EUROPEAN COMMISSION Brussels, 15.12.2021 SWD(2021) 455 final COMMISSION STAFF WORKING DOCUMENT



IMPACT ASSESSMENT REPORT

Accompanying the Proposal for a Directive of the European Parliament and of the Council on common rules for the internal markets in renewable and natural gases and in hydrogen (recast) Proposal for a Regulation of the European Parliament and of the Council on the internal markets for renewable and natural gases and for hydrogen (recast)



































{COM(2021) 803 final}

{COM(2021) 804 final} - {SEC(2021) 431 final} - {SWD(2021) 456 final} - {SWD(2021) 457 final} - {SWD(2021) 458 final}



Table of contents 1Political and legal context 1.1Context of initiative 1.2Scope of initiative 1.3Organisation and timing 1.4Links with other initiatives 1.5Alignment with the FIT for 55 Impact Assessment 2Problem definition 2.1Problem Area I: Hydrogen infrastructure and markets 2.2Problem Area II: Renewable and low carbon gases in the existing gas infrastructure and markets, and energy security 2.3Problem Area III: Network planning 2.4Problem Area IV: Low level of customer engagement and protection in the green gas retail market 2.5Interdependencies between problem areas 2.6Evaluation 3Why should the EU act? 3.1Legal basis 3.2Subsidiarity: Necessity of EU action 3.3Subsidiarity: Added value of EU action 4Objectives: What is to be achieved?

4.1General objectives 4.2Specific objectives 5Available policy options 5.1Options in the Problem Area I: Hydrogen infrastructure and markets 5.2Options in the Problem Area II: Renewable and low carbon gases in the existing gas infrastructure and markets, and energy security 5.3Options in the Problem Area III: Network planning 5.4Options in Problem Area IV: Low level of customer engagement and protection in the green gas retail market 6What are the impacts of the options? 6.1Assessment of options for Problem Area I: Hydrogen infrastructure and markets 6.2Assessment of options for Problem Area II: Renewable and low carbon gases in the existing gas infrastructure and markets, and energy security 6.3Assessment of policy option in relation to Problem Area III: Integrated network planning. 6.4Assessment of policy option in relation to Problem Area IV: Lack of customer engagement and protection in the green gas retail market 6.5Social impacts 6.6Impacts on SMEs 7How do the options compare? 7.1Comparison of options in Problem Area I: Ensuring emergence of cost-effective hydrogen infrastructure and contestable hydrogen markets 7.2Comparison of options in Problem Area II: Ensuring access of renewable and low carbon gases to the existing natural gas networks and market 7.3Comparison of options in Problem Area III: Ensuring integrated network planning 7.4Comparison of options in Problem Area IV: For addressing lack of consumer engagement and protection in the green gas retail market 7.5Synergies and trade-offs between problem areas

8Preferred options 8.1Problem Area I: Hydrogen infrastructure and markets 8.2Problem Area II: Renewable and low-carbon gases in the existing gas infrastructure and markets, and energy security 8.3Problem Area III: Integrated network planning 8.4Problem Area IV: Low level of customer engagement and protection in the green gas retail market 8.5REFIT (simplification and improved efficiency) 9How will actual impacts be monitored and evaluated? 9.1Future monitoring and evaluation plan 9.2Annual reporting by ACER and evaluation by the Commission 9.3Operational objectives 9.4Monitoring indicators and benchmarks Annex 1: Procedural information Lead DG, Decide Planning/CWP references Organisation and timing Consultation of the RSB Evidence, sources and quality Annex 2: Stakeholder consultation Consultation strategy Inception Impact Assessment Public consultation

Other consultation activities Council/Member States European Parliament National regulatory authorities Annex 3: Who is affected and how? Practical implications of the initiative Summary of costs and benefits Annex 4: Analytical methods Description of the model used Description of the scenario definition methodology Modelling approach to Problem Area I Modelling approach to Problem Area II Data collection methodology Annex 5: Modelling results for Problem Area I: Hydrogen infrastructure and markets Infrastructure needs Costs of hydrogen Annex 6: Detailed measures for Problem Area I: Hydrogen infrastructure and markets Tables assessing individual measures Clarification of joint versus separate regulated asset base approach Annex 7: Detailed measures for Problem Area II: Renewable and low carbon gases in the existing gas infrastructure and markets, and energy security

Tables assessing individual measures Gas quality: Hydrogen blending cross-border framework Annex 8: Detailed measures for Problem Area III: Network planning Annex 9: Detailed measures for Problem Area IV: Low level of customer engagement and protection in the green gas retail market Annex 10: Additional analysis for Problem Area IV: Low levels of customer protection and engagement Driver 1: Untapped competition potential in retail markets Driver 2: Insufficient customer empowerment in terms of switching, price comparison tools, billing information, energy communities, and access to data Annex 11: Evaluation and impact assessment Annex 12: Detailed Annex on coherence with the present proposals with other Fit for 55 proposals as well as other legislative acts The revised Renewable Energy Directive (RED II) The Energy Efficiency Directive (EED) Energy Performance of Buildings Directive and the Renovation Wave initiative The Regulation on trans-European energy networks (TEN-E) Emission Trading Scheme (ETS)/Innovation Fund and Effort Sharing Regulation Energy Taxation Directive (ETD) Methane leakage CCS directive The Alternative Fuel Infrastructure Regulation The FuelEU Maritime and REFuel EU Aviation proposals Glossary

List of Figures List of Tables 1 Political and legal context 1.1Context of initiative The European Green Deal (EGD) and the Climate law set the target for the EU to become climate neutral by 2050 in a manner that contributes to European competitiveness, growth and jobs. This, together with a 55% greenhouse gas emissions reduction target by 2030, requires an energy transition and significantly higher shares of renewable energy sources in an integrated energy system and acceptance and active participation of consumers in competitive markets, to benefit from affordable prices, good standards of service, and effective choice of offers mirroring technological developments. On 14 July, the European Commission adopted a first set of proposals to make the EU's climate, energy, transport and taxation policies fit for reducing net greenhouse gas emissions by at least 55% by 2030, compared to 1990 levels. The present initiative is equally part of the Fit for 55 package. It covers market design for gases. Whilst it will not deliver decarbonisation by itself, it will remove barriers for this to happen and create the conditions for this to take place in a more cost effective manner. Electrification of demand sectors will further increase as it is generally the most cost-effective and energy-efficient way to decarbonise final energy demand. Coupled with an increased contribution from renewables, energy efficiency and a circular economy, electrification delivers a substantial part of the emission reductions across the energy system. Gaseous fuels (natural gas, biogas and biomethane, synthetic methane and hydrogen) will however continue playing an important role in the energy system. Their ability to store energy allows matching seasonal demand patterns and complements fluctuating supply of renewable electricity. For processes, which cannot easily be electrified for technical or economic reasons, gaseous fuels are likely to remain present in the EU’s energy system. It is however clear, that these gases must be decarbonised on the way to 2050. This document analyses how to adapt the current legal framework for the internal gas market (mainly the Gas Directive and the Gas Regulation) to facilitate the decarbonisation of gaseous fuels in a competitive manner at least economic costs whilst ensuring energy security and placing consumers at the heart of the energy markets. Two main pathways, are likely to emerge in parallel and expected to develop at different pace across the EU: -A hydrogen-based infrastructure will progressively complement the network for methane gases; -A methane-based infrastructure in which natural gas will progressively be replaced by other sources of methane (i.e. biomethane and synthetic methane, possibly occasionally blended with hydrogen). Currently, some 300 Mtoe (350-400 bcm) of gaseous fuels are consumed in the EU per year, of which 95% is natural gas. They account for roughly 25% of total EU energy consumption, used for 20% of EU electricity production, and 39% of heat production. In line with the policy scenarios that underpin the Fit for 55 initiative, biogas and biomethane, renewable and low-carbon hydrogen and synthetic fuels (E-gas) will gradually replace fossil gases and represent very significant shares of the gaseous fuels in the energy mix towards 2050. Conversely, the share of natural gas is projected to be significantly reduced and coupled with Carbon Capture Usage and Storage (CCUS) technologies. Figure 1 shows the latest projections for consumption of gaseous fuels produced by the Commission with the PRIMES energy model. The projections also show that the energy carried by gaseous fuels would, after slightly decreasing between 2020 and 2030, stay in 2050 at about 85% of the current level. Two scenarios are shown in the Business as Usual (BAU) case (the Reference 2020 – REF) and in the Green Deal scenario (MIX). Source: PRIMES Under current framework conditions, biomethane, synthetic methane and hydrogen have significantly higher levelised costs of energy compared to natural gas. This cost gap can be addressed by a much higher carbon price , by direct financial incentives in particular for renewable gases and by reducing the cost for access to the system for the gaseous fuels other than natural gas. However, the renewable and low-carbon gases today face regulatory barriers for market and grid access that represent a comparative disadvantage versus natural gas. The differences in costs of production and potential of biomethane and hydrogen production between EU Member States are significant and are a strong argument to enable cross-border trade. Abolishing the regulatory barriers will enable renewable and low carbon sources of gases to compete in the EU gas market, bringing down costs of production, increasing cost efficiency and leading to less support measures and state aid. It will also enable supply of those gases to Member States, and end-consumers, that otherwise would not satisfy their demand. 1.2Scope of initiative

The initiative aims to adapt the rules for the transmission, distribution, supply and storage of methane and hydrogen based gases. It lays down the rules relating to the organisation and functioning of these gas sectors, access to the market and the operation of systems as well as rights of consumers of gases. Where necessary, the rules for hydrogen and methane gases are differentiated to make them fit for purpose. Maintaining overall energy security is an underpinning factor. 1.3Organisation and timing The Commission has conducted a number of wide and targeted public consultations between 2019 and 2021 on the different problem areas covered by the present Impact Assessment. Given the cross-cutting nature of the planned Impact Assessment work, the Commission set up an inter-service steering group, which held regular meetings to discuss the policy options of the proposed initiatives and the preparation of the Impact Assessment. In parallel, the Commission has also conducted a number of studies for this Impact Assessment. 1.4Links with other initiatives The proposed initiative is focussing on enabling the markets to decarbonise gas consumption. It is strongly linked and complementary to the legislative proposals brought forward in the context of the Fit for 55 package to implement the European Green Deal, including: -The revised Renewable Energy Directive (RED II), which is the main EU instrument dealing with the promotion of energy from renewable sources. It aims to incentivise the penetration of renewable energy, including renewable gases. Its proposed amendment to increase the target for renewable sources in the EU’s energy mix to 40% and promote the uptake of renewable fuels, such as hydrogen in industry and transport, with additional targets. However, other low-carbon fuels (including low-carbon gases, such as low-carbon hydrogen) are not in the scope of RED and its revision. Such fuels can however also play a role in the transition, particularly in the short and medium term to rapidly reduce emissions of existing fuels, and support the uptake of renewable fuels such as renewable hydrogen. In order to fill in this gap and enable low-carbon fuels to be a viable solution for Member States in a transitional period, this Impact Assessment explores options for deploying a system of terminology and certification of non-renewable low-carbon fuels; -The Energy Efficiency Directive (EED) and the related Energy Performance of Buildings Directive (EPBD) including the proposals for their amendment interact with the present initiative as they affect the level and structure of gas demand. Energy efficiency measures can alleviate energy poverty and reduce consumer vulnerability. As gaseous fuels are currently dominating in European heating and cooling supply and in the cogeneration plants, their efficient use stays at the core of the energy efficiency measures. The present initiative is coherent with the energy efficiency first principle: an open and competitive EU market with prices that reflect energy carriers’ production costs, carbon costs, and external costs and benefits would efficiently provide clean and safe hydrogen to end users who value it most. -The TEN-E Regulation, as proposed by the Commission in December 2020, aims to better support the modernisation of Europe's cross-border energy infrastructure for the EGD. It introduced hydrogen infrastructure as a new infrastructure category for European Network Development. The present initiative is complementary as it focuses on alignment of the national plans with the requirements of the European Network Development plan; -As announced in the EU strategy to reduce methane emissions, the Commission will propose legislation to reduce methane emissions in the energy sector. The initiative will seek to improve information for all energy-related methane emissions. The present initiative seeks to facilitate the penetration of renewable and low-carbon gases, enabling a shift from natural gas; -The Emission Trading Scheme (ETS) increases the price of using fossil fuels relative to renewable and low-carbon gases and, thus, fosters the demand of such gases and investments in related production technology. The Commission has proposed strengthening, including reinforcements in and extensions to the aviation sector, maritime and road transport, and buildings. -The revised Alternative Fuels Infrastructure Regulation, which will repeal Directive 2014/94/EU on deployment of alternative fuels infrastructure (AFID), as proposed by the Commission in July 2021, aims to tackle rising emissions in road transport to support the transition to a nearly zero-emission car fleet by 2050. The Regulation requires Member States to expand their network of recharging and refuelling infrastructure in line with zero emissions car sales, and to install charging and fuelling points at regular intervals on major highways. The present initiative is coherent and has clear synergies with these instruments and others. 1.5Alignment with the FIT for 55 Impact Assessment The quantitative assessments shown in this report build on the analysis performed for the Fit for 55 policy package. Consequently, all model-based analysis related to hydrogen and renewable and low carbon gases is aligned to the MIX-H2 PRIMES scenario , which underpins the Impact Assessment supporting the proposal for a revised Renewable Energy Directive. While the Impact Assessment for a revised Renewable Energy Directive, is looking at policy measures to promote the demand and production of hydrogen as well as renewable and low carbon gases, the present assessment explores the policy measures required for optimum infrastructure and efficient markets. By using the MIX-H2 PRIMES scenario, the overall relationships between energy supply and demand are preserved. This ensures consistency with the underlying policies driving the transition to Greenhouse Gas (GHG) neutrality as proposed in by the Fit for 55 initiative. The relationship between the MIX-H2 PRIMES scenario and the policy measures that are assessed in this report is further explained in Section 6 and Annex 4. 2Problem definition 2.1Problem Area I: Hydrogen infrastructure and markets 2.1.1Problem: Barriers exist for the deployment of a cost-effective hydrogen infrastructure and a competitive and integrated hydrogen market Today, hydrogen represents a modest fraction of the European Union’s energy mix. It is mainly used as industrial feedstock and is largely produced from fossil fuels emitting CO2. Hydrogen is not yet a traded commodity and a hydrogen network is not yet an essential facility, as producers and consumers are not competing for access to a cross-border network for hydrogen transport. Existing networks are privately owned and tailored for the point-to-point transport of hydrogen to industrial customers.

The Communication on a hydrogen strategy for a climate-neutral Europe (the EU Hydrogen Strategy) published in 2020 as well as the hydrogen strategies of a number of Member States, define ambitions towards 2030 to prepare for the expected steep increase of hydrogen consumption between 2030 and 2050 (in particular hydrogen produced from water using renewable electricity through a process of electrolysis). Next to renewable hydrogen, other forms of low-carbon hydrogen can play a role, primarily to rapidly reduce emissions from existing hydrogen production and to support the parallel and future uptake of renewable hydrogen. The Communication describes a roadmap for the development of a hydrogen value chain that would progressively require EU logistical infrastructure and would reach a more mature phase by 2030. Today - 2024 2025 - 2030 2050 Electrolyser installed capacity 6 GW 40 GW 500-550 GW Production RES H2 Up to 1 Mt Up to 10 Mt 70-80 Mt Infrastructure Infrastructure needs for transporting hydrogen over longer distance will remain limited. Need for an EU-wide logistical infrastructure will emerge. Fully developed EU hydrogen network in place (with connections to non-EU countries) Electrolyser targets national hydrogen strategies (until November 2021) - 32.5-33.5 GW - Source: EU Hydrogen strategy and national hydrogen strategies, PRIMES The current regulatory framework for gaseous energy carriers does not address the second pathway identified above by which gaseous fuels will be decarbonised, namely the deployment of hydrogen and the development of a dedicated hydrogen infrastructure next to the already existing methane-based infrastructure. There are no rules on the operation of new hydrogen infrastructure or the repurposing of existing natural gas networks for the future transport of hydrogen. The security challenges of hydrogen deployment are also not addressed in the SoS Regulation,. The problem resides in the fact that barriers exist for the development of a cost-effective hydrogen infrastructure and integrated, competitive hydrogen market. 2.1.1.1Driver 1: Decarbonisation will result in the emergence of a European hydrogen value chain reliant on a cross-border hydrogen market With renewable energy resources being key but unevenly distributed over Member States the availability of well-integrated, cross-border hydrogen markets will be key to support the EU’s climate neutrality objectives and ensure its cost-effectiveness. Hydrogen networks will allow the transport of hydrogen from regions with excess capacity of renewable energy to supply demand centres in (cross-border) regions with lower hydrogen production capacity. Any trade barriers for hydrogen and a lack of transport capacity could hamper the development of the hydrogen value chain and, consequently, decarbonisation. In view of the variability of renewable hydrogen production on the one hand and the need to provide stable supply to users on the other hand, storage infrastructure will be an important asset on such a hydrogen market. It allows hydrogen producers to optimise their economic activities by utilizing electrolysers on the basis of (favourable) price variations for renewable electricity instead of adapting the operation of electrolysers to consumption patterns. Currently, salt caverns are the only proven large-scale hydrogen storage option but, due to geological conditions this storage option is only available in certain Member States. Accordingly, large-scale storage might be scarce (especially at the ramp-up stages) thereby underlining the need for (cross-border) markets. EU hydrogen demand might be partially covered by imports from third countries depending on the competitiveness of renewable and low carbon gases produced in these countries relative to domestic EU production and the possibilities and costs to import them into the EU. In terms of volumes, the potential for hydrogen imports and exports remains uncertain, especially by 2030. Moreover, alongside pipelines that interconnect the EU with third countries, hydrogen can be imported from (more distant) third countries by ships that can use a range of different modes to transport hydrogen such as in liquid form or as ammonia. As the optimal import means will also depend on the envisaged end use of hydrogen, it is not yet fully clear what means of hydrogen import will become predominant. In any event, investments in and the operation of import facilities will equally be dependent on functioning commodity markets (and on the available transportation infrastructure to reach demand centres). Low-carbon hydrogen (LCH) and low carbon fuels (LCFs) have decarbonisation potential. However, they lack a definition. Yet, it can be expected, at least in the short term, that Member States will use LCF and LCHs to initiate the development of transport infrastructure as well as adaptations by end-users for the eventual uptake of renewable hydrogen. Not certifying LCF and LCHs in a comprehensive and harmonised manner risks to jeopardise the integrity of the EU market and hamper cross-border trade, inside the EU as well as trade with third countries, since it would create uncertainty about the real GHG footprint of such solutions. An efficient hydrogen market can increase welfare by exploiting comparative advantages whilst the price signals it produces will steer investment decisions and the operation of hydrogen assets. Whilst the development of a hydrogen market has clear benefits, no such integrated hydrogen market exists today. 2.1.1.2Driver 2: Lack of hydrogen infrastructure investments hinders market development The development of a hydrogen market requires infrastructure. Pipeline transportation is highly likely to be the most cost-effective means of transporting hydrogen for distances compatible with the European territory, compared to other means such as road-based or marine transport or transportation through the electricity grid of electricity before its transformation into hydrogen. A lack of hydrogen networks may increase the carbon footprint of production and render hydrogen more expensive for consumers, as they have to divert to less cost-effective (and sustainable) transportation means. As production and consumption of hydrogen ramp-up across the EU, cross-border hydrogen networks will be required to meet transport needs from favourable production locations to demand centres. The construction of a pan-European grid would require considerable capital investments . Existing natural gas networks can be partially repurposed for the transport of hydrogen, with significant cost savings compared to new-build infrastructure. The same applies to large scale storage and, likely to lesser extent, import terminals. However, there is no clarity on the context in which infrastructure investments can take place and barriers to exploit repurposing opportunities exist. There is no transparency on what parts of the gas grid may become available for repurposing, no clear rules exist on how repurposing could be organised, how (new or repurposed) hydrogen infrastructure is financed and whether current arrangements applicable to gas pipes (e.g. permitting and land use rights) continue to be applicable once these pipes are used for hydrogen transportation. 2.1.1.3Driver 3: Hydrogen infrastructure is likely to constitute a natural monopoly, resulting in non-competitive market structures As hydrogen markets develop, dedicated hydrogen networks and possible other types of infrastructure are likely to constitute natural monopolies or essential facilities on which hydrogen producers and consumers depend in order to transport, store and receive hydrogen. While existing hydrogen pipeline infrastructure is currently unlikely to constitute a natural monopoly as current hydrogen producers and sellers/buyers are not competing for access to hydrogen infrastructure, it is expected to happen in the future, based on the following elements: -Pipelines have a sub-additive investment cost curve. This means that the total cost of transport services are expected to be lower for one pipeline operated by a single firm than for two pipelines with an equal transport capacity that are operated by two firms;

-Other transportation means (such as transportation by trucks) would not provide suitable or competitive alternatives for most uses; -Refurbishing natural gas pipelines to hydrogen operations will be less expensive than new-build pipelines, and will hence offer a competitive advantage to the owners/operators of existing natural gas networks. As a result, the hydrogen pipeline/network ‘inherits’ the natural monopoly character from the natural gas pipeline/network; -Hydrogen is expected to become a traded commodity with a high number of producers/sellers and buyers competing for access to transport infrastructure. This would coincide with phase 2 (2025-2030), and more broadly phase 3 (2030 towards 2050) defined in the EU hydrogen Strategy. Natural monopolies could lead to the foreclosure of upstream (hydrogen production) and downstream (supply of hydrogen to end-users) activities within the hydrogen value chain, which may in turn lead to hydrogen consumers being deprived from supply or being confronted with higher prices in the end also affecting the ability for hydrogen to decarbonise the EU economy. However, no rules exist to ensure market access addressing the risk of market foreclosure and non-competitive market structures, while taking into account the specificities of a nascent market. 2.1.1.4Driver 4: Diverging hydrogen quality rules may hinder cross-border flows and incur additional costs Gas quality for pure hydrogen networks has so far received little attention as current hydrogen supply is predominantly organised on a point-to-point basis. Once hydrogen is injected into the network from different production processes and transported through a meshed network, including across-borders, issues around hydrogen quality (i.e. purity) may arise. Different applications require different hydrogen purity levels and can have different tolerances for the composition of the impurities. Industrial grade purity is required at a minimum 99.9% (e.g. in ammonia and steel production and in refineries), fuel cell uses require a purity above 99.97% (e.g. in road and rail transport), while used for its thermal value hydrogen purity is a less important parameter e.g. in power plant turbines. Different sources and production methodologies lead to different hydrogen purity levels and the transport via pipeline also has an effect on the purity: Existing gas pipelines converted for hydrogen transport can respect a 98% purity, which can represent a significant issue with reusing existing gas infrastructure for hydrogen transport. To ensure that the level of hydrogen purity matches end-use requirements, purification might be necessary as an additional step at added cost in the production process or at a later stage, e.g. at end-use points. Currently, only a few national level standards are applicable or under development, while the European Committee for Standardization (CEN) is investigating the tolerance of infrastructure elements and end-use applications to hydrogen. As of today, there is limited availability of data on and experience with hydrogen purity and its implication on the operation of infrastructure and appliances. The lack of harmonised rules on a minimum purity level for hydrogen transportation can pose a risk to the unhindered flow and use of hydrogen in the near future. Such issues are expected to become particularly pertinent when dedicated hydrogen networks connect Member States and divergent technical rules, including quality specifications, constitute a barrier to the cross-border flow of hydrogen. Thus a need exists to assure that diverging hydrogen quality (hydrogen purity and contaminants) rules hinder cross-border flows. 2.1.2How will the problem evolve? Today, the share of hydrogen represents a negligible share of all gaseous fuels, predominantly produced and used within chemical production sites and refineries. In the MIX-H2 scenario, the production of renewable hydrogen will increase to more than 17 Mtoe (or 6 Mt of hydrogen) in 2030 and can be 230 Mtoe (80 Mt) in 2050. The share of hydrogen in the total consumption of gases increases to 4% in 2030 and up to 40% in 2050 If the above issues remain unresolved, market integration will be hampered, infrastructure roll-out slowed down and non-competitive markets outcomes can be expected. Higher hydrogen prices and lower uptake of hydrogen and lower decarbonisation will be the result. Member States may take national initiatives based on national strategies, but these efforts are likely to be dispersed, resulting in uncoordinated and weaker cross-border integration and network development. As geographical and geological circumstances vary among Member States, some will have no or limited access to hydrogen storages and terminals. These problems will not only pose risks to the objectives as set out by the EU Hydrogen Strategy by 2030, but even more so beyond 2030 in view of the steep increase in hydrogen consumption and production envisaged beyond 2030 towards 2050. 2.2Problem Area II: Renewable and low carbon gases in the existing gas infrastructure and markets, and energy security 2.2.1Problem: Untapped potential of RES gases and barriers blocking the access of biomethane to gas market and infrastructure Today, renewable and low-carbon gases represent a minor role in the EU energy mix. Biogas is primarily used on-site to generate heat and electricity. Biomethane totalled around 20 TWh in 2019, which, was less than 1% of the EU’s natural gas consumption of about 3850 TWh. Blending hydrogen into natural gas grids and the production and injection of synthetic methane only exist at the scale of demonstration or pilot projects. The global biomethane export potential is estimated by the IEA at 8084 TWh in 2018, rising to 9731 TWh in 2040. The costs of imports to the EU ranged in 2018 between EUR 12/MWh and EUR 98/MWh. In 2040, import costs are estimated in the range of EUR 13/MWh and EUR 70/MWh (including shipping costs), depending on the region . Import of biomethane can take place using Liquified Natural Gas (LNG) terminals or transmission pipelines (high pressure pipelines transporting gas on long distances).

In the EU, currently, the production costs of biomethane vary from EUR 36/MWh to EUR 116/MWh . The differences in production costs show an opportunity for trade across the EU. However, unlike natural gas, which is normally injected at the transmission level, about half of the biomethane production capacity is connected to the distribution grid (low pressure pipelines which distribute gas in local areas). Injecting biomethane into distribution grids may, on the one hand be realised at lower operational costs, but on the other hand it deprives the biomethane producers access to the wholesale market which is organised around the transmission grid and the market dominated by natural gas. Source: Fraunhofer Figure 4: LCOE of biomethane in 2030 (EUR/MWh) This results in a problem that the potential to produce biomethane remains untapped. At the same time rules applicable to biomethane vary between Member States which results in lack of level playing field between the producers of biomethane across the EU. Leaving biogas potentials from agricultural residues and waste (from sewage, municipal waste or landfills) unused represents a missed opportunity to make an additional step towards a circular economy as outlined under the Circular Economy Action Plan (CEAP) . Furthermore, the potential contribution of biomethane to the energy security is not considered in the current framework on energy security. 2.2.1.1Driver 1.1: Constrained market and grid access for local producers of biomethane connected to the distribution grids For efficient marketing of renewable and low carbon gases, access to the gas wholesale market, i.e. the Virtual Trading Points (VTP), represents a key prerequisite. Yet, current market organisation and legislation in Member States does not necessarily foresee, in terms of market access, the integration of distribution systems in entry-exit zones of Transmission System Operators (TSOs) and the participation of the distribution level injected gases in the wholesale market. Consequently, the tradability of locally produced gases at the VTPs is limited, blocking, in particular smaller facilities, from becoming active components of the energy system. Currently, entry-exit zones include, under various conditions, distribution grids injected gas in 10 countries (AT, BE, ES, DE, FR, CZ, PL, FI, IT, PT). Biomethane plants connected to distribution grids may face another barrier in addition to the potentially restricted access to the VTP: Physical injection at the distribution grid level may be capped by the minimum demand levels in the local network as gas flows are typically mono-directional (from the transmission to the distribution level). Gas demand in distribution grids typically features a strong seasonal variation, notably where gas is used for space heating. Biomethane production on the other hand does not show a large seasonal variance. Thus, the minimum demand typically occurring during summer represents the limiting factor for biomethane injection. Surplus gas injection may hence not be accommodated in the grid if no remedial action is undertaken. This may even lead to connection request denial. Besides connection to other distribution systems or local storage solutions (which may not always be available), reverse flow compressors from Distribution System Operator (DSO) to TSO level are the most effective infrastructure option. Only Austria, Spain and France appear to have such policies in place. In Italy, a pilot project is under way. 2.2.1.2Driver 1.2: Divergence of rules regarding obligation to connect and costs of grid connection for renewable and low carbon gases Biomethane plants may be connected to the transmission or the distribution grid, upon request to the TSO or DSO. Currently, a connection obligation exists in 16 Member States, while at least five countries do not have such a national obligation. Connection obligation exists No connection obligation No information available AT, HR, CZ, DK, EE, FR, DE, HU, IE, IT, LV, LT, LU, NL, SI, ES BE, PL, PT, SK, SE BG, CY, FI, GR, MT, RO Source: (ACER, 2020) The allocation of grid connection costs between the network operator and the biomethane producer is handled quite heterogeneously across the EU: -Deep cost allocation where producers pay all costs associated with the connection. This allocation is applied in Ireland, Italy and Spain; -Shallow cost allocation where producers pay the cost for the physical grid connection and the system operator pays the necessary network reinforcement beyond the connection point. This allocation is applied in Austria, Belgium, Czechia, Denmark, Estonia, Finland and Sweden; -Super shallow cost allocation where producers pay only partially or not at all for the physical grid connection, and system operators bear the majority of costs for the network reinforcement beyond the connection point and all/part of the physical connection. This allocation is applied in France, Germany and Lithuania. When it comes to grid injection tariffs, in several Member States injection tariffs are lower for biomethane and hydrogen compared to tariffs for the injection of natural gas in transmission grids. This leads to a distorted level playing field between biomethane and hydrogen producers in various Member States.

2.2.1.3Driver 1.3: Intra-EU entry/exit tariffs hinder the establishment of a fully integrated, liquid and interoperable EU internal gas market The current gas market model is organised around entry/exit zones in which TSOs transport two kinds of flows: -National flows from an entry point (TSO, LNG terminal, storage, production) to an national exit point (DSOs, industrial consumers, gas-fired power plants); -Transit flows from an entry point (TSO, LNG terminal, storage, domestic production) to one cross-border exit point. The costs of transporting these flows are borne by the TSOs. They are recovered via grid tariffs taking into account the allowed revenues to remunerate their assets that are determined by the National Regulatory Authorities (NRAs). The methodology to define how allowed revenues are determined is not homogeneous among the Member States and it is not harmonised at EU level. Tariffs can be distinguished by three categories: -The exit tariffs at internal exit points, which are paid only by the national consumers; -The exit tariffs at cross-border points, which are paid by grid users other than national consumers; -The entry tariffs paid by either national or non-national grid users (depending on where the flow crossing this point is destined). The revenue repartition between these three kinds of tariffs is a complex matter. The Network Code on tariff structures (NC TAR) creates rules on which basis the allowed revenues can be collected, enhancing transparency of tariff setting, providing a framework based on cost-drivers and the principle of cost reflectivity. However, although being transparent and cost reflective, tariffs effectively render cross-border flows uneconomic in case the tariff of the needed capacity is higher than the price difference between markets, to the detriment of overall efficiency. The more borders are crossed, the higher the effect of adding tariff layer on tariff layer, which is called the ‘pancaking’ effect. In the context of biomethane, pancaking may lead to a situation where the differences of production costs between Member States are not exploited. This may lower physical cross-border trade with renewable gases that might be compensated by higher natural gas imports. 2.2.1.4Driver 2: Differences in gas quality and hydrogen blending levels can negatively impact cross-border flows and end-users, current gas quality rules not fit to deal with future developments Today, gas quality is defined by European Committee for Standardization (CEN)-standards and at national level. The EN 16726 standard on gas quality developed by the CEN is not mandatory. Member States are setting the mandatory gas quality specifications, which can deviate from the CEN standard. In practice, the national specifications vary significantly between Member States to take into account national specificities. Gas producers and suppliers are obliged to deliver the gas within quality ranges specified in commercial agreements between the network user and the system operator. In most Member States, system operators have either the obligation or the right to reject the injection of gases, which do not comply with the applicable gas quality specifications. In the cross-border context this means that TSOs at a cross-border point can reject gases of a quality not corresponding with the applicable (national) gas quality specification. Beyond the quality standards, a cross-border coordination and dispute settlement framework for interconnection points (IPs) exists. The Interoperability and Data Exchange Network Code obliges neighbouring TSOs to address gas quality aspects in their Interconnection Agreement for a given IP. Should the concerned TSOs fail to agree on a solution, the competent NRAs must adopt a coordinated decision. In the absence of such coordinated decisions, ACER can adopt an individual decision. In practice, the injection of growing volumes of renewable and low-carbon gases, including biomethane and hydrogen, into the existing gas network is changing the parameters of gas consumed and transported in the EU, both at transmission and distribution levels. These changes in the quality of gases can have negative impacts on their cross-border flow and can cause problems and additional costs for system operators and end-users. Biogas and biomethane have specific quality aspects to consider. In order to transport biogas in the existing gas network and use it in connected appliances it has to be upgraded to biomethane before injection. Biomethane producing Member States developed their (differing) quality standards, and also CEN developed a biomethane quality standard for injection in the natural gas grid and for use in transport. While biomethane can be used without the need for any changes in transport infrastructure and end-user equipment, quality related issues (e.g. due to differences in oxygen content) might still arise, including at cross-border IPs. Further, the lower and varying calorific value of the gas at high biomethane injection rates could lead to issues related to metering and billing to end-users, as flow meters could incorrectly measure the user’s energy consumption. Blending of hydrogen affects the operation of gas infrastructure, end-user applications, and interoperability of cross-border systems. Hydrogen has a lower specific energy content which reduces the combustion properties of the gas mix, in particular the calorific value. This affects gas engines. Not all gas infrastructure components and gas consumers are able to cope with blended gases. Currently, allowed hydrogen blending rates are determined in some Member State and vary significantly (see Figure 5 . The interconnection agreements may not provide specifications regarding hydrogen concentrations. In addition, the future gas mix will lead to changes and more frequent fluctuations of the gas quality, making gas quality management in the existing gas network more complex and costly. . The interconnection agreements may not provide specifications regarding hydrogen concentrations. In addition, the future gas mix will lead to changes and more frequent fluctuations of the gas quality, making gas quality management in the existing gas network more complex and costly.

Source: (ACER, 2020), (FCHJU, 2021) 2.2.1.5Driver 3: LNG terminals equipped to receive mainly natural gas, limited access for new gases to LNG terminals The LNG market has significantly changed since the adoption of the Third Energy Package and rules applicable to LNG terminals in the EU. Efforts were made to utilise the LNG terminals to bigger extend, to move towards shorter-term capacity reservations and to enable small scale LNG and smaller players to develop. Some barriers to access LNG terminals persist, such as lack of transparency in tariff setting, capacity availability and allocation procedures. Even if today’s LNG facilities are primarily used for the import of natural gas from third countries, they could act in the future as facilitators for the import of renewable and low-carbon gases into EU. Biomethane, hydrogen and methanol can be liquefied and transported using LNG facilities provided some adaptations: -In case the biomethane or synthetic methane meets the gas quality specifications, no changes are needed in LNG terminals; -Regarding hydrogen, the physical and chemical differences between methane and hydrogen do not allow using existing LNG infrastructure as such and require its adaptation. Moreover, due to lower energy density of hydrogen the transport costs are likely to be higher; -Hydrogen can be transformed to ammonia and methanol and LNG ships and terminals can be used to transport these energies. The associated costs for liquefaction, transport, storage and regasification stages are smaller. Addressing the residual barriers regarding access to LNG terminals could open the way to importing renewable and low carbon gases from abroad supporting the decarbonisation of the EU gas market. 2.2.1.6Driver 4: Long term supply contracts for unabated natural gas may lock-in natural gas and hinder supply of renewable gases towards 2050 Long term contracts (LTC) for natural gas amount today to some 80% of the total supplies in the EU gas market. Some LTCs run as far as 2049. Long-term contracted volumes decrease over time (Cedigaz). While many of the current pipeline contracts date back to the 1990’s, LNG contracts were in majority concluded after year 2000. As public information indicates, new LTCs could be signed, or the existing contracts could be prolonged, which may have a duration until 2050 and beyond. This will depend on the perception of market participants about EU achieving full net decarbonisation by 2050 and available technologies to reach this. Natural gas supply contracts reduce the space left for biomethane and low-carbon synthetic methane. This may hinder the penetration of renewable and low-carbon gases as the market could be driven by imports of natural gas combined with contracts on the demand side, even in a situation where biomethane would be cost competitive (e.g., due to a significantly higher carbon price). Overall, the continued unconstrained existence of LTC’s up to 2050, risks to lead to carbon lock-in. Consistency with the transition from today towards climate neutrality by 2050 could then only be ensured through large scale deployment of CCS technology. Source: Cedigaz database, calculations Artelys 2.2.1.7Driver 5: Current energy security arrangements only address risks related to the supply of natural gas and not of renewable and low carbon gases. The current framework on energy security to prevent and manage possible disruptions are laid down in the SoS Regulation, which scope is limited to the risks related to the supply of natural gas only. Effects of repurposing or decommissioning of existing gas infrastructures are not explicitly addressed nor the positive impact or the specific risks of biomethane. Climate change induces risks impacting both infrastructure and production of renewable gas. Moreover the uses of smart grids, big data, artificial intelligence and automation enables a more efficient, resilient and lower-carbon operating model for the energy sector but increase the exposure to cyber threats. The current framework for ensuring energy security is not prepared for this change. 2.2.2How will the problem evolve? By 2030, a regulatory patchwork would still exist regarding access to wholesale markets, connection obligations and TSO-DSO coordination measures. Likewise, renewable and low-carbon gas producers will be facing different connection and injection costs across the EU, thereby resulting in an unequal playing field. Existing gas quality standards would remain non-binding and their application cross-border would not be aligned. Regarding biomethane, gas quality specifications would continue to be mainly defined by the quality parameters of natural gas. All these aspects are likely to lower cross-border trade of renewable gases that might be compensated by higher natural gas imports or higher support schemes. The utilisation of the terminals and imports could remain mainly for natural gas. With the increasing share of domestic production of gases and diversified suppliers, the current framework for ensuring energy security based on natural gas corridors, will become less effective. New cyber risks would become much more present, in a changing topology of the network. 2.3Problem Area III: Network planning 2.3.1Problem: Insufficient energy system integration in network planning

As outlined in the European Commission’s Energy System Integration Strategy, coordinated planning and operation of the entire EU energy system, across multiple energy carriers, infrastructures, and consumption sectors is a requisite to achieve the 2050 climate objectives. However, consideration of energy system integration in current network planning schemes and practices is deficient. Additionally, there are discrepancies between the EU-wide ten-year network development plan (TYNDP) and national network development plans (ETS NDP) in relation to the requirement of e.g. joint scenario building between electricity and gas infrastructures, which is all not required for NDPs. As a consequence, this may result in overestimating infrastructure needs in national plans, but also in the TYNDP as the TYNDP is based upon NDPs, and may hence negatively affect more efficient and coordinated infrastructure investments enabling a faster and better transition. On the contrary, a better linkage between the TYNDP and NDPs would allow transnational exchange of information on expected transmission systems usage and developments based on joint scenarios. This aspect in particular is linked with Problem Area I and II because a harmonised system development strategy would also provide the possibility to valorise stranded assets to transport decarbonised gas or hydrogen. 2.3.1.1Driver 1: Network planning varies between Member States and TSOs, separate planning for electricity and gas Member States are not required by EU law to develop a national network development plan, if the TSO is certified as ownership unbundled. Therefore, network plans do not exist in all Member States. The TYNDP covers in principle only cross-border infrastructure and is of lower granularity. Additionally, in about 74% of Member States there is either a methane NDP or no NDP at all, while only in two cases a cross-sectoral approach is taken. Planning on national level is hence based on sectoral needs, and, in contrast to the requirement of joint scenario building between gas and electricity at EU level, can be even based on different scenarios used for different energy sectors. Uncoordinated planning risks that synergies between different sectors are not exploited leading to inefficient investments. 2.3.1.2Driver 2: No transparency on potential of existing infrastructure for repurposing or decommissioning. While it is expected that demand for natural gas will decrease significantly, infrastructure of one sector, e.g. gas, may provide services for transporting energy to the benefit of another sector (e.g. electricity) and hence reduce overall infrastructure investments. Current development plans focus on the identification of additional investments, while neglecting information on which infrastructure may not be required anymore in the future. Additionally, without providing this information, the impact on energy security of Member States downstream of the Member State where infrastructure is planned to be used for another purpose or would be decommissioned could be negatively affected. 2.3.1.3Driver 3: DSOs not explicitly included in TSO planning Current planning practices and obligations on gas TSOs and DSOs to cooperate on network planning vary significantly across Member States leading to suboptimal information provision for planning purposes. Some Member States have obligations for the TSO(s) and DSO(s) to cooperate e.g. in order to define the most appropriate level for connection of new biomethane plants. ACER and CEER (Council of European Energy Regulators) note that while TSOs generally provide or publish information on the network and DSOs on connections, the level of information sharing varies per country and usually there is no obligation for the TSO to take the information from DSOs into consideration. In some countries combined transmission and distribution system operators exist, such as in Denmark (Energinet) and Luxembourg (Creos). However, most EU Member States have separate operators for gas transmission and distribution networks. 2.3.2How will the problem evolve? Electricity and gas are already interlinked mainly by gas-to-power assets. However, with power-togas assets, such as electrolysers, the interlinkages between electricity and gases including hydrogen is expected to become more integrated. The TEN-E proposal already includes the requirement of joint scenario building as well as hydrogen as new infrastructure category. Although hydrogen infrastructure is part of the TYNDP, the TEN-E proposal does not require the inclusion in the national plans. Moreover, the implementation of a joint scenario, as described in Section 2.3.1, requires minor changes to the Electricity Directive, e.g. in respect of joint scenario building and involvement of all transmission system operators irrespective of the unbundling model that will equally need to apply to electricity to implement a more sector integrated approach on national level. Without aligning national electricity network planning with gas, the problem of inconsistencies between both, the national and European level planning and between the sectors could evolve into even more inconsistencies as a result of joint scenario building on EU level. Without reflecting a higher degree of integration and coordination, the problem of different approaches to network planning and little information on planned decommissioning or repurposing entails the risk of leading to more inefficiencies, both in terms of sector integration, but also for the integration of renewables gases in the methane-based infrastructure. 2.4Problem Area IV: Low level of customer engagement and protection in the green gas retail market 2.4.1Problem: Insufficient customer protection, lack of participation and rigid competition make the green methane gases difficult to access the retail market For new gases to play a full role in the energy transition, the retail market rules should empower customers to make low carbon choices. This is not currently the case. Retail gas markets exhibit market concentration and low levels of new entry and innovation. This prevents customers from benefiting from competition by making low carbon choices. Moreover, as the increase in natural gas prices occurring in autumn 2021 shows, a sharp increase in the price of natural gas can have a significant impact on consumers. The possibility of a resurgence of such a price increase cannot be excluded over time. It is therefore important to take into account the extent to which the contemplated measures can help to prevent and mitigate this price volatility in the future and ensure access to energy as an essential service, in line with the European Pillar of Social Rights. 2.4.1.1Driver 1: Untapped competition potential in retail markets Limited competition in many Member States explains poor customer satisfaction and engagement in the gas market as well as slow uptake of new gases. In spite of falling prices in wholesale markets, gas prices for household customers rose between 2010 and 2019. Industrial customers pay, in general, two to three times less for their gas than household consumers . Non-targeted price regulation still exists in at least 14 out of 27 gas household markets and in the non-household market in at least Portugal, Slovakia, Hungary and Bulgaria. Price regulation – particularly with low or negative mark-ups – hinders entry by suppliers of new products, notably green gases, and can result in consumer disengagement. Low mark-ups may even lead to market foreclosure in Latvia, Hungary, Romania, Croatia, Bulgaria, Slovakia and Poland. Household gas markets continue to be more concentrated than industrial and commercial markets indicating high entry barriers for new suppliers particularly of renewable and low carbon gases. While consumer choice has widened in recent years, a closer inspection reveals that variety of offers in Member States are mainly fixed offers. The offer and uptake of other, more innovative products, remains limited. In 2019, ‘green’ gas offers were available in only seven out of 25 screened Member States. Countries with a more liberalised retail market tend to have a higher percentage of ‘green’ offers. 2.4.1.2Driver 2: Insufficient customer empowerment in terms of switching, price comparison tools, billing information, energy communities, and access to data. To be able to make sustainable energy choices, customers need sufficient information on their energy consumption and origin, as well efficient tools to participate in the market. Today customers are not sufficiently engaged in the gas market, which still lags behind on consumer protection compared to the electricity sector, especially with regards to bills and billing information, switching and price comparison tools. Consumers face particular issues in understanding the basic information in their energy bill. There is a high divergence in particular in the internal market regarding information on sources of energy and historical consumption.

Switching is an important indicator. Without this pressure, there is no incentive for suppliers to compete for customers, notably by offering renewable or low carbon options. Switching rates in some countries are still below 1%, which may be attributed to consumer inertia and aggravated by further price increases due to decarbonisation,. Consumers often encounter difficulties to understand the terms and conditions of their energy contracts, especially with regard to termination, as exit and termination fees discourage consumers switching. Source: (CEER, 2018) Price comparison tools (PCTs) facilitating consumer engagement are inconsistently developed among Member States and customers. Even where available, comparison may only be possible based on price rather than renewable credentials. Malpractices (e.g. default offers, misleading language) prevent consumers from access to clear, independent, and free of charge information about their gas supply. The creation of energy communities can be a solution to enhance public acceptance of renewable gas (projects). However, today, the number of energy communities operational on the green gas market is still limited despite their potential to contribute to the uptake of renewable energy. This may be attributed to a variety of general and renewable gas-specific barriers,. The enabling framework for ‘renewable energy communities’ (REC) in the Renewable Energy Directive 2018/2001/EU does not facilitate a majority of shareholders/members distant from production sites (e.g. in cities) buying renewable and low-carbon gases, and does not fully tap into community potential for bringing more volume or less costly renewable and low-carbon gas to the system,. Limited access to smart metering and to data can also contribute to low engagement by consumers. Smart metering help customers manage energy consumption and supports energy efficiency. It also improves billing accuracy - one of the largest sources of consumer complaints . Currently, the business case for gas smart metering remains more challenging than that for electricity, and as a result, its deployment is limited and is progressing at a slow pace across the EU. Existing legislation lacks rules on data management to govern processes by which data is sourced, validated, stored, protected and processed and by which data can be accessed by suppliers or customers . This is market entry barrier for new entrants. The necessity to adapt to different data management models for each national market has an impact on the resources of potential market newcomers. The fact that not all countries have rolled out smart meters yet also creates significant differences in the availability and accessibility of data. 2.4.1.3Driver 3: Inadequate consumer protection in particular for vulnerable and energy poor The EU’s increased climate ambition will result in low income households across the EU bearing a relatively higher burden in terms of heating fuel expenses compared to wealthier households. In 2019, natural gas accounted for 32% of the EU final energy consumption in households, the highest energy source. 64% of energy use by households was for home heating where demand is prices inelastic. Gas decarbonisation is likely to result in further price increases. There is currently a mismatch of energy poverty and vulnerable customers coverage across internal energy market legislation. This results in a lack of coherence with other EU interventions in the wider energy and climate domain. Protection of gas consumers also relies on the availability of effective means of dispute settlement. All Member States, except Cyprus, have implemented an Alternative Dispute Resolution (ADR) mechanism for both electricity and gas, in most cases free of charge for final household customers. However, there are still varying levels of available mechanisms and information on how to access such mechanisms – for example legal maximum processing times vary substantially across MSs and can reach up to six months. 2.4.2How will the problem evolve? The identified gaps in all customer empowerment and protection areas, including switching fees, market-based prices, basic contractual rights, vulnerable consumers, and energy communities are likely to worsen if not properly addressed. Both the legal framework and energy policies should, thus, be improved where needed to constantly protect and empower customers, namely households. This should be pursued still in a flexible way to adapt to the changing energy landscape and technologies, while respecting national features, where suitable. 2.5Interdependencies between problem areas All problem areas are connected in that they concern the rules affecting (wholesale and retail) markets and infrastructure for gases that are necessary for enabling the energy transition. By readying these rules for the changes that replacing fossil gas with decarbonised alternatives will bring, a system is created whereby renewable and low carbon gas producers can use networks and wholesale markets and challenge incumbents for access to consumers across the internal market and consumers can benefit from functioning (retail) markets across the EU and renewable and low carbon gases. At a more granular level: -Problem Areas I and II are connected in some sub-areas, notably terms of infrastructure and infrastructure operators and tariffs and governance structure; -Problem Areas II and IV are connected as both concern methane wholesale and retail markets. Such connections are less pertinent for Problem Areas I and IV as hydrogen retail customers are few and likely larger and more sophisticated; -Problem Area III is linked to Problem Areas I and II as it adapts the network planning at national level to the integrated approach introduced in the TEN-E Regulation at the EU level. 2.6Evaluation Conclusions from the Evaluation and treatment in this Impact Assessment.

2.6.1Problem Area I The entry into force of the Third Energy package has positively contributed to competition and performance of the internal energy markets. However, the current regulatory framework for gas focuses on fossil-based natural gas and does not anticipate the emergence of gases and infrastructure for alternatives to methane, in particular hydrogen and hydrogen infrastructure. The Evaluation thus concluded that a re-examination of the current gas market regulatory framework is therefore needed. Given the different potential in EU Member States for the production of renewable and low carbon hydrogen, a suitable market framework could facilitate hydrogen to play its role as an energy carrier and as an enabler of energy system integration in the EU. On these basis, four main drivers have been identified under Problem Area I of the Impact Assessment. 2.6.2Problem Area II 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. Accommodating higher shares of renewable and low-carbon gases in the system poses also new challenges that were not originally foreseen by the Third Energy Package. The growing volumes of biomethane, hydrogen but also LNG affect gas quality and thereby the design of gas infrastructure and end-user appliances. In particular, this Impact Assessment recognizes five main drivers related to renewables and low carbon gases emerging role in the existing infrastructure and markets. 2.6.3Problem Area III Concerning network planning, the Evaluation states that under the Third Energy Package cooperation between TSOs and the national regulatory authorities has improved, but needs to evolve further. The increasing penetration of intermittent energy sources, on the contrary, requires the whole energy system, both markets and infrastructure planning, to be better integrated. The progressive integration and emergence of new energy markets characteristics, means that infrastructure becomes more interconnected. A more holistic and inclusive approach to infrastructure network planning may therefore be required for system operators, as opposed to the largely silo-based current practices. The Impact Assessment outlines three main drivers regarding this Problem Area. Furthermore, a more harmonised system development strategy would further increment interlinkages between electricity and gases systems including hydrogen. 2.6.4Problem Area IV The evaluation showed that competition still needs to significantly improve to ensure that the full benefits of market integration are passed on to EU consumers. Furthermore, consumers are still deprived from the necessary tools to get actively involved in the market, including fast switching procedures, independent comparison tools, transparent gas bills, and gas smart metering. Consumer protection provisions in the analysed legislation prove to only be partially fit for purpose. In particular, protection for vulnerable customers is still uneven between Member States and energy poverty continues to be significant across the EU and the years leading to climate neutrality will require solid safeguards to ensure the energy transition leaves no one behind, meaning that energy poverty alleviation measures will need to be strengthened. Concordantly, Problem Area IV identified three problem drivers. For a more detailed analyses of the manner in which the conclusions of the Evaluation have been taken into account, reference is made to Annex 11. 3Why should the EU act? 3.1Legal basis The planned measures of the present initiative seek to advance the four objectives set out in Article 194 TFEU, while at the same time contributing to the decarbonisation of the EU’s economy. The planned measures are to be adopted on the basis of Article 194 (2) TFEU together with Article 114 (1) TFEU. In the field of energy, the EU has a shared competence pursuant to Article 4 (2) (i) TFEU. 3.2Subsidiarity: Necessity of EU action To achieve EU decarbonisation goals it will be necessary to gradually replace natural gas by decarbonised energy carriers including electricity, renewable heat and decarbonised gases. The speed and scope of this transition, including how much of which gaseous fuels will be part of the energy mix, will depend on the chosen decarbonisation pathway and the deployment of other policy instruments. However, the current regulatory framework for gas focuses on natural gas and does not anticipate the emergence of alternative methane gases, such as bio-methane, or other gaseous fuels, such as hydrogen. Currently, there are no rules at EU-level regulating dedicated hydrogen networks or markets and LCH and LCFs. In view of the current efforts at EU and national level to promote use of renewable hydrogen as a replacement for fossil fuels, Member States would be incentivised to adopt rules on the transport of hydrogen dedicated infrastructure at national level. This creates the risk of a fragmented regulatory landscape across the EU, which could hamper the integration of national hydrogen networks and markets, thereby preventing or deterring cross-border trade in hydrogen. Harmonising rules for hydrogen infrastructure at a later stage (i.e. after national legislation is in place) would lead to increased administrative burden for Member States and higher regulatory costs and uncertainty for companies, especially where long-term investments in hydrogen production and transport infrastructure are concerned. When it comes to biomethane, without an initiative at EU level, it is likely that by 2030 a regulatory patchwork would still exist regarding access to wholesale markets, connection obligations and TSO-DSO coordination measures. Likewise, without some harmonisation at the EU level, renewable and low-carbon gas producers will be facing vastly different connection and injection costs across the EU, resulting in an unequal playing field. Without further legislation at the EU level Member States would continue to define gas quality specifications based on the quality parameters of natural gas. Therefore, biomethane producers would also in the future need to adapt to this quality at additional cost. The rules on hydrogen blending would be left to the Member States without the definition of allowed hydrogen blending levels at cross-border interconnection points.

All these aspects are likely to lower cross-border trade with renewable gases that might be compensated by higher natural gas imports. The utilisation of the LNG terminals and imports could remain restricted to natural gas, despite that no adaptation of LNG terminals would be necessary in case competitive biomethane or synthetic methane from non-EU sources were available. Without adjusting the national planning provisions, there is a risk that NDPs and the TYNDP (which builds on NDPs) become inconsistent. Member States may decide to adapt their national plans, but without EU’s action it cannot be ensured that all NDPs follow the same basic framework. Ensuring consistency between EU and national network development planning is of Union relevance as it cannot be achieved in an efficient way only on the basis of the European plan due to a lack of more detailed information on network level. Close interaction and informed decisions based on local circumstances are required. It is therefore necessary that the methodology and overall framework for the European planning process and the national planning is consistent with each other. Moreover, an EU-wide framework for introducing competition on methane retail markets and enabling consumers' choice is beneficial for providing level playing field for energy producers and suppliers as well as to benefit the consumers. Harmonised approach to metering and billing as well as consumer protection provisions safeguard the level playing field for suppliers and provide equal rights for energy consumers. It also facilitates providing cross-border services. The current framework for ensuring gas supply security will not be adequate for the needs and threats of the future decarbonised gas system. Uncoordinated national emergency preparedness for the new gases risks undermining their effectiveness in case of disruptions. The EUCJ ruling of 15 July 2021 (Case C-848/19) confirmed the need to consider security of supply and energy solidarity in Commission's initiatives. 3.3Subsidiarity: Added value of EU action The initiative aims at modifying existing EU legislation and creating a new framework for an internal hydrogen market, which is key to achieve a cost efficient clean hydrogen economy. The challenges cannot be addressed as efficiently by individual Member States as fostering more efficient and integrated EU markets for gases requires harmonised and coordinated approaches by all Member States; which can only be achieved by EU action. The initiative is also aimed at avoiding the distortive effects of uncoordinated, fragmented policy initiatives as many Member States develop national approaches e.g. with regard to hydrogen deployment. EU action has significant added-value by ensuring a coherent approach across all Member States and towards third countries, as achieving the decarbonisation objectives of the EU may require imports of renewable and low carbon gases from third countries. The initiative on decarbonised gases also contributes to achieving binding EU-level objectives. The EU has already committed to achieving a share of at least 32% of renewable energy sources in total energy consumption by 2030 and has issued an ambitious strategy for the deployment of hydrogen to reach 40GW of installed electrolyser capacity by 2030. The European Commission has recently proposed to cut net greenhouse gas emissions even further by at least 55% compared to 1990 levels by 2030, up from the current target for 2030 of at least 40%. The greenhouse gas emissions reduction target of 55% is assessed to lead to a share of renewables of between 38% and 40%. Gaseous fuels will continue to provide an important share of the energy mix also by 2050, requiring the decarbonisation of the gas sector via a forward-looking design for competitive decarbonised gas markets. Consequently, the objectives of this initiative cannot be achieved only by Member States themselves and this is where action at EU-level provides an added value. As regards hydrogen, the creation of regulatory framework at EU-level for dedicated hydrogen networks and markets would foster the integration and interconnection of national hydrogen markets and networks. EU-level rules on the planning, financing and operation of such dedicated hydrogen networks would create long-term predictability for potential investors in this type of long-term infrastructure, in particular for cross-border interconnections (which might otherwise be subject to different and potentially divergent national laws). EU coordinated emergency preparedness for the current gas sector has proven to be more efficient than action only at national level. 4Objectives: What is to be achieved? 4.1General objectives General policy objective Contribute to the EU’s decarbonisation within the framework of the Fit-for-55 package to implement the European Green Deal in a cost-effective manner by facilitating the creation of a European hydrogen market and the gradual decarbonisation of gaseous fuels markets 4.2Specific objectives Problem Area Objective Sub-objectives I Facilitate the emergence of an open and competitive EU hydrogen value market -Enable the emergence of an efficient, integrated EU hydrogen market -Remove barriers and ensure incentives to invest in hydrogen infrastructure -Address risk that the natural monopoly character of hydrogen infrastructure gives rise to non-competitive market structures. -Ensure cross-border integration (including on borders with third countries), unhindered hydrogen (cross-border) flows and required hydrogen quality for end-users II Ensure access of renewable and low carbon gases to the existing methane networks and markets and their security of supply -Facilitating access of local production of biomethane to the gas markets across EU -Facilitating connection rules and injection -Ensuring access to LNG terminals for RES&LC gases -Ensure unhindered cross-border flows for RES&LC gases -Tackle risk of negative impact on end-users in terms of gas quality -Avoid lock-in into LTCs for natural unabated gas -Improve the resilience to relevant threats of the future gas system integrating renewable and low carbon gases III Ensure transparent and inclusive infrastructure planning -Provide transparency for repurposing existing gas networks -Enable cost efficient planning on the basis of scenarios that are in line with the climate target objectives IV Give consumers tools to choose the cheapest decarbonisation options -Increase competition in retail renewable and low carbon gas markets by also addressing price regulation -Strengthening consumer engagement in such market -Ensure an adequate level of consumer protection 5Available policy options The policy options investigated in this Impact Assessment are packages structured around more detailed sets of measures that reflect different depths of the regulatory intervention for creating markets for gases that enable the energy transition. The policy options hence represent political choices going from a lighter to a more detailed/stringent regulatory framework. Each of these packages reflect different sets of more detailed policy measures (summarised within this chapter for each Problem Area but also described in more detail in the Annexes) that seek to address the problem and its underlying drivers.

5.1Options in the Problem Area I: Hydrogen infrastructure and markets 5.1.1Baseline Today, about 1600 km of hydrogen transportation infrastructure exists. It is fragmented with few cross-border connections. The conditions under which these networks have been built, sized and are used are negotiated between hydrogen producers and, mostly, industrial consumers. Other infrastructure, such as large scale storage and import terminals for liquefied hydrogen do currently not exist within the EU. The baseline represents the unregulated status of the EU hydrogen infrastructure and market. It assumes adopted and planned policy initiatives under the Fit for 55 package to contribute to the development of renewable hydrogen production and demand. Accordingly, the projections of hydrogen supply and demand under the baseline are derived from the MIX-H2 scenario. In addition, the proposed funding of cross-border hydrogen infrastructure as well as its integration in infrastructure planning under the TEN-E regulation will promote cross-border hydrogen infrastructure development under the baseline. However, there are no (additional) rules on the ownership, operation and financing of hydrogen infrastructure under the baseline. Moreover, there is no common EU terminology and certification system for LCFs/LCH. These rules are however deemed necessary to enable cross-border hydrogen trade. Cross-border trade is needed as locations for a cost effective and high volume production of (renewable) hydrogen production are unlikely to be located next to existing demand centres. Whilst Member States will likely take initiatives based on national strategies and approaches to enable hydrogen trade, these efforts are expected to be dispersed under the baseline scenario, resulting in uncoordinated and weak cross-border integration and transportation infrastructure development. As geological and geographical circumstances vary among Member States, some will have no or limited access to large-scale hydrogen storage and import facilitates under the baseline scenario. 5.1.2Description of policy options In order to address the problem and its drivers as set out in Chapter 2 and in order to realise the objectives as defined in Chapter 4, different packages of policy options are considered. The detailed measures considered to be part (or not) of a given policy option are summarised in Table 5 . In Annex 6, more detailed descriptions of each of these measures and their specific advantages and disadvantages are provided. Please note that certain hydrogen related issues are also dealt with under Problem Area II and III, in particular on cross-cutting issues as SoS and network planning. 5.1.2.1Option 0: Business as Usual (BAU) In BAU, there are no rules or restrictions at EU level on the ownership or operation of hydrogen infrastructure, or its financing. Infrastructure is operated by unregulated companies that can combine hydrogen production and supply activities with the operation of infrastructure without rules on potential market foreclosure. They can set conditions (if any) for the operation of and access to infrastructure freely and guided solely by the business interests as perceived by the companies concerned. LCH and LCFs are not defined or certified. Stakeholders' opinions: In the public consultation a large majority of respondents, mainly companies/business organisations, business associations and half of the public authorities that responded, support the introduction of regulation to foster a well-functioning and competitive hydrogen market and hydrogen infrastructure. None of the respondents stated that there is no need for regulation at all. A majority of stakeholders takes the view that LCH and LCFs should be defined and that the claims about their contribution towards decarbonisation should be verified. However, stakeholders had diverging views on how this should be done. 5.1.2.2Option 1: Rights for network operation tendered As under BAU, there are no rules or restrictions at EU level on the ownership or operation of infrastructure, or its financing. However, under this option Member States would tender the rights for investments in and the operation and ownership of future hydrogen networks to market participants (including existing gas TSOs). The successful bidder would be granted a regional monopoly position, e.g. on national level or for a local network within Member States or, possibly even, for a specific pipeline or other type of infrastructure, under which the bidder could build and operate it and supply hydrogen customers or, if it chooses to do so, offer infrastructure usage to third parties. The tendering may include conditions or principles set at national level to reflect certain public interests. However, these will not be harmonised by EU rules. This option thus represents a form of ‘competition for the market’. Concession holders may or may not have interests to foster within the EU or with third countries cross-border interconnection and interoperability, including e.g. ensuring that acceptable and required hydrogen purity levels are addressed, to the extent this is compatible with their business interests, which can include upstream and downstream business. Stakeholders' opinions: In the public consultation, only a minority of respondents, composed by three business associations, one public administration and one company/business organisation, supported this option. Respondents who supported the introduction of regulation for hydrogen markets and networks, stated that a suitable regulatory model should be developed at EU level rather than at national level. 5.1.2.3Option 2: Main regulatory principles This option entails the introduction of main regulatory principles that are inspired by those that are applicable to the natural gas (and electricity) markets. Option 2 in essence represents a choice for a ‘competition in the market’ approach (as opposed to a ‘competition for the market’ under BAU and Option 1), but regulation does not have the same depth and scope of the market design of the mature natural gas market. Instead, option 2 reflects a more modest, first step approach. Setting main principles would provide guidance as to investors and operators in what regulatory framework they would act and thus provides investor certainty. However, main regulatory principles would still leave ample scope to investors and operators to develop and test a variety of business models therein. In this manner, it seeks to take account of the uncertainties that still exist at this stage as to the precise pathway the development of the hydrogen value chain will take. If and when required when it fall short of expectation, a regulatory system based on main regulatory principles can be fine-tuned later ‘merely’ by rendering it more specific in certain areas. Under this option, the natural monopoly character of hydrogen networks is countered through rules that impose constraints on its owners. These include the unbundling of transportation from supply and production activities (vertical unbundling) and rules that govern access for third parties (TPA) to networks. Cross-border integration, including with third countries, is fostered by communality of main regulatory principles but also specific ones, such as rules on the quality of hydrogen at cross-border points or a rules on common EU terminology and certification system for LCFs/LCHs. Similarly, repurposing infrastructure is facilitated to a degree by EU rules. Hydrogen infrastructure can be developed by both private investors and regulated entities, like todays TSOs. The main regulatory principles would necessitate corresponding powers and competences of national regulatory authorities (and, where appropriate, of ACER) to ensure adequate implementation and monitoring at national level. Stakeholders' opinions: A large majority of respondents, including companies/business organisations, business associations and half of the public authorities that responded, supports the ‘competition in the market’ approach and believe that a common approach is needed to define key regulatory principles (such as neutrality of network operation, third party access, cost reflective and market compatible network tariffs, treatment of private networks) as networks can represent a natural monopoly, even if stakeholders have different views on the depth and scope of the rules needed. A step-wise approach is largely supported. Under Option 2: two sub options are distinguished that both share the characteristics set out above but are different with regards to the requirement they impose on market participants and the degree in which they provide guidance or define a longer term perspective on the regulatory framework for hydrogen infrastructure and markets. I.e. Option 2a and 2b they represent different manifestations of a step-wise approach based on main regulatory principles.

5.1.2.3.1Option 2a: Main regulatory principles only Whilst inspired by the rules for the natural gas sector, under Option 2a the main regulatory principles are adapted to the specificities of a developing hydrogen value chain. Options 2a defines the main regulatory principles that would apply during the ramp-up phase of a hydrogen value chain until 2030, it does not look what rules may be required once it reaches a more mature development stage. Under sub-Option 2a, existing natural gas TSOs are relatively unconstrained in being involved in and build out a hydrogen network, including through repurposing the natural gas assets they currently manage. In order to ensure the emergence of a competitive market structure, negotiated TPA to hydrogen networks and large scale hydrogen storage is introduced. Negotiated TPA provides flexibility in infrastructure financing options (relative to regulated TPA). No TPA at all is required for hydrogen terminals to reflect the fact that, as the means by which hydrogen and its derivatives can be imported are wider in scope than for today’s natural gas terminals, it is more likely that hydrogen terminal operators will be subjected to effective competition and less need for regulation exists. Large volumes of imports do not exist yet by 2030 under the scenarios used. Gas TSOs can operate hydrogen networks under the same rules for vertical unbundling as in the natural gas sector. Some measures are taken to facilitate investments in existing infrastructure by stimulating the grandfathering of existing rights and permits of methane infrastructure when repurposed to hydrogen infrastructure. Gas TSOs can finance and de-risk hydrogen infrastructure investments by using (regulated) revenues from the natural gas side of their business (including revenues collected through cross-border tariffs from network users in other Member States) without constraints (joint-RAB). Private parties can invest and operate hydrogen infrastructure under exemptions. Such investments can take place without specific measures that ensure a future convergence on a single regulated regime within a progressively inter-connected hydrogen network. Cross-border operation, in particular hydrogen quality, is assured by the same rules as those that exist today for natural gas, including a dispute settlement procedure with the involvement of the concerned regulatory bodies. For LCH and LCFs, a common EU terminology and a light GOs-based certification system for LCFs/ LCH) would be introduced. Main regulatory principles apply to interconnections with third countries on the EU territory. There are no specific consumer protection rules beyond the main regulatory principles (such as TPA) reflecting that early users of hydrogen are larger, more sophisticated consumers, unlike the more varied customer base for natural gas (that also includes SMEs and households). Stakeholders' opinions: A significant majority of stakeholders that gather companies/business organisations, business associations, NGOs and half of the public authorities, academia and citizens that responded consider it very important that TPA to dedicated hydrogen network is set at an early stage (but their preference is for regulated TPA). Most stakeholders (including companies/business organisations, business associations, public authorities, academia and half of the NGOs that responded) consider that, appropriate measures are now required on imports and a significant majority supports rules for access to hydrogen terminals. A large majority of respondents composed by companies/business organisations, business associations, NGOs, academia and public authorities consider it important or very important to define market rules for access to storage for (pure) hydrogen at an early stage and it should entail a choice between negotiated and regulated access. The vast majority of stakeholders, including companies/business organisations, public authorities, some NGOs and half of the business associations that responded consider it important or very important to set rules at an early stage to ensure the neutrality of hydrogen network operations (i.e. vertical unbundling) and that network operations should be in a distinct legal entity (coherent with the current Independent Transmission Operator (ITO) unbundling model) or ownership unbundled. With regard to repurposing, a majority of respondents (companies/business organisations, business associations, and half of public authorities that responded) consider it necessary to clarify whether rights of land use, private easements as well as the validity of public permits that have been granted for the construction and operation of methane gas pipelines continue to be valid when these are used for hydrogen. Respondents are divided on whether cross-subsidies between hydrogen and natural gas transport activities should be allowed (separate versus joint RAB). Half of the respondents (mainly incumbent natural gas TSOs, DSOs and industrial energy consumers) are in favour of (partial) cross-subsidisation to ensure the development of dedicated hydrogen networks. Most respondents, gathering the majority of companies/business organisations, business associations, NGOs, public authorities and half of the academia that responded, considered it important or very important to define early the role of private parties in developing hydrogen infrastructure. However, few supported that this should be done unconditionally and without ensuring regulatory convergence. A quarter of respondents (composed by companies/business organisations, business associations, public authorities and academia) specifically support establishing hydrogen quality (purity) standards at Member State level with EU-level cross-border coordination rules. There is strong support for establishing rules on roles, responsibilities and cost-allocation for the management of hydrogen quality at EU-level. With regard to LCHs and LCFs, answering to a poll during the first stakeholder workshop, 38% of the respondents took the view that the RED II certification scheme should be extended to LCH and LCFs. 23% of the respondents think that GOs should become the only verification of a compliance system. Very few stakeholders (mainly represented by companies/business organisations, business associations and some NGOs) support the view that the main regulatory principles by themselves provide sufficient consumer protection. 5.1.2.3.2Option 2b: Main regulatory principles with a vision Option 2b is similar to 2a in that it is built on the main regulatory principles governing the current natural gas market. However, it seeks to provide more guidance as to the direction into which the regulatory framework will develop in the future whilst retaining flexibility in the transition in order to take account of the emergent nature of the hydrogen value chain today and the uncertainties surrounding its development. It also takes better account of some of the lessons learnt from the liberalisation of the gas and electricity sectors and takes advantage of the fact that it is possible to take a ‘greenfield’ approach to regulation, in which choices aimed at creating a competitive market can still be made unconstrained by an entrenched factual or regulatory situation (unlike when liberalising the than already mature gas and electricity markets). Thus, while still representing a light regulatory regime based on the main regulatory principles as the natural gas market, Option 2b takes the adaption to the characteristics of the hydrogen value chain a step further and provides more guidance as to its future. In comparison with Option 2a, Option 2b represents a real step-wise approach that both provides a regulatory framework for the ramp-up of a hydrogen value chain until 2030 as well as a perspective on the main regulatory principles that will govern a more mature hydrogen value chain beyond 2030. Like Option 2a, it remains limited to setting the main principles that provide guidance as to investors and operators in what regulatory setting they would act whilst leaving ample space to develop suitable business models within this context. It thus provides more regulatory certainly without however sacrificing degrees of freedom to investors and operators to develop new business models. Like under Option 2a, under Option 2b the natural monopoly character of hydrogen transportation infrastructure is countered through rules that impose constraints on infrastructure owners. With regard to TPA to hydrogen networks (including cross-border interconnectors and interconnections with third countries) a stepwise approach is envisaged where negotiated TPA remains possible during a transition phase to provide flexibility (like under Option 2a) but where regulated TPA and tariffs would be phased-in later. Learning from the past, it seeks to avoid the ‘pancaking effect’ that currently characterises the natural gas system by prohibiting cross-border tariffs, thereby setting the stage for an EU hydrogen market with a true level playing field later. For large-scale storage, Option 2b entails a relatively strict regime of regulated TPA from the start, in accordance with stakeholder views. In view of the intermittency of renewable hydrogen production but the need to provide stable supply to (industrial) users, access to storage will be commercially crucial for hydrogen producers. However, large-scale storage will be scarce (especially at the ramp-up stages) and available only in certain Member States, due to geological conditions. Import terminals will under Option 2b not be left fully unregulated (like under Option 2a) but subject to a relatively light regime of negotiated TPA. To benefit from the ‘greenfield’ nature of hydrogen infrastructure regulation and the fact that vertical integration today is rare, a stepwise but relatively strict approach is taken under Option 2b with regard to vertical unbundling of networks. In the transition phase, the ITO model can still be used by the current natural gas TSOs that want to repurpose their assets for hydrogen transport. However, after this transition phase, hydrogen network operators are either ownership unbundled or the networks of vertically integrated operators are governed by an independent system operator (ISO), which can already be made available in the transition phase but is than not yet obligatory. Like under Option 2a, private investors can invest and operate infrastructure. However, guarantees are built in to foster convergence and avoid the persistence of divergent regulatory regimes within the later inter-connected network. Existing private networks can also opt-in into the regulated system. Facilitating networks development will not only be done by facilitating the repurposing of existing infrastructure (like under Option 2a), but also by ensuring that permitting and land-use rights for new infrastructure at national level are at least equivalent to those applicable for natural gas infrastructure. This to avoid bias in the feasibility of infrastructure projects and lock-in. With regard to the asset base of regulated entities, the default rule is a separation of hydrogen and gas network asset bases (separate RABs) and cost-reflective tariff setting. However, flexibility is provided by an option of (temporary) financial transfers between the natural gas and hydrogen asset base (financed by domestic natural gas network users only and subject to conditions). This allows cost-reflective tariffs setting but also hydrogen network operators to stabilise tariffs for hydrogen network users in the ramp-up phases of a hydrogen network whilst avoiding that this is paid for by network users in other Member states. This approach implies the need for (at least) horizontal accounts unbundling between natural gas and hydrogen network activities. Using the green field nature of hydrogen infrastructure regulation and the fact that technical standards already exist for hydrogen end-applications, Option 2b establishes an EU-wide acceptable purity level for cross-border points in order to foster cross-border interoperability. Further, this option would include cross-border dispute settlement tools and increased transparency as under Option 2a. With regard to LCH and LCFs, this option also provide a common terminology but (unlike Option 2a) certification will be based on life-cycle analyses and a mass-balance approach through voluntary schemes. The application of main regulatory principles to the entire interconnectors with third counties is assured through the need to conclude an Intergovernmental Agreement (IGA). A light regime of consumer protection rules will exist, reflecting the fact that early users of hydrogen are likely more sophisticated and need less protection. It will be aligned with those valid for the natural gas system in order to make sure that switching decisions are made on the basis of economic opportunity as opposed to regulatory bias.

Stakeholder’s opinions: A large majority of respondents, that gather companies/business organisations, business as