Hydrogen use in the energy sector
Hydrogen was deemed to constitute in 2020 less than 2% of the EU total energy system, but projected to grow to circa 15% in long-term decarbonisation strategies.
19 July 2023
The provisional agreement provides that 42% of the hydrogen used in industry should come from renewable fuels of non-biological origin (RFNBOs) by 2030 and 60% by 2035.
The agreement introduces the possibility for member states to discount the contribution of RFNBOs in industry use by 20% under two conditions:
- if the member states’ national contribution to the binding overall EU target meets their expected contribution
28 March 2023
- General approach on the directive on common rules for the internal markets in renewable and natural gases and in hydrogen
- General approach on the regulation on the internal markets for renewable and natural gases and for hydroge
15 February 2023
The European Commission hydrogen strategy of 8 July 2020 ambitions at least 40 GW of renewable hydrogen electrolysers installed by 2030 in the EU plus other 40 GW in Europe’s neighbourhood with export to the EU (ACER Market Monitoring Report 2019 – Gas Wholesale Market Volume, 23 September 2020).
The same strategy makes also the following prediction as regards the electrolysers costs:
"Costs for renewable hydrogen are going down quickly. Electrolyser costs have already been reduced by 60% in the last ten years, and are expected to halve in 2030 compared to today with economies of scale. In regions where renewable electricity is cheap, electrolysers are expected to be able to compete with fossil-based hydrogen in 2030. These elements will be key drivers of the progressive development of hydrogen across the EU economy".
Some of the EU Member States have established guarantees of origin (GOs) for renewable gases. The Directive (EU) 2018/2001 of the European Parliament and of the Council of 11 December 2018 on the promotion of the use of energy from renewable sources (RED II) stipulates that the EU Member States may arrange for guarantees of origin to be issued for energy from non-renewable sources (Article 19(2) of the RED II).
According to Recital 59 of the RED II:
"Guarantees of origin which are currently in place for renewable electricity should be extended to cover renewable gas. Extending the guarantees of origin system to energy from non-renewable sources should be an option for Member States. This would provide a consistent means of proving to final customers the origin of renewable gas such as biomethane and would facilitate greater cross-border trade in such gas. It would also enable the creation of guarantees of origin for other renewable gas such as hydrogen."
However, the energy market regulators (CEER Public Consultation Paper of 22 March 2019, Regulatory Challenges for a Sustainable Gas Sector, Ref: C18-RGS-03-0, p. 19) explicitly underline “black electricity cannot be converted into green gas”. This stance is based on the RED II definition of a “renewable energy source” - decarbonised gases, e.g. hydrogen derived from natural gas through steam methane reforming or thermal methane pyrolysis, “would not be considered as renewable gas but could be included in the national GO systems as decarbonised gas, thereby making transparent to gas customers the low-carbon nature of this gas”.
The European Commission's EU Hydrogen strategy characterises low-carbon hydrogen as encompassing blue hydrogen and electricity-based hydrogen with significantly reduced full life-cycle GHG emissions compared to existing hydrogen production (European Parliament Briefing, EU hydrogen policy, Hydrogen as an energy carrier for a climate-neutral economy, February 2021, p. 3).
ACER Market Monitoring Report 2019 – Gas Wholesale Market Volume of 23 September 2020 (p. 18 - 20) refers to the following facts on the hydrogen's use in the EU as of 2019:
- production efforts have been mainly focused on biogas, which on average accounts for 15% of EU gas domestic production and 4% of EU gas consumption,
- Germany, the UK and Italy are the frontrunners in absolute terms, while the relative weight of biogas and biomethane over final gas demand varies between the EU Member States; in Sweden, Denmark and Germany, its consumption reached 10% in 2019,
- most biogas continues to be produced and consumed close to the production site, either for heating or electricity generation,
- upgraded biomethane volumes injected into the network are still low – 5% of biogas production on average – due to higher production costs, gas quality and other technical constraints, the notable exceptions are Denmark and the Netherlands, where injections exceed 15% of biogas production,
- in absolute terms, Germany is the largest biomethane producer with more than 1 bcm in 2019,
- hydrogen is an established traded commodity in its own right, primarily produced on-site and consumed in certain industrial processes, in the refinery sector and for ammonia production – where its market value is higher than for electricity generation.,
- absolute hydrogen consumption is the highest in Germany and the Netherland,
- it is estimated that 95% of EU hydrogen production in 2018 originated from steam methane reforming (without carbon capture storage - CCS) and coal gasification, while only 5% came from electrolysis (for the latter, with a limited use of RES),
- large scale methane reforming to hydrogen with CCS is moving ahead only in the UK, a key limiting factor is the availability of suitable carbon dioxide storage structures,
- in the area of electrolysis, there are quite a few pilot and small-scale plants in operation, chiefly in Germany, France and the Netherlands.
As regards the price competitiveness of the various carbon neutral gas production technologies the said ACER Report of of 23 September 2020 acknowledges that the cost of low-carbon gases was three to more than five times higher than the price of conventional gas in 2019 - therefore, together with further technological developments and RES prices, a central element for determining the future competitiveness of all decarbonised energy technologies, including carbon-neutral gases, will be the price of carbon emissions under the EU ETS system.
Network infrastructure for the transport of pure hydrogen is not covered by Gas Directive 2009/73/EC "as the natural gas system does not include pipelines or network infrastructure dedicated to the transport of pure hydrogen" (When and How to Regulate Hydrogen Networks? “European Green Deal” Regulatory White Paper series (paper #1) relevant to the European Commission’s Hydrogen and Energy System Integration Strategies, ACER, CEER, 9 February 2021, p. 2).
Article 1(2) of the Gas Directive 2009/73/EC states in fact that the rules established by Directive for natural gas, including LNG, also apply in a non-discriminatory way to biogas and gas from biomass or other types of gas in so far as such gases can technically and safely be injected into, and transported through, the natural gas system. Therefore, while pure hydrogen transport is not subject to the Gas Directive 2009/73/EC, hydrogen production can be considered to be subject to it since a certain amount of hydrogen can be safely blended into the gas infrastructure.
Blending of hydrogen into the gas network is addressed in ACER’s 2020 Report of 10 July 2020 on NRAs Survey: Hydrogen, Biomethane, and Related Network Adaptations.
As underlined in the European Commission document of 10 February 2021 "Inception Impact Assessment, Hydrogen and Gas markets Decarbonisation Package" (Ref. Ares(2021)1159348 - 10/02/2021) "the Gas Directive and Regulation are designed for the organisation and functioning of the current fossil-based natural gas sector. They do neither anticipate the emergence of alternative methane gases, such as bio- or synthetic-methane, or other gaseous fuels, such as hydrogen, nor different production patterns. For instance, they do not integrate the distributed production of renewable and low-carbon gases and they do not prevent disruptions caused by changing gas quality. This focus on natural gas may lead to a situation in which it is more difficult to switch consumption from natural gas to renewable and low-carbon gases leading to lock-in effects or delays in a more significant deployment of renewable and low-carbon gases".
Other shortcomings of existing legal framework listed in the European Commission document of 10 February 2021 are:
- Elements of the existing gas rules, focusing on natural gas mainly imported from outside the EU, do not address the specific characteristics of decentralised renewable and low-carbon gases production within the EU. The vast majority of today’s bio-methane plants in the EU are connected at the distribution level. However, the current regulatory framework does not anticipate decentralised gas injections, meaning that the tradability and access of renewable and low carbon gases to markets and the gas grid is not on a level playing field with fossil natural gas, affecting the business case of renewable and low carbon gases producers and the costs for achieving the EU’s climate objectives. Likewise LNG terminals are not necessarily fit for receiving renewable and low-carbon gases and granting access in a transparent way.
- In comparison to the electricity sector, the gas market framework lags behind on consumer protection. The growing volumes of bio-methane and hydrogen affect gas quality (i.e. the physical characteristic of gas) and thereby the design of gas infrastructure and end-user applications and entail the risk of market fragmentation.
It is noteworthy, in the Joint letter of 29 June 2021 the major European energy market players (including ENEL, EDF, Iberdrola) called for the inclusion of the hydrogen sector in the carbon border adjustment mechanism regulation (CBAM) with the intention to avoid fossil based and highly emitting hydrogen imports, which would be similar to carbon leakage for hydrogen production.
Fit for 55 amendments
On 14 July 2021 the European Commission presented the Renewable Energy Directive revision (European Commission Proposal for a Directive of the European Parliament and of the Council amending Directive (EU) 2018/2001 of the European Parliament and of the Council, Regulation (EU) 2018/1999 of the European Parliament and of the Council and Directive 98/70/EC of the European Parliament and of the Council as regards the promotion of energy from renewable sources, and repealing Council Directive (EU) 2015/652, COM(2021) 557 final).
The Fit for 55 legislative Proposal introduces the definition of 'renewable fuels of non-biological origin’, which mean liquid and gaseous fuels the energy content of which is derived from renewable sources other than biomass. Moreover, the rule is established that gas and electricity from renewable sources is to be considered only once for the purposes of calculating the share of gross final consumption of energy from renewable sources. Energy produced from renewable fuels of non-biological origin shall be accounted in the sector - electricity, heating and cooling or transport - where it is consumed. The proposal includes the requirement for the EU Member States to ensure that the contribution of renewable fuels of non-biological origin used for final energy and non-energy purposes is 50 % of the hydrogen used for final energy and non-energy purposes in industry by 2030. Calculation of that percentage is to be made in accordance with the new Article 22a of the RED II.
The EU ETS proposal will include the production of hydrogen with electrolysers under the EU emissions trading system, making renewable and low-carbon facilities eligible for free allowances.
New EU framework to decarbonise gas markets and promote hydrogen
On 15 December 2021 the European Commission proposed new EU framework to decarbonise gas markets and promote hydrogen, consisting of:
- Proposal for a Directive of the European Parliament Parliament and of the Council on common rules for the internal markets in renewable and natural gases and in hydrogen, COM/2021/803 final,
- Proposal for a Regulation of the European Parliament Parliament and of the Council on the internal markets for renewable and natural gases and for hydrogen (recast), COM/2021/804 final.
Before the above legislative pieces there were no rules at EU-level regulating dedicated hydrogen networks or markets. The new framework seeks to facilitate the penetration of renewable and low-carbon gases into the energy system, enabling a shift from natural gas and to allow for these new gases to play their needed role towards the goal of EU climate neutrality in 2050. The proposal observes that legal barriers exist for the development of a cost-effective, cross-border hydrogen infrastructure and competitive hydrogen market - a prerequisite for the uptake of hydrogen production and consumption.
Among deficiencies of current regulatory framework for gaseous energy carriers the above proposal identifies:
- absent rules at EU level on tariff-based investments in networks, or on the ownership and operation of dedicated hydrogen networks;
- absence of harmonised rules on (pure) hydrogen quality.
The deployment of hydrogen as an independent energy carrier via dedicated hydrogen networks should be properly promoted. Therefore, the system of terminology and certification of low carbon hydrogen and low carbon fuels is proposed.
Under the new EU Directive authorisations granted under national law for the construction and operation of existing natural gas pipelines and other network assets will be grandfathered in the administrative permit granting processes for the deployment of hydrogen production facilities and hydrogen system infrastructure (see Recital 47 of the draft Directive). Moreover, conditions for granting authorisations for hydrogen system infrastructure must not be materially different- deviations can be justified by technical safety considerations only. In turn, Annex to the draft Regulation sets important rules for the format and content of the publication of the technical information on network access by hydrogen networks operators.
Furthermore, Point 2.2.5 of the Annex I to the said Proposal for a Regulation stipulates rules for the long term use-it-or-lose-it mechanism. According to the above provision transmission system operators must to partially or fully withdraw systematically underutilised contracted capacity on an interconnection point by a network user where that user has not sold or offered under reasonable conditions its unused capacity and where other network users request firm capacity.
Contracted capacity is considered to be systematically underutilised in particular if:
(a) the network user uses less than on average 80% of its contracted capacity both from 1 April until 30 September and from 1 October until 31 March with an effective contract duration of more than one year for which no proper justification could be provided; or
(b) the network user systematically nominates close to 100% of its contracted capacity and renominates downwards with a view to circumventing the above rule.
Withdrawal shall result in the network user losing its contracted capacity partially or completely for a given period or for the remaining effective contractual term. The network user shall retain its rights and obligations under the capacity contract until the capacity is reallocated by the transmission system operator and to the extent the capacity is not reallocated by the transmission system operator.
The rule of fundamental importance is Arricle 6(6) of the said draft Regulation stating that as of 1 January 2031, hydrogen networks shall be organised as entry-exit systems.
Examples of schemes for the promotion of renewable hydrogen
Among examples of schemes for the promotion of production renewable hydrogen it is useful to mention the German H2Global (estimated budget €900 million) approved by the European Commission on 20 December 2021. H2Global will support the production of renewable hydrogen in non-EU countries, to be imported and sold in the EU. The scheme will run for 10 years starting from the award of the first contract under the scheme. The scheme will be managed and implemented by a special-purpose entity named HINT.CO. This intermediary will conclude long-term purchase contracts on the supply side (green hydrogen production) and short-term resale contracts on the demand side (green hydrogen usage).
The aid will be awarded through competitive tenders. Prices will be determined on the buying and selling side via a double auction model, where the lowest bid price for hydrogen production and the highest selling price for hydrogen consumption will each be awarded a contract. The producers of renewable hydrogen and hydrogen derivatives such as green ammonia, green methanol, and e-Kerosene wishing to participate in the tenders will have to strictly comply with the sustainability criteria for renewable hydrogen and hydrogen derivatives production, set by the revised Renewable Energy Directive (RED II). They will also have to contribute to the deployment or financing of the additional renewable electricity needed to supply the electrolysers producing hydrogen under the scheme.
Another case is the Romanian scheme approved by the European Commission under EU State aid rules on 8 August 2022 worth €149 million made available through the Recovery and Resilience Facility to support the production of renewable hydrogen. The measure aims to contribute to the development of renewable hydrogen in line with the objectives of the EU Hydrogen Strategy and the EU Green Deal. The Romanian scheme will run until 31 December 2023 and is aimed at supporting the construction of new installations for the production of renewable hydrogen, to achieve by 31 December 2025 renewable hydrogen production capacities of at least 100 MW in electrolysis installations producing at least 10,000 tonnes of hydrogen per year. The scheme is open to (i) companies of all sizes that are active in the production of hydrogen or electricity, (ii) administrative-territorial units, or (iii) national institutes for research and development in the field of energy, including associations or partnerships formed by those actors. Under the scheme, the support will take the form of direct grants. The maximum amount of aid that can be granted per project will not exceed €50 million. The projects will be selected through a transparent and non-discriminatory bidding process, where beneficiaries will compete for the lowest amount of aid per MW of installed electrolysis capacity. The first call for projects was started in June 2022.