Hydrogen in the Energy Transition
In this cover the basics article, we answer some frequently asked questions about hydrogen and we explore how it contributes to the energy transition.
Achieving the ambitions of the EU Green Deal will require innovation and diversification across several key areas. One tool which is believed by many to be useful in addressing tricky decarbonisation issues in multiple sectors is clean hydrogen.
In this article, we aim to map the contemporary hydrogen landscape by responding to five common questions. What is hydrogen? What are the current and potential uses of hydrogen? How is it produced? What do hydrogen supply chains look like? Which strategies and laws are aimed at supporting a clean hydrogen economy in the EU?
What is hydrogen?
Confusingly, we can talk about hydrogen in both its atomic and molecular forms. The hydrogen atom is by a huge margin the most common atom in the known universe, making up roughly three-quarters of its mass. However, hydrogen in molecular form, ‘H2,’ i.e. two hydrogen atoms bonded together, is scarce and on earth is only found in combination with other atoms, like oxygen in the case of water or carbon in the case of methane.
Hydrogen molecules are the focus of this section. At room temperature, hydrogen molecules are an odourless colourless gas with the lowest density of any gas. As we cannot directly extract gaseous hydrogen as we can with some other energy vectors, we must liberate it from other products such as methane, water, coal and biomass. This can be done through a variety of processes, which we will explore later.
What current and potential uses are there for hydrogen?
More than 90% of the existing demand for hydrogen in the EU is related to industrial processes, in which hydrogen is a feedstock and a reductant.
- Removing impurities during the crude oil refining process (the main one being sulphur) (~50% of total).
- Chemical plants use hydrogen as a feedstock (i.e. raw material) to produce a wide variety of products including ammonia (NH3), methanol (CH3OH), fertilisers, household products and industrial solvents (~40%).
- Steel production from direct reduced iron (DRI) and other industrial uses, e.g., a blanketing gas and a coolant (~5%).
- Other (~5%)
In a decarbonised future we can imagine that demand for crude oil will drop considerably, reducing the demand for hydrogen in this sector, which is the biggest current consumer. What remains of current fossil hydrogen demand will need to be replaced with more sustainably produced hydrogen. However, in recent years hydrogen has also caught the attention of other sectors, most notably in applications as an energy vector. These uses remain very marginal in the EU today, constituting ~0.7 million tonnes (Mt) of the 8.4 Mt (IRENA, 2021) overall demand, with virtually all of this being of fossil origin. However, according to the International Renewable Energy Agency (IRENA, 2021) by 2050 hydrogen could represent as much as 12% of final global energy consumption.
Four categories of energy sector applications for hydrogen moving forward (EP, 2021):
- Buildings (e.g. space heating, water heating, cooking);
- Industry (e.g. high-temperature steam in the glass and cement industries);
- Mobility (e.g. for heavy-duty vehicles, derivatives for aviation);
- Electricity generation and grid balancing (e.g. seasonal storage of electricity – stored as hydrogen – and electricity generation during peak loads from hydrogen-based gas turbines or fuel cells).
How is hydrogen produced?
Currently, hydrogen is produced either at dedicated production facilities or as a by-product of other production processes, such as chlorine production. According to the IEA (2019), ~60% of global hydrogen production is at dedicated facilities, with the remainder coming as a by-product. Virtually all dedicated global hydrogen is of fossil origin, and other chemical processes that produce hydrogen as a by-product are also typically quite energy intensive.
Here we explore how hydrogen is produced and how it can be made more sustainable (Figure 2).
- Black – produced by gasification of ‘black’ coal.
- Brown – produced by gasification of ‘brown’ coal.
- Grey – produced by thermochemical conversion of fossil gas, either Auto-thermal Reforming (ATR) or Steam Methane Reforming (SMR).
- Blue – produced by ATR or SMR of fossil gas, with the addition of carbon capture (use) and storage (CCUS).
- Turquoise – produced by pyrolysis of methane (fossil or bio) driven by electricity (can be renewable) (see also Conti et al., 2021).
- Pink – produced by electrolysis of water, utilising electricity of nuclear origin.
- Green – produced via electrolysis of water, driven by renewable electricity.
- Yellow – produced by electrolysis of water, utilising grid electricity.
As a reference, in 2018 the global production of grey hydrogen for industrial feedstock uses generated around 830 Mt of CO2 emissions, 2.5% of global CO2 emissions (IEA, 2019). In the same year, clean hydrogen production was nearly zero, with projects of meaningful scale only emerging since 2021 (IEA, 2020).
It is important to keep in mind that lifecycle GHG emissions also depend on emissions associated with supply chains. For example, the GHG emissions of the natural gas supply chain can be significant and highly variable due to methane leaks in the chain. Although emissions from electricity supply chains can be negligible if the electricity is from renewable sources, there are still differences in the emissions from wind power infrastructure and solar, for example. This is one of the challenges in the certification of hydrogen.
What do hydrogen supply chains look like?
The vast majority of hydrogen currently consumed is produced at the point of consumption or nearby, typically connected via a private network. However, different forms of clean hydrogen require various conditions, such as abundant renewable electricity and suitable geological conditions for the storage of CO2. In these new value chains, there is a requirement for storage and transport infrastructure.
Hydrogen can be stored differently depending on its state (gaseous or liquid). For example, gaseous hydrogen can be stored in salt cavern storages or pressurised tanks. Geological storage is far cheaper than above-ground storage in manmade infrastructure.
There are two overarching transportation options for hydrogen, with different implications:
- Pipelines: used to transport either pure gaseous hydrogen, hydrogen blended into the methane network or hydrogen converted into a derivative, like ammonia;
- Shipping (maritime and land): either as a liquid following cooling to temperatures below -252°C, or in ammonia, methanol, or a LOHC (liquid organic hydrogen carrier).
Transport costs can greatly vary according to the volume of hydrogen demand and the distance required for it to be transported. Newly built and repurposed gas pipelines are widely believed to be the cheapest methods of transporting hydrogen under most circumstances (Agora Energiewende and AFRY, 2021; Wang et al, 2020). This is largely due to the cost of transforming hydrogen into a LOHC and the energy penalty for getting hydrogen to a low enough temperature to liquefy it (roughly 100°C lower than methane) compounded by equipment costs for handling such a cold and volatile product.
Blending relatively low volumes of hydrogen into the natural gas grid (<20%) is an option that is already available with current infrastructure, and it has been supported in the recent ‘Hydrogen and Decarbonised Gas Market Package’ (HDGMP), which we will discuss shortly. This approach has the advantage of providing immediate offtake options for producers, and potentially making a very marginal positive decarbonisation impact on the emission intensity of gas in the network. Nevertheless, the resulting gas mix will be of lower energy density than pure methane gas, create equipment interoperability issues beyond very low hydrogen volumes, be hugely energy inefficient when accounting for the energy input for hydrogen production, and will create challenges at end use, such as ‘de-blending’. This market evolution will mark a clear departure from the current configuration of gas supply chains, which almost exclusively transport pure methane or pure hydrogen (see also Dos Reis, P., 2021b).
What strategies and laws are most relevant to clean hydrogen in the EU?
As part of the European Green Deal, the European Commission’s complementary strategies ‘A hydrogen strategy for a climate-neutral Europe’ (Hydrogen Strategy) (EC, 2020a) and ‘An EU Strategy for Energy System Integration’ (ESI Strategy) (EC, 2020b) both identify ‘clean’ hydrogen and other synthetic fuels as necessary to reach decarbonisation.
The Hydrogen Strategy identifies cumulative investment needs and policies to promote the development of value chains for low-carbon and renewable hydrogen. These aims are broken down into the following three phases:
- Phase 1 (from 2020 to 2024): installation of at least 6 gigawatts (GW) of electrolyser capacity in the EU by 2024, corresponding to the production of up to 1 million tonnes of renewable hydrogen;
- Phase 2 (from 2025 to 2030): installation of at least 40 GW of electrolyser capacity in the EU by 2030, with a further 40GW installed in the neighbourhood region (Ukraine and North Africa) – corresponding to 10 million tonnes of renewable hydrogen in the EU;
- Phase 3 (from 2030 onwards and towards 2050): renewable and low-carbon hydrogen technologies should reach maturity and be deployed on a large scale.
The ‘REPowerEU’ documents released in March and May 2022 in response to the Russian invasion of Ukraine increased these targets considerably with a view to leveraging hydrogen and other clean molecules to enhance energy security (EC, 2022a, EC, 2022b). The total production and import target for renewable and low carbon hydrogen rises to 20 million tonnes by 2030, in the hope that this can replace 25-50 billion cubic metres (BCM) of Russian gas. The Communications also emphasise the need to ramp up the development of corresponding infrastructure, including storage, and promised expedited assessment and processing of hydrogen projects under the ‘Important Projects of Common European Interest’ (IPCEI) and state aid procedures.
The ESI Strategy describes the “use of renewable and low-carbon fuels, including hydrogen, for end-use applications where direct heating or electrification are not feasible, nor efficient or have higher costs” as some of the important uses of hydrogen in the context of energy system integration. Moreover, electrolysers are one of the key tools for sector coupling between renewable electricity and renewable gas networks.
The ‘Hydrogen and Decarbonised Gas Market Package’ (HGMDP) (EC, 2021a) of December 2021 was perhaps the most important development since the ESI and Hydrogen Strategies, particularly in terms of setting the incentives and market conditions for the uptake of hydrogen and other clean molecules. The HGMDP was the fourth iteration of comprehensive legislation in the sector, following most recently the ‘Third Energy Package’ in 2009.
The two major components of the publication were a proposed recast of the Regulation (EC, 2021b) on conditions for access to natural gas transmission networks (715/2009) (‘Gas Regulation’) and a proposed recast of the Directive (EC, 2021c) on common rules for the internal market for natural gas (2009/73) (‘Gas Directive’). The core aims of the updates are to (i) establish the conditions for facilitating rapid and sustained uptake of renewable and low-carbon gases, (ii) improve market conditions and increase engagement of gas consumers, (iii) better account for the contemporary security of supply concerns, (iv) address price and supply concerns at the Union level and (v) recalibrate the structure and composition of regulatory bodies.
The package covers many different issues, more complete explanations of which can be found here. However, in terms of hydrogen the package attempted to (i) define more clearly the different forms of clean hydrogen, (ii) provide incentives for the uptake of clean hydrogen, (iii) propose a specific framework for the management and planning of a clean hydrogen sector.
- Regarding definitions, Articles 2 and 8 of the proposed revision of the Gas Directive offer definitions of ‘low-carbon hydrogen’, and ‘low-carbon gases’ more widely, indicating a “greenhouse gas emission reduction threshold of 70%.” The greenhouse gas in question is not specified nor the benchmark against which the 70% reduction applies, but we can assume it refers to the unabated fossil equivalent. The Directive also refers to Article 2 of REDII for classifications of ‘renewable gas,’ ‘low-carbon gas,’ ‘low-carbon fuel’ and ‘renewable fuels of non-biological origin’ (RFNBOs). A specific methodology for calculating and defining the thresholds and conditions for renewable and low-carbon hydrogen will be defined in subsequent Delegated Acts, proposals for which were published in May 2022 (EC, 2022c, EC, 2022d).
- Concerning incentives, there is no stipulation of a mandatory offtake for industry (demand side) or a direct financing mechanism (supply side). However, renewable and low carbon hydrogen will receive a 75% discount from various entry and exit tariffs as per Article 16 of the Gas Regulation. Moreover, until 1 January 2031 tariffs will not be chargeable for transmission of these gases across interconnection points between the Member States. Tariffs at interconnection points will also not apply to the pure hydrogen network once it is established. There are also proposals to temporarily waive or adjust certain rules governing third-party access (TPA), private hydrogen networks and unbundling to help guarantee returns for investors.
- For management and planning of the network, first, an entity for European Distribution System Operators (DSOs) will be set up. Full details of the scope and role of the entity can be found in Articles 36 and 37 of the Gas Regulation. Second, a network association will be established for hydrogen network operators, ‘The European Network for Network Operators of Hydrogen’ (ENNOH). ENNOH’s tasks include writing relevant network codes and Union-wide non-binding ten-year network development plans (TYNDPs) for the hydrogen sector. Third, and remaining with the TYNDP theme, hydrogen interconnection projects will now be eligible to apply for funding if they fall within the scope of the wider TYNDPs of the European Network of Transmission System Operators (ENTSOG) provided they are not already covered in IPCEIs.
In May 2020, the European Commission’s recovery plan document ‘Europe’s moment: Repair and Prepare for the Next Generation’ (EC, 2020c) already identified hydrogen as one of the key technologies for the clean energy transition, for which investments would be reserved in the ‘Strategic Investment Facility.’ Later that year, EU leaders agreed that technologies based on ‘renewable’ and ‘low-carbon’ hydrogen and other synthetic fuels would also be one of the main potential recipients of the EU’s €750 billion recovery package.
Finally, many of the Member State National Energy and Climate Plans (NECPs) include hydrogen as a key component on the path to decarbonisation. Additionally, several EU member states have adopted national hydrogen strategies with varying perspectives on their roles in a European and global clean hydrogen economy (technology, exports, imports, etc.).
Find the full list of references here.
If you still have questions or doubts about the topic, do not hesitate to contact one of our academic experts:
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