countries in the coming years to improve their regulatory approaches towards hydrogen and to better incorporate it into their existing regulatory landscape.