Comments made by RSB in Opinion of 17 September 2021

Modifications made in reaction to comments RSB

The conclusions of the evaluation should be fully integrated into the problem description. The report should address both the conclusions related to decarbonisation as well as those related to market issues.

All elements listed in Annex 3 of the Evaluation (the list of articles of the Directive and Regulation) are addressed in the revision set out in the Impact Assessment.

To clarify this better in the Impact Assessment, it has been rendered transparent which areas listed in Annex 3 of the Evaluation are addressed by which option in the Impact Assessment. In particular, a new annex (Annex 11) has been added that contains a detailed table based on Annex 3 of the evaluation indicating where it is covered in the Impact Assessment.

A new section on the evaluation has been added in Chapter 2.

The problem definition should address how the initiative shifts the nature of energy security towards resilience.

The report should clearly spell out the role of the initiative as part of the enabling framework of the Fit for 55 package.

Chapter 1 and Annex 12 have been improved in order to spell-out the role of the present initiative within the Fit for 55 package and the interactions with its various components.

The report should explain why there is no common approach on the baseline between follow-up initiatives to the July Fit for 55 package. It should better describe how its baseline integrates the already proposed Fit for 55 initiatives.

In Section 1.5 (alignment with the Fit for 55 Impact Assessment), Section 5.1.1. (baseline for Problem Area I) and Annex 4 (analytical methods) it is explained what the baseline actually represents.

In addition, it is explained how the baseline relates to the use of common demand and supply assumptions in both this Impact Assessment and the one underpinning the already proposed Fit for 55 initiatives (e.g. the proposal for a revision of the RED II Directive) by the common use of the MIX-H2 PRIMES as the point of departure. Lastly, Section 5.1.1 and Annex 4 explain that the intrinsic assumption on the existence of policy measures to ensure cross-border infrastructure under the MIX-H2 PRIMES scenario is the actual aim of the current proposal, but that it does not lead to a divergent baseline.

The report should clarify the differences between the baseline and Option 0 and explain which one is used as point of comparison for the impact analysis and why.

In Annex 4 (analytical methods) it is explained that there are no differences between the baseline and Option 0 and that it represents ‘an infrastructure policy scenario’ that is the benchmark against which the policy options for this proposal are tested. In order to clarify that Option 0 and the baseline are the same, the headings in Section 6.1.3 have been changed.

The report should be clear how the options were constructed and explain why certain measures are in one option, and not in another. The construction of the options should clearly reflect the main policy choices.

For each of the policy options as described in Chapter 5, we have clarified the main (higher-level) characteristics of each option and, when pertinent, links and phases with the underlying policy initiatives.

E.g. in Problem Area I, the links with the phasing and time scales of the EU Hydrogen Strategy have been emphasised.

Comparability between options has been improved by inserting summary tables in Chapter 5 that, for each problem area and option, with the more detailed measures they are comprised of. It has hence been made clearer how the options were constructed whilst rendering also the differences between them more clear and verifiable.

In the text for Problem Area II in Chapter 5, it was clarified that the options build on each other in terms of the depth of their applicability e.g. Option 3 includes elements of Option 2 and adds new measures. Option 4 includes all elements of Option 2 and 3 and adds new measures. We will also move Table 36 to the end of Chapter 5 and improve its readability.

In Problem Area III, options’ description have been clarified in terms of connection with other problem areas.

General section describing interdependencies between problem areas added in Chapter 2 and Section on synergies, trade-offs and sequencing added in Chapter 6.

Annexes 6 to 9 include details of each of the options in terms of more granular measures and present pros and cons of each of them in a transparent manner.

The impact analysis should distinguish more between different actors, in particular between natural gas and hydrogen producers and consumers.

This should include an assessment of the effects of the inbuilt flexibilities on different types of actors and a risk of fragmentation between Member States in the transition period.

It has been rendered clearer how the various options can (or cannot) can deal with the uncertainties inherent to the development of a new hydrogen value chain differ and how they differ in terms of the degrees of freedom they offer to investors and operators to develop business models and foster investments. The distinction in Problem Area I between Options 2 and 3, i.e. the difference between an approaches based on ‘main regulatory principles’ as opposed to a fully-fledged regulatory framework has been rendered clearer. The same applies to the consequences this entails for the scope to refine the regulatory system later if it falls short of expectations.

The report should provide an assessment of how the initiative may have different impacts for SMEs compared to other (larger) companies.

The report should clarify the legal delivery instruments foreseen for the measures contained in the preferred option.

We have included a more detailed assessment on how these initiatives may impact SMEs for each policy measure. See in particular Section 6.6.

Annex 11 provides clarity on what legal instrument is used to address a given concern.

The report should better reflect the dissenting and minority views throughout the report, including in the problem definition, the construction of the options, analysis of impacts and the choice of preferred option.

Boxes containing stakeholder’s views, such as those in Chapter 5 provide, for each option in all policy areas, what the majority and minority stakeholders views were and by whom they are held.

In Annex 3, which contains detailed reports on stakeholder feedback, more detailed explanation were included, especially for the part on the public consultation, on how the certain subgroups of stakeholders, including the minority views, responded to the analysed options in the Impact Assessment.

The narrative of the report should be significantly improved. It should be re-written so that a non-expert reader understands easily all the issues at stake and the policy choices to be made. The Glossary should be completed.

The report has been reread by non-experts and its readability improved. The Glossary has been completed.

The cost and benefit tables (in Annex 3) should be completed in the appropriate format.

The tables have been included and, in line with the better regulation guidelines completed as far as possible. Please note that quantifying results is not possible for all options and all Problems Areas.

Other technical comments.

Monitoring success

More details on the process of establishing monitoring indicators have been included in Chapter 9 of the Impact Assessment report.

Renewable and low carbon gases from third countries

The treatment of renewable and low carbon gases from third countries is now integrated in the problem definition and specific objectives. To the extent a problem was defined in their connection (this mostly concerns Problem Area I), we have assessment specific measures under the options in Sections 5 and beyond and added a detailed table regarding the treatment of interconnectors to third countries to Annex 6.

Social impacts

To the extent meaningful, the assessment of social impacts in Section 6.5 has been conducted for all options in all problem areas (and not only the preferred option).

Interdependency of the problem areas

We have now briefly described interdependencies in Section 2.5 and assessed synergies and trade-offs in Section 6.77 of the Impact Assessment.

Tables with over view impacts

We have adapted tables and replaced drivers with (sub-)objectives in the tables providing and the overviews of impacts for the options under each problem area and provided better explanations or legenda.

Options in Problem Area IV

The main document and the Annex with regard to Problem Area IV have been rendered clearer. For instance, a table setting out different options for different measures is now included under Section 5.4. The Annex also provides gives a general overview table with pros and cons.

Title of study

Study served to study/substantiate impact of

Contractor(s)

Published

The role of trans-European gas infrastructure in the light of the 2050 decarbonisation targets

Assessment of the role of Trans-European gas infrastructure in the light of the EU’s long-term decarbonisation commitments.

Trinomics

Published

https://op.europa.eu/en/publication-detail/-/publication/1796ecd6-cb71-11e8-9424-01aa75ed71a1/language-en

Impact of the use of the biomethane and hydrogen potential on trans-European infrastructure

Assessment of the potential of biomethane and hydrogen to contribute to the decarbonisation of the EU energy system, the impacts this will have on the gas infrastructure and the extent to which gas network operators and regulators are prepared to cope with these impacts.

Trinomics

LBST

E3M

Published

https://ec.europa.eu/energy/studies_main/final_studies/impact-use-biomethane-and-hydrogen-potential-trans-european-infrastructure_en

Potentials of sector coupling for decarbonisation, Assessing regulatory barriers in linking the gas and electricity sectors in the EU

Assessment of regulatory barriers and gaps preventing closer linking of the EU gas and electricity sectors (both in terms of their markets and infrastructure) and hindering the deployment of renewable and low-carbon gases, including cross-border aspects of gas quality and hydrogen blending.

Frontier Economics

CE Delft

THEMA Consulting Group

Published

https://op.europa.eu/en/publication-detail/-/publication/60fadfee-216c-11ea-95ab-01aa75ed71a1/language-en

European barriers in retail energy markets

Research the extent to energy suppliers across Europe face a variety of barriers to enter and compete in the market; to identify which barriers exist and to provide some suggested solutions to those barriers.

VaasaETT,

REKK

MRC

The Advisory House

Published

https://ec.europa.eu/energy/studies_main/final_studies/european-barriers-retail-energy-markets_en

Study on gas market upgrading and modernisation - Regulatory framework for LNG terminal

Identifying and describing exiting barriers and gaps that could be addressed in order to ensure optimal use of existing LNG terminals in the EU

Trinomics

REKK

Enquidity

Published

https://op.europa.eu/en/publication-detail/-/publication/efa4d335-a155-11ea-9d2d-01aa75ed71a1/language-en

Assistance to assessing options improving market conditions for bio-methane and gas market rules

Impact Assessment of options related to a regulatory framework for bio-methane, gas quality and network planning.

Artelys, Trinomics, Frauenhofer, JRC

Forthcoming

Sector integration – Regulatory framework for hydrogen

Identifying options related to a regulatory framework for hydrogen

Trinomics

LBST

Forthcoming

Assessment of policies for gas distribution networks, gas DSOs and the participation of consumers

Problem definition and Impact Assessment of pitons related to Problem Area II (access renewable and low-carbon gas) and IV (energy communities, smart metering)

Frontier economics

Forthcoming

Assistance to the Impact Assessment for designing a regulatory framework for hydrogen

Impact Assessment of options related to a regulatory framework for hydrogen.

Guidehouse, Frontier Economics

Forthcoming

Upgrade of METIS and studies on sector integration – Study S2 Gaseous Fuels

METIS study on challenges related to the integration of new gaseous fuels

Artelys

Forthcoming

Quo Vadis EU gas regulatory framework

The study ‘Quo Vadis EU gas regulatory framework’ analysed whether the current regulatory framework in the EU gas sector is efficient in order to maximise overall EU welfare or whether changes may be necessary, and if so provide recommendations. The study identifies potential inefficiencies of the EU gas market regulatory framework and discusses possible additional regulatory measures which could potentially lead to the improvement of EU welfare.

EY

REKK

Published

https://ec.europa.eu/energy/studies/study-quo-vadis-gas-market-regulatory-framework_en

Blending hydrogen from electrolysis into the European gas grid. JRC Science for Policy report. JRC126763

Impact and cost of hydrogen blending in the European gas network on the cross-border flow of gases and on electrolyser capacity.

Joint Research Centre

Forthcoming

Investigating the benefits of aligning EU consumer protection and information rules in the gas and electricity sectors

To evaluate the EU legal framework for consumer protection and information in the gas and DHC sectors and assess the impacts of (partially) aligning the provisions for gas and DHC with those of the 2019 Electricity Directive.

Valdani Vicari Associati-Grimaldi Studio legale

Forthcoming

Consumer study on precontractual information and billing in the energy market – improved clarity and comparability

Investigating minimum requirements and options for standardisation of energy offers and bills; main factors discouraging energy consumers from switching; and price comparison tools (PCTs)

Ipsos-London Economics-Deloitte consortium

Published

https://ec.europa.eu/info/sites/default/files/final_report_2_july_2018.pdf

Second consumer market study on the functioning of the retail electricity markets for consumers in the EU

Investigating if a well-functioning electricity market is in place for consumers in the EU; assess how the performance of retail electricity markets for consumers has developed; the extent to which consumers are able to make informed and empowered choices and what motivates their behaviour

Ipsos-London Economics-Deloitte consortium

Published

https://ec.europa.eu/newsroom/just/items/53331/en  

The role of renewable hydrogen import and storage to scale up the EU deployment of hydrogen

Aspects of this study were geared towards investigating options and impacts of large scale hydrogen storage and import terminals.

Energy Transition Expertise Centre (EnTec) (TNO, Guidehouse, McKinsey, Trinomics, Universiteit Utrecht, Frauenhofer)

Forthcoming

Hydrogen generation in Europe

Overview of costs and key benefits

Infrastructure costs and benefits, including repurposing, storage and imports

Guidehouse

Tractebel Impact

Published

https://op.europa.eu/en/publication-detail/-/publication/c4000448-b84d-11eb-8aca-01aa75ed71a1/language-en

Benchmarking smart metering deployment in the EU-28

Smart metering and access to data measures under Problem Area IV and the consumer empowerment topic

Tractebel Impact

Published

https://op.europa.eu/en/publication-detail/-/publication/b397ef73-698f-11ea-b735-01aa75ed71a1/language-en/format-PDF/source-122443670

Policies for DSOs, distribution tariffs and data handling

Policy options for data handling arrangements within the EU, under Problem Area IV and the consumer empowerment topic

Copenhagen Economics

VVA

Published

https://ec.europa.eu/energy/sites/default/files/documents/ce_vva_dso_final_report_vf.pdf

Problem Area

Preferred option

Practical implications of the preferred option of initiative by stakeholder

Problem Area I: Hydrogen infrastructure and markets

Option 2b: ‘Main regulatory principles with a vision’

Access of hydrogen producers to (regulated) pipeline networks is ensured although in the market ramp-up phase producers have to negotiate the concrete terms of their access (including tariffs) with network operators. This might initially require additional resources in comparison with the situation post-2030 in which regulated tariffs would apply. Gas quality requirement will likely have an indirect effect on hydrogen producers in terms of the hydrogen quality they can inject in the network. Hydrogen producers will need to comply with (relatively light) consumer rights requirements.

(Industrial) hydrogen consumers that are directly connected to the hydrogen transmission network have to negotiate the concrete terms of access with network operators in the market ramp up phase. This might initially require additional resources in comparison with the situation post-2030 in which regulated tariffs would apply. Hydrogen end-users might still face some additional cost to adapt the quality of hydrogen before its final use.

Regulated hydrogen network operators (e.g. existing natural gas TSOs that want to pursue hydrogen network activities by repurposing natural gas pipelines) would not be allowed to own and operate hydrogen production facilities or to pursue hydrogen supply activities. Operators that are currently already ownership unbundled 11 are expected to be confronted with low, if any, administrative costs. However, operators that are not yet ownership unbundled can face administrative burden when they have to ensure convergence to the envisaged ownership unbundling or ISO model after the transition phase. However, administrative costs for ownership unbundled undertakings will be lower as there is a clearer separation of economic activities and accordingly less reporting needs to show compliance with the unbundling principles. Hydrogen network operators will have to comply with the obligation of granting negotiated third-party access (based on freely negotiated tariffs) and, later on, of granting regulated third-party access based on regulated tariffs that will be phased in post-2030. Hydrogen network operators will have to adhere to hydrogen quality standards at cross-border points and provide information on hydrogen quality to consumers.

Private hydrogen network operators may be exempted from regulation and would then only be affected by convergence criteria and subsequently the obligations applicable to regulated network operators once such exemptions expire and/or they decide themselves to become part of the regulated network.

Natural gas consumers in those Member States that allow operators that pursue both hydrogen and natural gas network activities to create financial flows between natural gas and hydrogen asset bases might see an increase of their gas bill. This impact can be contained by allowing such flows under conditions and NRA control.

Operators of large scale hydrogen storage have to show compliance with the requirement to grant regulated third-party access on the basis of regulated tariffs and potential other criteria that will be set under the regulated access regime.

Terminal operators have to negotiate the terms of access to their facilities with customers that are interested in access.

National regulatory authorities (NRAs) would face additional workload in the form of implementing and monitoring the requirements on hydrogen network operators, including as regards unbundling, the obligation to grant negotiated and (as of 2030) regulated third-party access, the setting or approval of regulated tariffs (as of 2030), the application of the hydrogen quality management framework and network planning at national and EU level. NRAs would also be involved in the administration of and decision-making on exemption requests for new or existing hydrogen networks, storage facilities and liquid hydrogen terminals, and the monitoring of possible derogations for specific types of hydrogen networks. The scale of these additional tasks will be dependent on the development of hydrogen supply chains in each Member State and is expected to rise gradually over the coming years. The application of the EU-level hydrogen quality management framework will imply administrative costs of implementation for the involved regulatory authorities (not necessarily NRAs) or other relevant Member State authorities (Ministries). However, the harmonised rules limit the risk and administrative impact of cross-border disputes.

ACER’s mandate will be extended to monitoring and reporting on the internal hydrogen market on an annual basis after the adoption of the proposals. Additional workload for ACER will mainly depend on which empowerments are envisaged for more detailed technical rules (network codes) and on the specificities of the envisaged governance system. At least in the short to medium term, the work on hydrogen would come on top of the ongoing tasks under the regulatory framework for (natural) gas.

Tax payers might benefit from the option of financial flows between users of the hydrogen and the natural gas grid as it decreases the need to finance the initial development of hydrogen transport infrastructure via direct subsidies.

Problem Area II: Renewable and low carbon gases, and energy security

Option 3: Allow and promote RES&LC gases full market access, security, tackle issue of long term supply natural gas contracts and remove cross-border tariffs for RES&LC gases

Biomethane producers are expected to benefit from access to the wholesale market and the reverse flow compressor obligation as such measures reduce uncertainty for grid injection increasing the potential for marketing and stable production. Producers of renewable gases will also benefit from reduced risks and costs linked to cross-border tariffs.

Producers of renewable gases benefit from reduced risks linked to grid connection and interruption of gas injection linked to potential grid bottlenecks. Removal of grid injection tariffs would only have a marginal effect on producers.

The shippers of natural gas would need to avoid long-term supply contracts for natural unabated gas and will find more flexible contracts with shorter duration.

The gas consumers would see a slight increase of their gas bill on a long term because of the increase in gas contract prices compared to a situation where long-term contracts for natural gas would not be affected.

Consumers of gas are also likely to face an increase in costs of gas as the connection obligations bring about an increase in overall costs.

Taxpayers may, however, benefit from a potential decrease in specific support scheme costs as these costs will be covered by consumers of gas.

Strengthened cross-border coordination on gas quality and establishing national allowed levels for hydrogen blends will imply administrative costs for TSOs, Member State authorities and NRAs. Businesses will have to ensure their equipment can withstand the level of blending (system operators and end-users). Depending on the hydrogen blending levels of their countries, end-users (mostly industrial consumers) will need to adapt their equipment. They will most likely also bear some of the grid adaptation costs linked to the deployment of blended hydrogen. For blending levels of the preferred option beneath and at 5% adaptation in the chemical and glass industries would be required, for blending shares between 5% and 10% gas turbines and industrial high temperature applications will have to be adapted, 20% implies adaptations of combined heat and power plants and blending beyond 20% requires the installation of new boilers. The application of the EU-level gas quality management framework will imply administrative costs of implementation for NRAs and other Member State authorities (Ministries). However, the harmonised rules – either through high-level principles or specific rules – limits the risk and administrative impact of (cross-border) disputes. Efficient energy security arrangements, fit for the future needs and risks, will benefit the society at large, and in particular the protected customers (mainly, households and essential services). The new rules will add legal certainty and thus facilitate the tasks of public administrations involved in the emergency preparedness and crisis management as well as Ministries responsible for energy policy, NRAs and other ‘competent authorities’ under the SoS Regulation. The measures will streamline efforts in case of the crisis, making emergency measures, including solidarity gas more efficient.

An increase in biomethane production creates 2 000 to 4 000 additional local jobs and local added value.

TSOs/DSOs are likely to face a limited increase in efforts due to the connection obligation as system operators would in any case need to take care of grid connection. All TSOs and DSOs would need to comply with the applicable allowed hydrogen blending cap defined by EU rules that would represent important adaptation costs for any threshold chosen.

LSOs would be directly impacted by the obligation of improving their transparency and access to their terminal, which can increase their administrative costs, but at the same time increase their revenues thanks to a higher load factor.

NRAs would have to ensure compliance with the measures in this option.

Regarding connection obligation with firm capacity, NRAs need to adapt the rules and specificities of the firm capacity obligation (e.g. regarding the level of capacity to be guaranteed). Reduction/removal of injection tariffs requires NRAs to review the cost reallocation and its inclusion in the calculation of grid tariffs.

The administrative exchanges between NRAs and natural gas shippers should increase to ensure the correct application of the measures on the long-term contracts. LSOs may face administrative costs to comply with the testing the demand for access of renewable and low carbon gases to the terminals.

In case two or more NRAs have to take joint decisions, e.g. on gas quality, ACER would need to take the decision should the NRAs not agree. A harmonised EU approach on gas quality management would need to be implemented, or at least monitored and coordinated, by ACER.

Problem Area III: Network planning

Option 2: National Planning based on European Scenarios

Producers of renewable and low-carbon gases might benefit from a more comprehensive grid planning that integrates in particular the fact that gas flows might reverse compared to today, from distribution to transmission grid level (reverse flows), injections taking place from domestic sites and less from external imports.

Gas TSOs would be required to substantially increase their coordination efforts with electricity TSOs as well as with LSOs/SSOs and DSOs. It is important to note that a too strong integration could oppose functional unbundling.

NRAs would need to outline which elements of the scenario building should actually be harmonised, which stakeholders need to be directly involved and how to treat hydrogen in the plans (one-off implementation costs). ACER would have a continued role to ensure compliance with the European Plan.

Problem Area IV: Consumer protection and engagement

Option 3: Flexible legislation addressing all problem drivers

Consumers will benefit from better information, in particular on their consumption patterns. They will face lower financial and technical barriers to switching, and overall competition will allow them to reduce energy costs. Any consumer prices rises in the Member States phasing out price regulation would reflect previous below cost prices which encourage excess consumption of energy. Targeted measures would continue to be available for the energy poor or vulnerable consumers. Consumers would also benefit from higher levels of service and greater availability of value added products.

Suppliers would benefit from increased access to the market of the Member States setting regulated prices above cost level for households and micro-enterprises, or phasing out blanket price regulation for large, small and medium-sized enterprises. However, suppliers would also likely face increased pressure on margins as the result of the modestly greater consumer engagement expected.

Certain suppliers may need to adjust contractual conditions and reformat their consumer bills in order to comply with new requirements. However, this would be minimised where these requirements follow what is already in place for electricity. New entrants and energy service companies offering innovative products would benefit from quick and non-discriminatory access to data, as also supported by smart metering as well as access to consumers thanks to improved switching processes.

As TSOs and DSOs are normally the market actors charged with data management, would need to implement further measures to ensure non-discriminatory data handling. Such costs are expected to be passed through to final customers. NRAs in the Member States phasing out price regulation will need to step up efforts to monitor compliance. However, these impacts may be offset by increased consumer engagement in the form of energy communities, which would naturally foster competition in the market. ACER would need to enhance its monitoring of retail prices and of the compliance with consumer rights in EU legislation.

Overview of Benefits, (total for all provisions) – Preferred Option (Option 2b: ‘Main regulatory principles with a vision’)

Description

Amount (if possible, otherwise qualitative statement)

Comments

Direct and indirect benefits

Economic impacts

The preferred option is expected to have the strongest economic impacts and be most efficient and effective.

Lowering total hydrogen supply costs by 14-22% leading to savings of €3,0-4,6 bn/year across the EU for a total consumption of 5 Mt per year.

See also Table 31

Environmental impacts

Fostering the emergence of hydrogen infrastructure and efficient markets enables one of the pathways to decarbonise the gas sector. Networks and large scale storage are likely to benefit renewable hydrogen producers in as location and production profiles of renewable hydrogen production facilitates are unlikely to match end-user requirements.

Overview of costs – Preferred option

Total costs

Citizens/Consumers

Businesses

Administrations

One-off

Recurrent

One-off

Recurrent

One-off

Recurrent

Costs

Additional investments in cross-border pipelines

€100- 200 m

Overview of Benefits, (total for all provisions) – Preferred Option (Option 3: Allow and promote RES&LC gases full market access, security, tackle issue of long term supply natural gas contracts and remove cross-border tariffs for RES&LC gases)

Description

Amount (if possible, otherwise qualitative statement)

Comments

Direct and indirect benefits

Economic impacts

Entry-exit zones including DSOs: up to €10 m/year of savings in public support costs;

Enabling physical reverse flows: up to €45 m/year saved in purchasing natural gas and €18 m/year for emission rights

See study ‘Assistance to assessing options improving market conditions for bio-methane and gas market rules'.

Environmental impacts

The option allows to meet the 55% GHG emission reduction target.

Overview of costs – Preferred option

Total costs

Citizens/Consumers

Businesses

Administrations

One-off

Recurrent

One-off

Recurrent

One-off

Recurrent

Costs

Reverse flow compressors

€70 m

€3 m

Overview of Benefits, (total for all provisions) – Preferred Option (Option 2: National Planning based on European Scenarios)

Description

Amount (if possible, otherwise qualitative statement)

Comments

Direct and indirect benefits

Economic impacts

Higher interlinkages between gas and electricity scenarios under the preferred option would ensure a common vision of the different stakeholders implying that investment decisions are more aligned, avoiding conflicting or redundant investments, thereby savings in societal costs.

Environmental impacts

Integration of networks as envisaged by the preferred option would lead to significant emission reductions resulting in a reduction of the footprint of the overall energy system on the environment.

Overview of costs – Preferred option

Total costs

Citizens/Consumers

Businesses

Administrations

One-off

Recurrent

One-off

Recurrent

One-off

Recurrent

Costs

Preferred option reduces the risk of potential lock-ins or stranded assets.

NA

NA

NA

NA

NA

NA

Overview of Benefits, (total for all provisions) – Preferred Option (Option 3: Flexible legislation addressing all problem drivers)

Description

Amount (if possible, otherwise qualitative statement)

Comments

Direct and indirect benefits

Economic impacts

Although no quantitative assessment is possible, substantial economic benefits are expected from the preferred option, retail competition would be improved and customers would have better information on consumption and energy sources. The phase-out of blanket price regulation will benefit to small and medium-sized retail suppliers and consumers.

Energy poor and vulnerable benefit from additional protection measures, smaller companies will benefit from price deregulation and market opening, engaged consumers benefit from measures on price comparison tools and switching related fees.

Environmental impacts

Taken together the proposed measures will help consumers make greener choices and energy communities-of-interest would contribute to the uptake of bio-methane and low-carbon gases, which will have a potential positive impact on the environment.

Benefits derived from decarbonisation for present and future generations of consumers.

Overview of costs – Preferred option

Total costs

Citizens/Consumers

Businesses

Administrations

One-off

Recurrent

One-off

Recurrent

One-off

Recurrent

Costs

NA

Higher energy prices in some Member States due to price deregulation.

Supplier costs associated with modifying consumer bills or adjusting contractual conditions.

Cost of supplying at regulated prices to energy poor and vulnerable households.

Suppliers will also face costs related to restriction on contract termination fees.

Costs for public authorities associated with running certification scheme for price comparison tool, or to run one independently.

NRA faces increased costs derived from enhanced efforts to monitor the market, guarantee consumer protection, and ensure effective competition.

Data protection authorities may face increased costs derived from implementation of the envisaged measures on data.

Scenario

Minimum cross-border capacity

Maximum cross-border capacity

Optimisation of cross-border capacity

Most likely to happen in regulatory option

Business as usual (BAU)

None

0

No

0 or 1

A constrained

EHB 2030

None

No

2a,2b, 3a,3b

(lower end)

A optimised

EHB 2030

None

Yes

2a,2b, 3a,3b

(higher end)

B optimised

EHB 2035

None

Yes

additional drivers

Technology

Substrates    

Biogas - on-site power and heat generation

-Manure

-Phasing out existing plants:

oCorn

oSewage gas, landfill gas

Biomethane Anaerobic digestion - rural residues

-Straw

-Grass cuttings abandoned grassland

-Animal waste

Biomethane Anaerobic digestion - rural cultivation

-Perennials: grassy

-Sequential cropping

-Phasing out existing plants: corn

Biomethane Anaerobic digestion - urban

-Common sludge

-Sewage gas

-MSW (not landfill, composting, recycling)

-Verge grass

Biomethane – thermal gasification    

-Stem wood from thinning and final fellings

-Logging residues from final fellings (tops and branches mainly)

-Stumps from final fellings

Parameter

Probable distance

Connection cost

1 (dense gas network)

0 km
raw biogas pipeline

€0/MWh
biomethane

2 (medium gas network)

8 km
raw biogas pipeline

€7/MWh
biomethane

3 (low gas network)

14.5 km
raw biogas pipeline

€12/MWh biomethane

4 (no gas network at NUTS1 region)

21 km
 Bio-LNG

€19/MWh biomethane

Category

Indicator

Format

Granularity 26

Renewable and low carbon gases integration

1.1

Number and capacity of biogas plants

Excel

MS-specific

1.2

Number and capacity of biomethane plants

Excel

MS-specific

1.3

Annual production of biomethane

Excel

MS-specific

1.4

Number and capacity of power-to-hydrogen projects

Excel

MS-specific

1.5

Number and capacity of power-to-synthetic methane projects

Excel

MS-specific

1.6

Current use for biomethane

Word/Excel

MS-specific

1.7

Production potential of biomethane and biogas

Word/Excel

EU-level

1.8

Biomethane injection profile

Excel

Other

1.9

Potential and costs of biomethane imports

Excel

Global regions

1.10

Current and potential costs of synthetic methane imports until 2030

Word

Global regions

1.11

Total cost of transport of biomethane and synthetic methane from third countries

Word/excel

Techno-economic

1.12

Domestic natural gas production in the EU

Excel

MS-specific

1.13

Capacity of cross-border pipelines between Member States

Excel

MS-specific

1.14

Entry/Exit tariffs for intra/extra-EU IPs and for LNG terminals

Excel

MS-specific

1.15

Long-term booked capacity

Excel

EU-level

1.16

Injection and withdrawal capacities of large natural gas storages

Excel

MS-specific

1.17

Tariffs for large natural gas storages

Excel

MS-specific

1.18

Distribution network archetypes

Separate excel

MS-specific

1.19

Available pipeline capacity in the EU that can be used for decarbonised gas imports in 2030

Excel

MS-specific

1.20

Flexible methane demand

Word

EU-level

1.21

Number of DSOs per Member State

Excel

MS-specific

1.22

TSO & DSO expenditures

Excel

MS-specific

1.23

TSO allowed revenues

Excel

MS-specific

1.24

TSO & DSO network length

Excel

MS-specific

1.25

Supply costs of biogas

Excel

Other

1.26

Cost of biogas upgrading to biomethane

Word

Techno-economic

1.27

Cost of hydrogen methanation

Word

Techno-economic

1.28

Costs of connection of biomethane plant to DSO or TSO grid

Word

Techno-economic

1.29

Cost allocation of biomethane plant connection

Excel

MS-specific

1.30

Biomethane connection obligation/request denials

Excel

MS-specific

1.31

Costs of other key components in methane network

Word

Techno-economic

1.32

Costs of reverse flow installations

Word

Techno-economic

1.33

Cost of de-odorization in case of reverse flow from DSO to TSO.

Word

Techno-economic

1.34

Grid injection tariffs for biomethane, synthetic methane and hydrogen

Excel

MS-specific

1.35

Expected cost reductions for techno-economic parameters

Excel

Techno-economic

1.36

Current MS status regarding the policy options for the integration of renewable and low-carbon gases

Excel

MS-specific

Gas quality

2.1

Overview of technical hydrogen admixture thresholds

Word

Techno-economic

2.2

Analysis of needed adaptations in the gas infrastructure network

Word

Techno-economic

2.3

Costs of adapting distribution and transmission infrastructure to hydrogen blending

Word

Techno-economic

2.4

Costs and feasibility of adapting end-use appliances to hydrogen blending rates

Word

Techno-economic

2.5

Feasibility of using gas storage for hydrogen blended gas

Word

Techno-economic

2.6

Potential administrative costs of reinforced cross-border regulatory framework for gas quality

Word

Techno-economic

2.7

Current national hydrogen admixture regulation

Excel

MS-specific

LNG terminals

3.1

Costs of adapting LNG terminals

Word

Techno-economic

3.2

Transport costs of re-exporting decarbonised gas within the EU via LNG route.

Excel

Techno-economic

3.3

Number and capacity of current LNG terminal projects

Word/Excel

MS-specific

3.4

Number and capacity of planned LNG terminal projects

Excel

MS-specific

3.5

Available LNG storage capacity in the EU that can be used for decarbonised gas imports in 2030

Excel

EU-level

3.6

Supply potential and supply costs for LNG imports

Excel

Main suppliers

3.7

Utilization profile of LNG terminals per hour/day

Excel

Other

System integration planning

4.1

Costs and benefits of changes in unbundling of DSOs to avoid conflicts of interests

Word

Literature review

4.2

Costs and benefits of additional coordination and cooperation requirements (electricity/gas, TSO/DSO, storage)

Word

Literature review

4.3

Analysis of current planning procedures in MSs

Excel

MS-specific

4.4

Current MS status regarding the policy options for integrated network planning

Excel

MS-specific

Scenario

Repurposed methane interconnections
[GW]

New hydrogen interconnections
[GW]

Total interconnections
[GW]

minimum

optimised

minimum

optimised

BAU

-

-

-

-

-

A constrained

19

10

-

29

A optimised

19

25

10

17

71

B optimised

47

8

120

10

184

Scenario

Storage capacity

Total

Largest share

BAU

20,8

DE (40%)

A constrained

18,3

DE (25%)

A optimised

17,9

ES (43%)

B optimised

17,7

ES (42%)

Scenario

Total Hydrogen Production (TWh)

Total Electrolyser Capacity (GW)

Electrolyser Utilisation (h)

BAU

194

53

42%

A constrained

198

47

48%

A optimised

220

42

60%

B optimised

220

43

59%

Scenario

H2 production price

Electrolyser Capex

Storage

Pipelines

Total

BAU

3,17

0,77

0,28

-

4,22

A constrained

2,69

0,66

0,24

0,02

3,62

A optimised

2,51

0,55

0,21

0,04

3,30

B optimised

2,51

0,55

0,21

0,09

3,36

Vertical unbundling

Objective

Vertical unbundling has the objective of preventing conflicts of interests which may result from a vertical integration of hydrogen network operations and hydrogen production/supply activities.

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big Bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

No rules

NA

OU/ITO/ISO

OU + ISO model

Ownership unbundling

EU TSO (ISO model) for hydrogen networks

Pros

May incentivise hydrogen network development by vertically integrated hydrogen producers.

No administrative burden/regulatory costs.

Similar to BAU

Carry-over of current unbundling models of natural gas TSOs to hydrogen could simplify implementation.

No costs for change in unbundling regime incurred by incumbent natural gas network operators when pursuing hydrogen transport activities and that are currently organised on basis of the ISO/ITO model.

Ownership unbundling ensures that hydrogen network operators do not have the incentive to discriminate among users of their network.

Vertical integration in hydrogen is limited, so regulatory costs of unbundling are low compared to developed sectors (natural gas and electricity).

Use of the ISO model would allow vertically integrated hydrogen producers to retain ownership of existing hydrogen networks, while providing adequate safeguards for third-party users of these networks.

In transition: ITO can be allowed until 2030.

Ownership unbundling ensures that network operators do not have the incentive to discriminate among users of their network.

Blanket ownership unbundling for hydrogen networks could allow for less stringent TPA requirements.

Addresses conflicts of interests resulting from vertical and horizontal integration.

Allows existing vertically integrated hydrogen producers to retain ownership of existing hydrogen networks.

EU TSO well placed for EU-level network planning and development.

Facilitates ITC mechanism (needed if for rTPA without cross-border tariffs. (See table on tariffs below)

Cons

Vertically integrated network owners incentivised to restrict third-party access and cross-border connections, thereby limiting competition and cross-border integration of hydrogen markets.

Similar to BAU

Use of historic unbundling models in the natural gas sector would constitute a missed opportunity to introduce a structural unbundling model at low cost due to small number of existing vertically integrated hydrogen producers.

The ISO and ITO modes are associated with a higher regulatory cost and administrative burden for operators and monitoring authorities.

Limits the commercial freedom of hydrogen producers/suppliers and hydrogen network operators.

The ISO and ITO models are associated with a higher regulatory cost and administrative burden for operators and monitoring authorities.

Limits the commercial freedom of hydrogen producers/suppliers and hydrogen network operators.

Would require divestment of existing hydrogen networks by vertically integrated hydrogen (and gas) producers.

May require ITC mechanism to allocate revenues.

Enabling certain functions (e.g. EU-level network planning) would require imposing financing obligations on networks owners (similar to ITO/ISO unbundling models).

Most suitable option:

Option 2b

OU + ISO: Ownership unbundling fully eliminates conflict of interests via structural separation of transport and production/supply activities and is thus effective at safeguarding competition and incentives for cross-border integration, has lower monitoring costs for regulatory authorities and allows for greater flexibility in network access rules. ISO model would allow vertically integrated hydrogen producers to retain ownership of existing hydrogen networks, while providing adequate safeguards for third-party users of these networks. Use of ITO model until 2030 creates greater flexibility in the ramp-up phase.

Horizontal unbundling

Objective

Horizontal unbundling has the objective of preventing conflicts of interests arising from the operation of different types of energy networks by a single entity

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big Bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

No rules

NA

Combined hydrogen/CH4 TSO

Legal + Accounts unbundling

Legal + Functional

Accounts unbundling (assets operated by EU TSO (ISO)

Pros

No administrative burden.

-

No additional administrative burden (as BAU for natural gas).

Facilitates repurposing of natural gas network.

Reduces risk of conflicts of interest regarding repurposing and de-commissioning of gas network infrastructure.

Gas TSOs can retain ownership of repurposed gas pipelines within company group structure.

Considerably reduces risk of conflicts of interest regarding repurposing and de-commissioning of gas network infrastructure.

Gas TSOs can retain ownership of repurposed gas pipelines within company group structure.

Considerably reduces risk of conflicts of interest regarding repurposing and de-commissioning of gas network infrastructure.

Gas TSOs can retain ownership of repurposed gas pipelines (operated by EU TSO).

Cons

National rules may prevent combined Hydrogen/CH4 operators in some Member States.

-

Risk of conflicts of interest regarding repurposing and de-commissioning of gas network infrastructure.

Administrative burden and regulatory cost for operation and monitoring, but relatively low.

Higher administrative burden and regulatory costs for operation and monitoring.

Higher administrative burden and regulatory costs for operation and monitoring.

Most suitable option

Option 2b

The choice of horizontal unbundling requirements is linked to the rules on the regulated asset base (RAB), since a joint asset base is possible only in the absence of horizontal unbundling requirements. Where a separate RAB is the preferred option, this allows for the choice of different horizontal unbundling requirements (from accounts unbundling up to ownership unbundling). Compared to vertical integration, the risk of conflicts of interests as a result of combined operatorship of different types of networks is present but less severe. The remaining risks can be managed effectively via monitoring and approval by regulatory authorities. Therefore, legal and accounts unbundling (but without functional unbundling), as a low level of horizontal unbundling, can be considered sufficient. This allows for the combined operation of natural gas and hydrogen networks within a group of undertakings (i.e. by creating a subsidiary). The possibility for gas TSOs to retain ownership of methane infrastructure intended for into hydrogen transport within their group structure reduces regulatory costs and facilitates infrastructure repurposing.

TPA for hydrogen networks

Objective

Rules on non-discriminatory third-party access (TPA) to hydrogen networks should enable competition by ensuring access to hydrogen commodity markets for all market participants.

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

No rules

No rules

Negotiated TPA (nTPA)

Regulated TPA (rTPA) +

no cross-border tariffs

(but nTPA possible until 2030)

Regulated TPA (rTPA) +

no cross-border tariffs

Regulated TPA (rTPA) + no cross-border tariffs

Pros

May incentivise investment in hydrogen networks (by vertically integrated hydrogen producers/suppliers).

Similar to BAU

Assures minimum degree of non-discriminatory third-party use of hydrogen networks, thereby enabling competition.

Lower regulatory burden than rTPA.

Provides room for network operators to enter into long-term transport contracts that could increase investment certainty/incentives in networks.

Ensures non-discriminatory third-party use of hydrogen networks, enabling competition.

Ensures cost-reflectiveness of access tariffs.

Harmonised TPA regimes would facilitate interconnections and thereby cross-border trade.

TPA supported by stakeholders.

Prohibition on cross-border tariffs fosters cross-border trade.

Option: nTPA would allow for more flexibility in ramp-up phase (see Option 2a).

Regulated TPA would ensure non-discriminatory third-party use of hydrogen networks, thereby enabling competition.

Regulated TPA, based on regulated tariffs, would ensure the cost-reflectiveness of access tariffs.

Harmonised TPA regimes would facilitate interconnections and thereby cross-border trade.

Prohibition on cross-border tariffs fosters cross-border trade.

Like Option 3a

Cons

Risks of non-competitive market outcomes limited market access and impediments for interconnection and cross-border trade.

Similar to BAU

Reduces the commercial freedom of hydrogen network operators.

Negotiated TPA is more prone to abuse, in the absence of regulated access tariffs.

Risk of competition distortion between Member States if national rules envisage regulated TPA.

Monitoring by regulatory authority required.

Limits the commercial freedom of hydrogen producers/suppliers and hydrogen network operators.

Increased regulatory costs.

Prohibition on cross-border tariffs likely to require ITC mechanism by 2030.

Monitoring by regulatory authority required.

Like Option 2b but no flexibility in transition

Like Option 2b but no flexibility in transition

Most suitable option

Option 2b

Regulated third-party access is effective in ensuring non-discriminatory market access to and competition in hydrogen commodity markets (including across Member States borders). Clear rules on TPA were considered important by stakeholders. The preferred option envisaged greater flexibility in the ramp-up phase in the form of negotiated TPA. The pre-set date for the transition to regulated TPA provides visibility for investors and network users.

TPA for large-scale hydrogen storage

Objective

The objective of third-party access for large-scale hydrogen storage is to ensure the access of all hydrogen producers and consumers to scarce storage facilities, to prevent that hydrogen producers and consumers are dependent in their activities on the (seasonal) variability of renewable electricity that is used for the production of renewable hydrogen.

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

No rules

No rules

Negotiated TPA (nTPA)

Regulated TPA (rTPA)

Regulated TPA (rTPA)

Regulated TPA (rTPA)

Pros

May incentivise investment in hydrogen terminals in particular by vertically integrated operators.

No administrative burden.

Like BAU

Would ensure a minimum degree of non-discriminatory third-party use of hydrogen-ready underground storage (not available in all MS), thereby enabling competition and cross-border integration.

Lower regulatory costs (compared to rTPA).

Regulated TPA would ensure non-discriminatory third-party use of hydrogen-ready (underground) storage (not available in all MS), thereby enabling competition.

Regulated TPA, based on regulated tariffs, would ensure the cost-reflectiveness of access tariffs.

Storage will, in particular at the early stages of infrastructure development be one of the few means to cover energy security risks, emphasising the need for fair access conditions.

Like Option 2b

Like Option 2b

Cons

High risk of non-competitive market outcomes (due to commercial value of storage) and market integration (as storage not available in all MS)

Like BAU

Reduces the commercial freedom of hydrogen storage operators.

Negotiated TPA is more prone to abuse, in the absence of regulated access tariffs.

Risk of competition distortion between MS.

Higher administrative burden/regulatory costs due to tariff regulation.

May disincentivise conversion of underground gas storage subject to nTPA.

Like Option 2b

Like Option 2b

Most suitable option

Option 2b

Ensuring access to large scale storage is expected to be conducive to investment incentives in renewable hydrogen production (e.g. via electrolysers) and consumption and therefore considered to be an important driver for the development of competitive upstream and downstream hydrogen markets. Ensuring access to large scale storage will allow renewable hydrogen producers to decouple production from consumption thereby allowing them to optimize their electrolyser operations on the basis of price variations for renewable electricity. It enables a stable hydrogen supply for initial (industrial) consumers. As large scale storage is expected to be scarce (especially during the hydrogen ramp-up phase) and only available in certain member states due to geological conditions, a strict access regime is justified.

TPA for hydrogen terminals

Objective

The objective of TPA for hydrogen terminals is to ensure non-discriminatory access to terminals for the import of liquid hydrogen for hydrogen producers and consumers.

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

No rules

No rules

No rules

nTPA

regulated TPA (rTPA)

regulated TPA (rTPA)

Pros

May incentivise investment in hydrogen terminals in particular by integrated operators.

No administrative burden.

Like BAU

Similar to BAU

Minimum degree of non-discriminatory third-party use of liquid hydrogen terminals, thereby enabling competition.

Reduces regulatory costs and administrative burden (relative to regulated TPA).

Regulated TPA would ensure non-discriminatory third-party use of liquid hydrogen terminals, thereby enabling competition.

Regulated TPA, based on regulated tariffs, would ensure the cost-reflectiveness of access tariffs.

Ensures consistency with LNG terminal regulation, given the high likelihood of combined terminals.

Like Option 3a

Cons

Risk of competitive market outcomes and market integration terminals not possible in all MS).

Means of hydrogen (and derivatives) imports uncertain. Other means than liquefied hydrogen may exert competitive pressure on terminal operators.

Like BAU

Similar to BAU BUT: access rules to network are NOT determined by an integrated operator.

Reduces the commercial freedom of liquid hydrogen terminal operators.

Negotiated TPA is more prone to abuse, in the absence of regulated access tariffs.

Risk of competition distortion between MS.

Administrative burden and regulatory cost (but lower than rTPA).

Limits the commercial freedom of hydrogen producers/suppliers and hydrogen network operators.

Increased regulatory costs due to tariff regulation and monitoring of capacity allocation rules.

Like Option 3a

Most suitable option

Option 2b

Hydrogen (and its derivatives) can be economically imported by various means. It is unclear at this stage whether hydrogen will be imported in liquefied form or otherwise whereas, in the earlier stages of a developing hydrogen market, imports may anyway be limited. This uncertainty and the likelihood that alternative means of importing hydrogen will exert sufficient competitive pressure on terminal owners, means that a heavy-handed regime for liquefied hydrogen terminals seems unnecessary and, probably, too early.

Hydrogen quality

Objective

Cross-border market integration; to ensure unhindered cross-border hydrogen flows and required quality for end-users

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

No rules at EU level on technical aspects, including on hydrogen purity. The operating conditions are negotiated between network operators and users (tailored towards the concrete demand of, mostly, industrial consumers).

MS to ensure that hydrogen quality is addressed in the tendering.

Cross-border coordination framework and dispute settlement

Obligation on Member States to agree on the acceptable hydrogen purity levels for cross-border points; cross-border dispute settlement procedure with the involvement of the concerned regulatory bodies (similar to that of the Interoperability Network Code for methane networks, with specific roles for network operators, NRAs and ACER); EU-level principles on roles of hydrogen producers and network operators, on regulatory oversight and transparency on hydrogen purity.

EU-wide acceptable hydrogen purity level for cross-border points (detailed technical specifications in either a delegated or implementing act); cross-border dispute settlement and EU-level rules on roles of hydrogen producers and network operators, on regulatory oversight and on transparency as in Option 2a.

EU-wide acceptable purity level for cross-border points

(like Option 2b)

EU-wide acceptable purity level for cross-border points

(like Option 2b)

Pros

Limited administrative burden as no new legislation is introduced.

Limits the risk of cross-border flow restriction and market segmentation.

Limited intervention; leaves flexibility to the Member States on defining acceptable hydrogen quality standards both cross-border with adjacent Member State and in domestic network.

Limited administrative costs for system operators and regulatory authorities.

Ensures common approach on hydrogen quality for cross-border points across the EU limiting the risk of cross-border disputes, flow restrictions and market segmentation to a minimum.

Ensures strong coordination between Member States in case cross-border disputes still arise due to actual quality differences.

Ensures a harmonised approach across the EU on quality management by setting rules on roles, responsibilities, regulatory oversight and transparency on hydrogen quality.

Supports the development of a cross-border hydrogen infrastructure and trade in the EU.

Limited intervention; leaves flexibility to the MS on hydrogen quality standards in the domestic network without interfering with national specificities of hydrogen quality.

Support by stakeholders for establishing hydrogen quality (purity) standard at Member State level with EU-level cross-border coordination rules.

Stakeholders also support establishing rules on roles, responsibilities and cost-allocation for the management of hydrogen quality at EU-level.

Ensures a fully harmonised approach on hydrogen quality at cross-border points.

Eliminates the risk of cross-border disputes on hydrogen quality standards.

Ensures a harmonised approach across the EU on quality management by establishing EU-level rules on roles of hydrogen producers and network operators, on regulatory oversight as well as on transparency and quality monitoring (including European level monitoring tasks).

Supports the development of a cross-border hydrogen infrastructure and trade in the EU.

Retains flexibility for Member States to define the acceptable hydrogen quality/purity levels for the domestic network.

Provides clarity to investors, operators and users on acceptable quality providing for more investment stability.

Very strong support by stakeholders for establishing binding hydrogen quality (purity) standard at EU-level.

Like Option 2b

Like Option 2b

Cons

Applicable rules on hydrogen quality would remain undefined or set at national level; their application cross-border would not be aligned risking cross-border flow restrictions and market segmentation.

Potential of cross-border disputes due to differences in hydrogen quality standards.

Additional costs for market participants incurred for the implementation of different voluntary approaches.

Stakeholder do not support this option.

Lack of cross-border coordination on hydrogen quality can lead to cross-border flow, trade restrictions and market segmentation.

Lack of visibility and oversight of hydrogen quality patterns at production and needs at user side can lead to mismatch and consequently to increased cost of quality adaptation.

Stakeholder do not support this option.

I.e. this option does not impose EU-level regulation on hydrogen network operation.

Risk of cross-border disputes due to differences in quality standards and/or the actual quality (purity) of the hydrogen transported cross-border remains.

Lack of a harmonised approach to acceptable hydrogen quality levels across Europe can hamper investments in the hydrogen market.

Additional cost for deblending, especially at end-user points.

Administrative costs due to implementation tasks for the involved authorities (incl. for the European-level tasks) and market participants, including for hydrogen system operators.

Administrative costs for cross-border dispute settlement (including for European level coordination).

Limited risk of disputes due to differences in the actual quality (purity) of the hydrogen transported cross-border remains.

Limits the flexibility of Member States to agree on specific quality rules cross-border.

Administrative costs for the implementation of the EU rules for the involved regulatory authorities (including for the European-level monitoring) and market participants (including for hydrogen system operators).

Like Option 2b

Like Option 2b

Most suitable option

Option 2b

Under the preferred option, hydrogen quality would be governed by a harmonised EU approach for cross-border interconnection points. Even if the emergence of dedicated pipelines and the conversion of existing gas pipelines might be limited to the local level in short and mid-term, a joint European standardisation approach would enable the later connection of these hydrogen pipelines to a cross-border network. EU-level technical rules are crucial for managing cross-border hydrogen flows within and into the EU.

Option 2b achieves the objective of cross-border market integration by setting a harmonised EU-level purity requirement for cross-border points, establishing a harmonised EU-approach for cross-border dispute settlement should problems still arise and setting harmonised rules for the management of hydrogen purity, thereby enabling unhindered cross-border flows and ensuring that end-users receive the hydrogen quality needed for their uses.

These elements provide an increased clarity and visibility on hydrogen quality and related processes also for end-users. In addition, especially the EU-level rules on hydrogen quality management address the risk of negative impacts of different hydrogen qualities for end-users by allocating roles and responsibilities for quality handling to market participants, by increasing transparency on actual and forecasted cross-border qualities, and by ensuring proper regulatory oversight.

The preferred option provides a proportionate approach by limiting the intervention to cross-border interconnection points to avoid market segmentation, without imposing hydrogen purity standards for the Member States’ domestic hydrogen networks. Under the preferred option, Member States will still have the flexibility to define hydrogen quality requirements for their domestic networks which take into account the specificities of domestic hydrogen production technologies.

It also provides a proportionate approach by setting the detailed technical specifications for the acceptable cross-border hydrogen purity level in either a delegated or implementing act. Given that as of today, there is limited availability of data on hydrogen purity levels and their implications for the infrastructure and end-use, this approach ensures that these very technical topics are addressed in the most proportionate manner, allows for strong stakeholder involvement, for the involvement of technical experts and for the assessment of emerging data and experience. This approach was used in the past to define technical rules for the natural gas market in the framework of network codes (equivalent to today’s delegated acts and implementing acts).

In terms of subsidiarity, EU action is needed as, voluntary standards – while they could in theory lead to an alignment of hydrogen purity levels between Member States – would lead to a convergence across Europe only slowly, or not at all. Further, fostering efficient and integrated EU hydrogen markets requires a harmonised and coordinated approach by the Member States, which can only be achieved efficiently by EU action (not by individual Member States). The preferred option avoids the distortive effects of uncoordinated, fragmented policy initiatives which may occur if Member States develop national approaches with regard to acceptable hydrogen purity levels. EU action has significant added-value by ensuring a coherent approach across all Member States.

The preferred option imposes administrative costs on Member State authorities, including regulatory authorities, and on network operators, as they will need to implement the EU-level rules. At the same time, this option limits the costs of cross-border dispute settlement for all involved market participants (while these costs can still be significant under Option 2a, where cross-border disputes can still arise due to differences in the actual quality of transported hydrogen).

Transition

Objective

Exemptions provide tailored waivers from certain regulatory requirements if this creates welfare benefit and a detrimental market impact is unlikely.

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

No rules

NA

Individual exemptions for new and/or existing infrastructure

Like Option 2a, but:

Exemptions for infrastructure are granted with conditions that ensure convergence on the main regulatory principles.

For example:

Exempted networks (later) integrated in meshed network must comply with main regulatory principles.

Exempted private networks have unilateral opt-in into regulated system.

.

Only new infrastructure can be exempted (like Art. 36 Gas Directive)

Like Option 3a

Pros

Allows for assessment of market impact of each exemption.

Temporary exemptions will eventually result in comprehensive applicability of regulatory requirements, thereby reducing potential distortions of competition.

Like Option 2a but:

Requirement of convergence avoids regulatory barriers once network become more interconnected. It assures level playing field and avoids cherry picking.

Unilateral opt-in for existing private network is low hanging fruit.

Provides roadmap for users’ private infrastructure to inter-connected hydrogen grid and connected customers and producers.

Main regulatory principles apply immediately throughout network.

Lower regulatory costs (compared to Option 2).

Like Option 3a

Cons

Since most hydrogen infrastructure will be new or repurposed, a large share of future hydrogen infrastructure may be eligible for exemptions.

Delayed convergence in regulated structure when network gets more integrated. Potential of regulatory barriers once network is extended/integrated.

Regulatory costs.

Unilateral opt-in delays convergence relative to relative to more prescriptive measures under Option 3

Regulatory costs.

Disruption to operation and financing structure of existing hydrogen networks.

Like Option 3a

Most suitable option

Option 2b

Option 2b will incorporate the benefits of Option 2a in that it fosters private investment. However, it addresses the specific disadvantage, closely associated with the fact that the meshed network that will exist in a mature phase of a market, will have grown out of initially disconnected network elements. In order for the operation of this progressively interconnected system to support a deeply integrated hydrogen market, it needs to be avoided that regulatory barriers develop as a result of the different regulatory regimes under which the initial elements of the network were build. Convergence on the main regulatory principles for network elements that later become inter-connected needs to be build-in.

Transition

Objective

Derogations reduce the regulatory burden for infrastructure that is typically less relevant for general market access

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

No rules

NA

Derogations for geographically confined networks

Like Option 2a but: Derogations expires once additional producers are connected and/or become part of meshed network

Like Option 2b

Like Option 2b

Pro

Allows vertical integration and non-regulated operation in situations where need for TPA is less likely.

May incentivise investments in hydrogen infrastructure.

Allows vertical integration and non-regulated operation in situations where competition concerns is less likely.

May incentivise investments in hydrogen infrastructure.

Requirement of compliance once additional producers connect or network becomes part of wider meshed network avoids cherry-picking, assures/level playing field and fosters convergence.

Like Option 2b

Like Option 2b

Cons

Potential of regulatory barriers once network is extended/integrated.

Requires clear rules on connection rights for new network users to address moral hazard (i.e. remaining isolated to avoid regulation).

Increased regulatory costs for monitoring.

Like Option 2b

Like Option 2b

Most suitable Option

Option 2b

Option 2b envisages derogations for geographically confined hydrogen networks to reduce the regulatory burden on these types of assets during the market ramp-up and in situations where competition concerns are less likely.

Permitting and land use rights

Objective

Clarity on the validity of permits and land use rights that have been granted for the construction and operation of natural gas pipelines once the transported gaseous energy carrier changes from natural gas to hydrogen, should prevent undue delay in repurposing natural gas pipelines for hydrogen transport. Coherence in the conditions for permitting and land use rights for newly built pipelines should on the one hand ensure that a different legal regime does not lead to delay in the development of pipelines that should complement repurposed pipelines and on the other hand that operators of newly built pipelines do not suffer from a competitive disadvantage vis-à-vis incumbent gas network operators that repurpose their pipelines for hydrogen transport.

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

No EU rules

No EU rules

As a general rule, existing permits and land use rights granted for the operation of natural gas transport pipelines are grandfathered for the operation of hydrogen pipelines. However, no harmonisation of national rules.

Like Option 2a

+ General requirement that conditions for permitting and land-use rights for new hydrogen pipelines are aligned with those currently used for natural gas. However, no harmonisation of national rules.

Harmonisation of permitting and land use rights

Like Option 3a

Pro

Discretion MS

Discretion MS

Facilitates repurposing in all MS

Facilitates repurposing and puts newly built hydrogen infrastructure at par with natural gas, thereby avoiding bias in the feasibility of infrastructure projects and lock-in of natural gas. Leaves discretion to Member States to set location specific (technical safety) rules on permits and land use rights.

Conditions for repurposing and newly built infrastructure aligned within EU.

Like Option 3a

Cons

No alignment rules between MS

No alignment rules between MS

No clarity on permits and land use rights for newly built infrastructure.

Relevant rules are currently set at national level and might not be required at EU level (subsidiarity).

Relevant rules are currently set at national level. Potential proportionality and subsidiarity issue.

Like Option 3a

Most suitable option

Option 2b

Option 2b prevents a potential delay in repurposing pipelines as a resubmission for a request for permits and land use rights once the transported energy carrier changes from natural gas to hydrogen is not needed. In addition, it creates a level playing field between (potential different operators of) repurposed and newly built pipelines. Infrastructure projects based on both repurposed and newly built pipelines do not face different legal regimes in terms of permits and land use rights. Option 2b leaves discretion to Member States to set location specific (technical safety) rules on permits and land use rights thereby preventing potential subsidiarity issues.

Hydrogen Consumer rights

Objective

Provide for a level playing field across different energy carriers for relevant consumer groups

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

No rules

NA

No rules beyond defined elsewhere (e.g. TPA, hydrogen quality)

Consumer protection rules equivalent to those for larger consumers in Gas Directive

Consumer protection rules are those valid for all gas users (including e.g. SMEs, households)

Like Option 3a

Pro

Rules set between (private) operators and connected customers bi-laterally.

No regulatory costs.

Rules set between (private) operators and connected customers bi-laterally

No regulatory costs.

Leaves large scope of freedom to set conditions between users and suppliers. No additional regulatory costs.

Overall, level playing field between hydrogen and other energy carriers (assuming current electricity rules are made applicable to gas users) for relevant consumer categories.

All consumers treated at par with gas users.

Perfect level playing field for energy carriers (assuming current electricity rules are made equivalent to gas users).

Like Option 3a

Cons

Risk that rules are biased by the interest of monopolistic operators.

Divergence between customer categories and MS.

Risk that rules are biased to interest monopolistic operators.

Divergence between customer categories and MS.

Divergence between customer categories and MS.

Limited regulatory costs.

In view of likely customer base for hydrogen (larger, more sophisticated consumers) full equivalence disproportional.

High regulatory costs.

Like Option 3a

Most suitable option

Option 2b

The preferred Option 2b provides for consumer protection rules in principle equivalent to those for larger consumers under the Gas Directive, precisely, if households are connected to the hydrogen system they do benefit from basic rights but those which encourage participation in the market e.g. citizen Energy Communities are not extended to hydrogen provisions. It is important that these typical users of a hydrogen network have the same rights as if they would be connected to the natural gas grid as it provides a level playing field between hydrogen and other energy carriers for relevant consumer categories (under the condition that current gas rules are aligned to those for electricity users, see in this regards Policy Area 4). Choices between energy carriers would be made on economic grounds as opposed to regulatory treatment.

It also avoids diverging measures between Member States for similar customer categories which could limit the uptake of hydrogen, at limited regulatory costs.

Option 2b also provides a proportionate approach in view of the expected customer base for hydrogen (larger, mainly industrial users). An approach like under Option 3a and 3b would be disproportional from this perspective and higher regulatory costs.

Non-reneweble low carbon fuels

Objective

Provide for a level playing field across different energy carriers for relevant consumer groups

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

No rules

NA

Definitions of LCH/ LCFs + legal basis for issuing GOs or reference to existing GOs article 19 of RED II.

Definitions of LCH/ LCFs + legal basis for deploying a certification system based on an adapted methodology (based on existing ones for RFNBOs and RCFs) and using existing voluntary schemes for applying and certifying it.

Like Option 2b

Like Option 2b

Pro

Less complexity in the market since only RES gases will be defined and certified under the certification system of RED II.

Like BAU

Defining LCFs will allow for their certification. The light GOs approach for certification will be less costly for suppliers to implement.

In the spirit of the EU Energy system integration strategy, this certification system can build up on the best practices using the existing tools under the RED II. In order to avoid inconsistencies and ensure positive synergies, it can rely (to the degree possible) on the existing methodologies for RFNBOs and RCFs certification. It can also use the existing system of voluntary schemes.

Using such comprehensive certification system would allow to enforce a level playing field across all energy decarbonisation options and this way ensure that Member states can effectively compare these options. Since such certification system is global, no discrimination can be expected to any economic operator inside or outside the EU.

Further, it would need to include a requirement applying to the Commission, the Member states and operators to include such fuels in the Union database (in a mass-balance system (MBS) 28 ). Although, the MBS can be adapted to reflect the specifics of the gas market, this would allow to ensure certain link between the supply and demand and would not allow the trade of sustainability certificates in a fully parallel system (as it is done under a pure book & claim system of GOs).

Synergies with other elements of the present proposal, in particular the proposed extension of the entry-exit system to DSO level and the abolition of cross-border tariffs for renewables and low carbon methane gas.

Like Option 2b

Like Option 2b

Cons

Not defining and certifying LCFs would mean that they would not be an available decarbonisation option for Member States or EU initiatives in harder to decarbonised sectors. This would be a missed opportunity to speed up the decarbonisation specifically in the short and medium term.

Like BAU

The light GOs approach may be problematic to implement if there would be reluctance by Member States to issue GOs in all circumstances and to include in the GOs the GHG emission footprint as mandatory information.

However, the main drawback of using this certification system would be the potentially detrimental effect on RES fuels and RES Hydrogen, which will be certified against the more complex methodology under a life-cycle analyses approach of RED II.

A comprehensive certification system can build up on the existing knowledge, methodologies, and infrastructure of RED II but will be more difficult and costly to implement.

Like Option 2b

Like Option 2b

Most suitable option

Option 2b

The main aim of the terminology and comprehensive certification system to be put in place for LCFs/ LCH is to ensure that all related GHG emissions are correctly accounted for in a life-cycle analyses approach. This in turn will enable Member States and economic operators alike to effectively compare their carbon footprint in a portfolio of possible energy solutions. Ultimately, such certification system will make a valuable contribution to market integrity and foster cross-border trade, specifically in the segment of hydrogen and hydrogen-based energy decarbonisation options. Taking also into account that such certification system will apply a global harmonised standard of certification, no discrimination can be expected to any economic operator inside or outside the EU.

Having all this in mind, Option 1b is the preferred option, since its content fulfils all the necessary pre-conditions to achieve this objective. It will be based on a harmonised certification methodology, integrating all GHG emissions as well as applied in a harmonised way by a system of certification schemes, recognised by the Commission. Including the so certified LCFs in the union database in a mass-balance system would make further support to market integrity by ensuring traceability and efficient transfer of data on GHG emissions footprint along the value chains, which is crucial for intra-EU trade but also for imports of LCFs into the EU.

Taking into account that the mandate of the development of the union database is already under RED II not much additional costs or administrative burden can be expected from its extension. The certification process would entail costs at the level of economic operators but it can be expected that they will be largely compensated by the economic opportunities which such certification would give in the context of the energy transition and achieving the decarbonisation targets, specifically at short and medium term.

The preferred option is likely to have synergies with other elements of the present proposal, in particular the proposal to extent the entry-exit system to DSO level and the abolition of cross-border tariffs for renewables and low carbon methane gas.

Regulation of H2 inter- connectors with third countries

Objective

Rules on the operation of hydrogen interconnectors with third countries should safeguard competition on the internal energy market and provide legal clarity for investors, operators and market participants.

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

No rules

No rules

Alignment with current rules in Gas Directive

Full application of EU-level H2 network operation rules (i.e. unbundling, third-party access and regulated tariffs) to H2 interconnectors between EU Member States and third countries (including possibility of regulatory exemptions for new interconnectors).

Option 2a + Mandatory EU-level IGA

As per Option 2a, rules for H2 interconnectors are set out in the Directive.

In addition, the detailed operational rules for the entire H2 interconnector shall be enshrined in an intergovernmental agreement (IGA), concluded by the EU and the connected third countries.

Like Option 2b

Like Option 2b

Pros

-

N/A

The full application of EU-level H2 network operation rules (i.e. unbundling, third-party access and regulated tariffs) to H2 interconnectors with third countries would ensure a minimum degree of non-discriminatory third-party use of international hydrogen interconnectors, thereby enabling competition on EU hydrogen markets.

The conclusion of an EU-level IGA would ensure that a single set of rules would apply to the entire H2 interconnector. This in turn would avoid ‘conflict of laws’ situations where divergent sets of rules apply to sections of the interconnector. If required, such EU-level IGAs could diverge from the generally applicable EU law. Coherence across IGAs for different interconnectors would be ensured by their exclusive conclusion at EU level.

Like Option 2b

Like Option 2b

Cons

Lack of legal clarity regarding applicability of H2 network operation rules to international interconnectors may deter investments and could result in legal disputes.

Risk of non-competitive market outcomes, limited market access and impediments for interconnection and cross-border trade.

N/A

International hydrogen interconnectors would typically be subject to two or more different legal orders (i.e. EU law and the laws of the third country or countries). This could result in a ‘conflict of laws’ situation where pipeline operators would have to apply divergent sets of operational rules to different sections of the hydrogen interconnectors.

Failure to agree on operational terms with the connected third countries might create obstacles to the construction and operation of new interconnectors.

Like Option 2b

Like Option 2b

Most suitable option

Option 2b

Option 2b builds upon the status quo for natural gas (i.e. application of EU market rules to interconnectors with third countries), but adds an IGA on operational rules prior to starting the operation of hydrogen interconnectors to help ensure the consistent application of the future EU framework on the operation of hydrogen networks to the entire infrastructure.

Regulated asset base (RAB)

Objective

Rules on regulated asset bases determine whether different types of network assets are financed by joint or separate network tariffs.

BAU
No additional measures

Option 1 
Rights for network operation tendered

Option 2
Main regulatory principles

Option 3
Big bang

2a: Main regulatory principles only

2b: Main regulatory principles with a vision

3a: Hydrogen rules by Big Bang

3b: Hydrogen rules by Big Bang plus

Measures

Separate RAB (due to current natural gas tariff rules)

Separate RAB (due to current natural gas rules)

Joint RAB allowed

Separate RAB

Sub-option (at MS discretion): separate RAB but financial flows possible between them (subject to conditions, including financial flows only levied on domestic users and under NRA supervision)

Separate RAB

Separate RAB

Pros

No cross-subsidies between gas and hydrogen possible via gas tariffs.

Competition distortion between private and regulated entities prevented.

Similar to BAU

Reduces administrative burden and regulatory costs.

Enables lower network tariffs in hydrogen ramp-up phase.

Prevents cross-subsidisation between gas and hydrogen network users. Allows for cost reflective tariff setting for each asset base.

Separate RABs from start facilitates valuation transferred assets

Sub-option:

Enables targeted cross subsidies of hydrogen networks to stabilise tariffs for early hydrogen network users. Cross-subsidies are transparent (as opposed in case of joint RAB) imposition on domestic users avoids cross-subsidies being financed by users in other MS.

Provides exit route for phase-out cross-subsidies and avoids combined-RAB lock-in.

Prevents cross-subsidisation between gas and hydrogen network users. Allow for cost reflective tariff setting for each asset base.

No possibility to support lower network tariffs in hydrogen ramp-up phase (within energy system)

Separate RABs from start facilitates valuation transferred assets.

Like Option 3a

Cons

Repurposing not- enabled.

Incentivising appropriate repurposing investments is challenging in a tendering approach.

Cross-subsidies between gas and hydrogen shippers and users.

Competition distortion among incumbent and new network operators.

Move to separate RABs later difficult.

In view of cross-border tariffs in natural gas, risk that domestic hydrogen network development is financed by consumers in other Member States.

Increased regulatory costs for operation and monitoring.

Sub-option:

Increased regulatory costs as may require ITC mechanism and NRA supervision.

Competition distortion among incumbent and new network operators (but less than under Joint RAB).

Increased regulatory costs.

Need for transfer of assets for repurposing may complicate repurposing.

Like Option 3a

Most suitable option

Option 2b

Separate RAB for hydrogen prevents uncontrolled and non-transparent cross-subsidies between users of different networks.

Sub-option: Targeted levies on domestic network exits allows for temporary cross-subsidisation in ramp-up phase, while avoiding an increase in cross-border tariffs and resulting detrimental impact on cross-border trade.

More detailed explanations on the issue of the RAB are provided in text form below.

Access of RES&LC gases to hubs and transmission grids

Objective

Enable access of local production of biomethane to the markets

BAU
No additional measures

Option 1 

Option 2

Option 3

Option 4

Measures

Access of RES gas is not explicitly dealt with in the current framework.

General principle of non-discrimination and the objective for NRAs to help to integrate production of gas from renewable energy sources in both transmission and distribution.

Access of locally produced gases to the hubs and the transmission grid.

Enabling physical reverse flows between DSO and TSO.

As Option 1 plus:

Connection obligation with firm capacity for new RES&LC gases.

Reducing costs of injection for renewable and low carbon gases

Pros

Limited administrative burden as no new legislation is introduced.

Compliance with the 55% GHG emission reduction target.

Improved marketing options.

Biomethane production might be realised at lower total costs as in Option 1.

State aid less needed.

Cons

Patchwork of various provisions in the Member States will persist

Investments costs for reverse flows compressors.

Reducing injection tariff and access tariff is not respecting fully the principle of costs-reflectivity.

Connection costs may increase the abatement costs by some €15 to 30/t (from a level of €400/t).

Most suitable option

Option 3

The option contains maximum of measures to support renewable gases. Some elements will be also imported from other options, namely rules on citizens energy communities included from the discarder option and assessed under Problem Area IV.

The costs of biomethane production would be lowered (slightly) by a possibility to release producers from injection and connection costs.

Treatment of cross- border tariffs (pancaking)

Objective

Ensure unhindered cross-border flow and trade of new gases

BAU
No additional measures

Option 1 

Option 2

Option 3

Option 4

Measures

Cross-border tariffs for transport of gases are set on interconnection points between MS. No detailed rules to facilitate regional mergers.

Removing cross-border tariffs from interconnection points within EU for RES&LC gases only. Eligibility would be based on presenting the GOs to the TSO.

Facilitating voluntary regional gas market mergers (Guidance by the Commission).

Measures for transparency of allowed revenues, costs benchmarking.

Removing cross-border and der tariffs from interconnection points within EU for all gases in the methane network.

Pros

Limited administrative burden as no new legislation is introduced. No need to negotiate an ITC mechanism between TSOs and NRAs.

Costs of RES&LC gases reduced. RES&LC gases can move more freely across the borders than natural methane.

Assistance for Member States voluntarily engaging in market mergers.

Measures on allowed revenues will reduce the outliers on cross-border tariffs.

May help tracking RES&LC consumption.

Overall welfare increase for consumers.

More gas-to-gas competition Wholesale prices in the S-E EU will fall.

Exit tariffs will need to increase in most MSs.

Peer review for allowed revenues.

Gas market design closer to the electricity market.

Cons

No promotion of regional mergers, no changes to current tariff system. Issue of pancaking is not addressed.

Option to address tariffs removal only on a regional level.

Significant impact on the European gas market.

Most TSOs will lose revenues, ITC will be necessary.

Administrative costs related to ITC mechanism which will be higher than in electricity.

Uncertainty for the gas-consuming industry.

Risk of gas to coal switch in power production in PL and NL.

Most suitable option

Option 3

The option would contribute to integrate RES&LC as it would allow transporting these gases free of cross-borders tariffs (avoiding pancaking for RES&LC). On top this options aims to introduce, measures for transparency of allowed revenue, and costs benchmarking as well as guidance facilitating voluntary market mergers.

Long term contracts (LTC)

Objective

Ensure long-term clarity for decarbonisation for gas sector and avoid lock-in effects, in line with climate-neutrality objective until 2050.

BAU
No additional measures

Option 1 
Allow RES&LC full market access

Option 2
Allow and promote RES&LC gases full market access

Option 3

Allow and promote RES&LC gases full market access, tackle issue of long term supply natural gas contracts and remove cross-border tariffs for RES&LC gases

Option 4

Allow and promote RES&LC gases full market access, tackle issue of long term supply natural gas contracts, EU standards for gas quality and remove cross-border tariffs for all gases

Measures

No sector specific rules exist as regards gas supply contracts in terms of their duration. Derogations from third party access possible on the take-or-pay obligations concluded in long-term supply contracts (Art. 35 and 48).

As Status Quo plus:

Remove privileges (derogations) for new long-term natural gas contracts, signed after [entry into force of the GR], and limit duration of such contracts to 2049.

As Option 3 plus:

Introduce time limit for new long-term contracts already before 2050.

Pros

No administrative burden.

Tendency to increase the market price for natural gas.

Increase the volume risk of the LTC buyer of natural gas.

Clear long-term signal to the industry.

Energy security maintained as short-term contracts still possible.

Similar as Option 3 but duration of contracts limited as from near future.

Cons

No clear signal to the industry.

New LTC can be signed and can run after 2050, no time limits. Derogations for LTCs are maintained. Negative impact on decarbonisation objectives.

Consumers would see a slight increase of their gas bill on a long term.

LTCs can still be signed for a long duration (e.g. 25 years).

No full ban of natural gas.

Consumers would see a slight increase of their gas bill on a long term.

No full ban of natural gas.

Most suitable option

Option 3

Removing the privileges for long term contracts and limiting their duration to 2049 will give a clear long-term signal to the industry towards decarbonisation at the same time maintaining energy security as short-term contracts will be still possible. This option may as well lead to a slight increase of wholesale gas prices with a long-term effect in terms of organising the energy transition.

Gas Quality

Objective

Ensure unhindered cross-border flows of gases and interoperability of markets

BAU
No additional measures

Option 1 

Option 2

Option 3

Option 4

Measures

Do nothing.

Stronger enforcement.

Revision of CEN standards to include renewable and low-carbon gases.

Reinforced cross-border coordination on gas quality management and transparency on national hydrogen blending levels.

EU rules setting principles for processes, roles, responsibilities, cost recovery and allocation, regulatory oversight and reinforced cross-border coordination of gas quality management.

Variant: Setting detailed EU rules.

As Option 2/3 plus:

EU-level harmonisation of gas quality standard for cross-border interconnection points, based on the quality of natural gas.

Variant: Quality standards potentially based on biomethane quality parameters.

Pros

Limited administrative burden as no new legislation is introduced.

Limits the risk of cross-border flow restriction and market segmentation.

Supports the integration of renewable and low-carbon hydrogen at the TSO level.

Limited intervention; leaves flexibility to the Member States on hydrogen blending.

Limited administrative costs.

Harmonised EU approach on gas quality management supports aligned application of gas quality standards.

Reinforced cross-border coordination limiting the risk of cross-border flow restriction and market segmentation to a minimum.

Leaves flexibility to Member States on application of gas quality standards for the domestic network (i.e. not interfering with the specificities of domestic gas production).

EU allowed cap for hydrogen blends for cross-border points supports the integration of renewable and low-carbon hydrogen into the network.

Harmonised approach on blending limits the risk of market segmentation.

Stakeholder support for EU-level harmonization of gas quality management and reinforced cross-border coordination.

EU gas quality standard provides fully harmonised approach for cross-border IPs, eliminating the risk of cross-border flow restrictions and market segmentation, strongly limiting the risk of cross-border disputes.

Supports the integration of biomethane by limiting the cost of adapting biomethane to existing gas quality standards.

Cons

Applicable standards would remain non-binding; risks of cross-border flow restrictions and market segmentation.

High potential of cross-border disputes due to differences in gas qualities/blending levels.

Gas quality specifications would continue to be mainly defined by the quality parameters of natural gas, limiting the integration of renewable and low-carbon gases in the existing gas network.

Stakeholder do not support this option.

Significant costs for TSOs/DSOs and end-users for adapting infrastructure elements and end-use appliances.

High abatement cost.

Risk of cross-border disputes due to differences in gas quality/blending levels remains very high, which may lead to market segmentation.

Risk of cross-border disputes due to differences in gas quality is limited but still remains.

Setting detailed EU rules for gas quality management might be over prescriptive, limiting the flexibility of Member States to reflect national specificities.

Increases cost of gas quality management to comply with the EU gas quality standard.

Biomethane quality standard would imply additional quality adaptation cost for other gases in the network.

High administrative costs for market participants and authorities.

Most suitable option

Option 3 (containing Option 2)

Reinforced cross-border coordination on gas quality limits the risk of cross-border flow restriction and market segmentation to a minimum. The harmonised EU approach on gas quality management supports aligned application of gas quality standards.

In detail:

Under the preferred option gas quality would be governed by a harmonised EU approach for cross-border interconnection points while leaving flexibility to the Member States on the application of gas quality standards in their domestic networks (i.e. without interfering with the specificities of domestic gas production).

The preferred option achieves the desired objective of ensuring unhindered cross-border gas flows by strengthening the cross-border regulatory framework and thereby limiting the risk of market segmentation to a minimum. In case Member States (or TSOs) transport cross-border gases, which do not comply with the applicable gas quality and/or blending specifications, the preferred option provides a dispute resolution tool to find agreements. These elements provide an increased clarity and visibility on gas quality and related processes for end-users. In addition, especially the EU-level rules on gas quality management address the risk of negative impacts of different gas qualities for end-users by allocating roles and responsibilities for gas quality handling to market participants, by increasing transparency on actual and forecasted gas quality and the cost of gas quality management, by setting out principles for the recovery of costs incurred by gas quality management and where necessary for the allocation of such costs also cross-border and by ensuring proper regulatory oversight for the improved framework.

The preferred option provides a proportionate approach by limiting the intervention to cross-border interconnection points to avoid market segmentation, without imposing gas quality standards or blending obligations at domestic level. In doing so, it leaves flexibility to the Member States to define such standards for the domestic network if they wish so, taking into account the specificities of domestic gas and hydrogen production.

In terms of subsidiarity, EU action is needed as, while voluntary standards could in theory lead to an alignment of gas quality specifications and hydrogen blending levels between Member States, they would lead to a convergence across Europe only slowly, or not at all. Further, fostering more efficient and integrated EU markets for gases requires a harmonised and coordinated approach by all Member States, which can only be achieved efficiently by EU action. This option also avoids the distortive effects of uncoordinated, fragmented policy initiatives as many Member States develop national approaches, e.g. with regard to allowed hydrogen blending levels. EU action has significant added-value by ensuring a coherent approach across all Member States.

In comparison, Option 1 relies solely on a cross-border dispute settlement tool, risking suboptimal outcomes and increasing the administrative costs for TSOs, NRAs and ACER (especially with an increased number of disputes due to differences in gas qualities and blending levels). As significantly different levels of blending are expected between Member States, this will not resolve cross-border flow constraints. In the absence of clear cross-border rules TSOs would likely reject the flows, or the injection of these gases, which would limit the integration of renewable and low-carbon gases. Voluntary standards could in theory lead to an alignment of gas quality specifications between Member States, if national authorities or network operators adopt them. For example, several interconnected Member States with high ambitions for hydrogen or biomethane integration might have an incentive to align their gas quality standards in order to ensure cross-border flows. In the practice however, the experience with the cross-border application of existing gas standards show, that the voluntary approach would lead to a convergence of gas standards across Europe only slowly, or not at all. Mandatory standards on the other hand (Option 4), could ensure the alignment of standards within the EU but might not reflect the national contexts and lead to unreasonable costs for adapting gas infrastructure and end-user equipment, appliances and processes.

Hydrogen blending cross-border framework

Objective

Ensure unhindered cross-border flows of gases and interoperability of markets

BAU
No additional measures

Option 1 

Allow RES&LC gases full market access

Option 2

Allow and promote RES&LC gases full market access

Option 3

Allow and promote RES&LC gases full market access, tackle issue of long term supply natural gas contracts and remove cross-border tariffs for RES&LC gases

Option 4

Allow and promote RES&LC gases full market access, tackle issue of long term supply natural gas contracts, EU standards for gas quality and remove cross-border tariffs for all gases

Measures

Do nothing.

As no rules for cross-border flows of hydrogen-gas blends exist, no implementation or enforcement would take place.

Reinforced cross-border coordination and transparency on national hydrogen blending levels.

EU rules setting an allowed cap for hydrogen blends that Member States must accept at cross-border interconnection points and reinforced cross-border coordination.

As Option 2/3 plus:

Prohibition against the acceptance of blending levels above maximum cap of hydrogen blends at cross-border IPs.

Pros

Limited administrative burden as no new legislation is introduced.

Limits the risk of cross-border flow restriction and market segmentation.

Supports the integration of renewable and low-carbon hydrogen at the TSO level.

Limited intervention; leaves flexibility to the Member States on hydrogen blending in the domestic network.

Strong stakeholder support for blending and for setting allowed blending thresholds at national level with EU cross-border framework.

Limited administrative costs.

EU allowed cap for hydrogen blends for cross-border points supports the integration of renewable and low-carbon hydrogen into the network.

Harmonised approach on blending limits the risk of market segmentation.

Leaves flexibility to Member States on application of gas quality standards for the domestic network (i.e. not interfering with the specificities of domestic gas production).

Reinforced cross-border coordination limiting the risk of cross-border flow restriction and market segmentation to a minimum.

Maximum cap of hydrogen blends limits the adaptation costs.

Cons

Applicable rules on hydrogen blends would continue to be set at national level; their application cross-border would not be aligned risking cross-border flow restrictions and market segmentation.

High potential of cross-border disputes due to differences in blending levels.

Stakeholder do not support this option.

Significant costs for TSOs/DSOs and end-users for adapting infrastructure elements and end-use appliances.

High abatement cost.

Risk of cross-border disputes due to differences in blending levels remains very high, which may lead to market segmentation.

Increasing adaptation and CO2 abatement costs (depending on the actual blending level chosen).

Divided views among stakeholders on the role of blending hydrogen. Limited support for EU-level allowed cap for hydrogen blends for cross-border points.

Only limited support by stakeholders in the public consultation for setting binding EU-level allowed cap for hydrogen blends at cross-border points.

Maximum cap of hydrogen blends might limit blending in a few Member States (depending on the actual threshold chosen).

High administrative costs for market participants and authorities.

Most suitable option

Option 3 (containing Option 2)

5% allowed cap for hydrogen blends at cross-border points, which TSOs must accept (but without setting a blending obligation).

An EU allowed cap for hydrogen blends for cross-border points supports the integration of renewable and low-carbon hydrogen into the network and limits the risk of market segmentation, without imposing a blending obligation, i.e. leaving choice to the Member States.

Setting this EU allowed cap at 5% would enable the integration of 70 TWh hydrogen per year at an adaptation cost of €3 bn/year. A higher cap would increase the adaptation costs drastically (€5 bn/year for 10% or €12 bn/year for 20%).

See further details below.

Blending level

No measure

Measure 1 only

5% min level

5% min & max

10%

20%

30%

Adaptation costs (€bn/year)

2.6

3.6

3.6

0.7

5.4

12.5

37.4

Avoided emissions

(Mt CO2/year)

4

6

8

5

10

21

33

Abatement costs (€/tCO2)

612

532

445

144

524

582

1124

LNG terminals

Objective

Ensure transparent access to LNG terminals for imported RES gases, including liquid hydrogen.

BAU
No additional measures

Option 1 
Allow RES&LC gases full market access

Option 2
Allow and promote RES&LC gases full market access

Option 3

Allow and promote RES&LC gases full market access, tackle issue of long term supply natural gas contracts and remove cross-border tariffs for RE&LC gases

Option 4

Allow and promote full RES gases market access, tackle issue of long term supply natural gas contracts, EU standards for gas quality and remove crossborder tariffs for all gases

Measures

LNG terminals are regulated with third party access (exemptions are possible).

No clear rules on capacity allocation and congestion management. Tariff discounts may be granted. Underutilization of capacities in some cases.

Principles concerning transparency, voluntary (e.g. led by industry) initiatives and supported by EU guidance.

Binding legal framework at EU level for transparency, congestion and access rules (secondary trading).

As Option 2 plus:

Mandatory market test/screening and development plans for LNG terminals (and gas storage) to receive RES&LC gases.

As Option 3 plus:

Removing the entry tariff discount in favour of LNG natural gas or extending existing discount also to RES&LC gases.

Pros

Small administrative cost

No need for a regulatory intervention, just legally non-binding action as guidelines by the EC.

Transparency may be improved (voluntarily).

Improvement of transparency, market access and congestion management – more efficient utilization of the terminals + additional available capacities for RES&LC gases

Obligation to consider the RES&LC gases imports.

Matching supply and demand (exporters and importers) by market tests.

More transparency which capacities are available for RES&LC gases.

If discount for RES&LC gases added, imports of these gases are incentivised.

Cons

Underutilization may remain.

Congestion may occur due to high volumes to be imported.

Mainly imports of natural gas.

Only transparency would be improved, only limited impact on RES&LC gases.

As it is voluntary action, the effects are less certain.

Need to adjust current regulatory framework - some burden for LSOs – ‘cost to adjust’.

Need to adjust current regulatory framework - some burden for LSOs ‘cost to adjust’.

If discount is removed, it can negatively impact energy supply of some MS.

Risks of cross-subsidization.

Most suitable option

Option 3

A mandatory market test/screening mechanism and development plans bring incentive to prepare for the imports of RES&LC gases. These mechanisms will contribute to match supply and demand and increase transparency on which capacities are available for RES&LC gases.

Network Planning

Objective

Ensure transparent and inclusive infrastructure planning

BAU
No additional measures

Option 1 
National Planning 49

Option 2
National Planning based on European Scenarios

Option 3

European Planning

Measures

Baseline: Do nothing

Note: Inclusion of hydrogen in the EU-wide network development plan (TYNDP) as proposed in the TEN-E

One single network plan (NDP) (including also storages, LNG and production) per Member State irrespective of the unbundling model chosen and the number of gas TSOs in the country.

Instead of providing a national plan, Member States can also opt to come up with a regional plan instead.

The NDP needs to be drawn up every two years (now: every year).

The network plan remains binding only for ISO and ITO certified TSOs to the extent valid today.

National regulatory authorities are empowered and required to ensure a transparent process.

The NDP includes information to what extent and from what point in time certain methane pipelines are not required anymore and could be used for other purposes (e.g. hydrogen-transport).

Introduction of a sustainability indicator.

Integrated planning on national level by requiring joint scenario building between gas and electricity.

The joint scenario needs to be aligned with the at least one scenario used for the TYNDP. This can also be ensured linking it to the relevant NECP, which is required to be in line with the climate goals.

Creation of a competence for NRA to assess the actual need for a hydrogen pipeline network.

Distribution system operators as well as LNG and storages need to be involved in the scenario building. NRAs may take decisions for setting a framework for the involvement (de-minimis rules, national DSO association).

Other energy carriers (e.g. hydrogen, district heating) as well as CO2 need to be taken into account in the scenarios, but not in the plan itself.

Provisions for national electricity plans needs to be amended to require joint scenario building.

Drawing up a system wide network development plan (i.e. going beyond joint scenario development), including gas, hydrogen and electricity on European level only.

Unregulated infrastructure investments and investment plans are taken into account when elaborating the national network development plan.

Pros

No additional burden on NRAs/TSOs that do not have a national plan.

Requiring a single, consolidated NDP avoids potential incoherencies between the visions of different gas TSOs operating in the same country (e.g. in France), leading to a more coherent, cost-efficient network planning procedure, lowering the risks of over-dimensioning the system or stranded assets.

Having plans in each MS ensures that PCIs are included with highest priority and ACER can provide an opinion on the consistency between the NDP and TYNDP.

Same as Option 1, plus:

Ensures that indirect interlinkages between gas and electricity are treated in a consistent way in subsequent processes.

Eliminating risks that electricity and gas TSOs plan the evolution of their systems based on incompatible assumptions (e.g. electricity TSOs assuming a strong deployment of heat pumps in the residential sector while the gas TSO assumes a deployment of gas boilers).

The transparency obligation (repurposing potential) and the performance of market test facilitates the evaluation of potential hydrogen-PCI projects under the revised TEN-E regulation, while reducing the risk of initial over dimensioning of the hydrogen-network.

Joint planning ensures that the efficiency of investments in the gas sector (incl. hydrogen) is compared to alternatives such as electricity networks, and that the most economically, environmentally sound and secure option is identified and selected.

Cons

Does not ensure consistency of European and national plans.

Higher planning costs/administrative burden.

Higher coordination/transaction costs between involved parties.

Risks that planning undermines individual sector performance and liability.

No available objective model to identify and optimise investment needs across different energy carriers → risk that implementation can only be done on low(er) level of sophistication not being suited for individual system planning.

The current TYNDP is not based on hydraulic modelling. TSOs would need to provide all detailed network information to ENTSOG. This may create confidentiality conflicts and increases the risk for critical infrastructure and could be better achieved on national or regional level.

Most suitable opion

Option 2

This option provides the best balance in terms of achieving the objective of more inclusive planning allowing for a conceptual system plan, but leaving the required level of detail sector specific. It also enables the identification and actual use of pipelines that for repurposing based on the market demand for hydrogen and informing about locations based on avoiding network costs.

Retail markets, consumer protection and engagement

Objective

Ensure adequate levels of customer empowerment and protection in the decarbonised market

Option 0

No additional measures

Option 1

Enforcement and soft implementation measures

Option 2

strengthened enforcement, enhanced implementation measures and intense consultations with stakeholders

Option 3

Flexible legislation

Option 4

Harmonization and extensive consumer safeguards

Measures

Baseline: Do nothing.

No new legislation is adopted. The problem drivers are addressed by strengthening enforcement, i.e. reinforced administrative cooperation, information campaigns, exchange of good practices without resorting to new legislation. In addition, Commission issues interpretative and guidance documents on switching and bills.

The same enforcement non regulatory measures as in Option 1 are complemented by bilateral consultations with Member States to try to progressively phase out price regulation. Soft legislation (COM Recommendation/Guidance on price regulation, billing, switching and price comparison tools). Renewable energy communities are supported by an interpretative note and enhanced through existing initiatives, such as the Energy Community Repository. All relevant smart metering provisions are consolidated in a single legislative act (no extra regulatory requirements are introduced) and use is made of the existing acquis and of further promotion of best practices. Data management arrangements are primarily left with Member States. Support to the EU Energy Poverty Advisory Hub is enhanced.

New legislation mostly mirroring the electricity provisions provides Member States leeway to adapt their laws to the conditions in national markets. Member States phase out blanket price regulation. Exemptions for households, micro-enterprises as well as vulnerable and energy poor households are defined at the EU level. The use of contract termination fees is restricted. Provisions on billing and switching are aligned with those in the Electricity Directive, The right to access objective and certified price comparison tools is granted to customers.

An improved, principle-based EU legal framework to support Member State action on vulnerable and energy poor consumers is put in place. The concept and enabling framework for ‘citizen energy communities’ is mirrored into EU gas legislation. EU data management rules are set up, along with measures for transparent and non-discriminatory access to data irrespectively of the data management model used. While the decision for smart metering remains with Member States, additional requirements are adopted for an enhanced deployment. That includes a set functionalities, a rollout target, and the right to a smart meter as well as regular revision of negative assessments, and a strong recommendation to carefully consider the benefits for selective, targeted rollouts.

New EU harmonised legislation going beyond the levels of customer empowerment and protection currently in force in electricity market is proposed. Member States phase out blanket price regulation. Exemptions for vulnerable and energy poor households are defined at the EU level. All switching-related fees are banned, including contract termination fees. NRAs offer (or fund) price comparison tools. Format and content of energy bills is partially harmonised. A uniform EU framework to monitor energy poverty and reduce disconnections is set up. The concept of ‘citizen energy communities’ is made more citizen-centred and coupled to an enabling framework with support measures. A standard EU data management model (data hub) is enforced throughout the EU, along with standardised formats for exchange of data. A mandatory throughout the EU smart metering rollout is legislated, irrespectively of the national cost-benefit assessment, with fixed functionalities that are mirroring those for electricity.

Pros

Little additional administrative burden resulting from enhanced enforcement, however, it would be limited as no new legislation is introduced.

Low cost of implementation.

More flexibility to Member States and NRAs to accommodate their national specificities in the measures.

Still relatively limited additional efforts needed by Member States, though increased (in comparison to Option 1), due to cooperation on phasing out regulated prices and implementing soft legislation, in addition to reinforced enforcement foreseen already in Option 1.

Soft legislation will provide further guidance to MS and once implemented, benefits to customers.

Some progress towards the phasing out of regulated prices may be achieved.

Low cost of implementation, though slightly higher than in Option 1.

More flexibility to Member States and NRAs to accommodate their national specificities in the measures.

Higher levels of non-household customer satisfaction as a result of the better service levels consumers receive in the non-regulated market.

Increase energy efficient consumption of gas caused by artificially low prices in non-household markets.

Better engagement of customers in transition and strengthened customer rights and satisfaction.

Positive environmental impact thanks to improved customer awareness of consumption and energy origin as well as increased public acceptance of renewable gas and private capital mobilisation through energy communities.

Transparent and non-discriminatory data access from eligible market parties resulting in a high net benefit for service providers and consumers and in increased competition in the retail market.

Significantly increased market opening, effective retail market competition.

Increase energy efficient consumption of gas caused by artificially low prices in all markets.

Strengthened rights for customers and improved customer satisfaction.

Possible improvement in consumer engagement to some extent.

Positive social impact due to the enhanced citizen focus of the energy community concept.

Easier enforcement of standardised, harmonised rules.

Cons

Does not ensure consistency of European and national frameworks.

No significant improvements of the status quo realistically expected. Does not align with EU policy targets and decarbonisation plans.

Consumer engagement and protection are only limitedly addressed. Low consumer satisfaction persists due to limited availability of innovative offers (including green) and high value services.

Maintain a fragmented, not updated to reflect market and technology developments regulatory framework across the EU which translates into administrative costs for entering new markets.

Higher planning costs/administrative burden (compared to Option 1).

Non-regulatory measures are unlikely to consistently and adequately address current issues, as they would rely on Member States’ proactive attitude without binding rules, with high risks of fragmented landscape throughout Europe in terms of customer empowerment and protection.

Does not align with EU policy targets and decarbonisation plans.

Low consumer satisfaction persists due to limited availability of innovative offers (including green) and high value services.

A fragmented regulatory framework across the EU also not reflecting of the latest market and technology developments.

Higher coordination/transaction costs between involved parties.

Increased costs and administrative burden for suppliers and increase in margins for suppliers.

Household customer satisfaction and availability of innovative offers (including green) increases but in 15 household markets it will depend on the speed of opening and competition paths of national gas retail markets.

Risks that planning undermines individual sector performance and liability.

No available objective model to identify and optimise investment needs across different energy carriers.

Uncertain effectiveness of measures to address current issues (e.g., suitability of NRA developed PCTs).

Expected political resistance to full harmonisation of certain consumer protection measures.

Increased administrative costs for public authorities to implement support measures for energy communities and high adaptation, divergently within the EU disproportionate costs by enforcing smart metering and data management solutions that do not fit all.

Most suitable option

Option 3

This option is based on proposing flexible legislation mirroring the electricity market with regard to customer protection and where relevant the empowerment provisions. It is likely to be the most effective, efficient, and consistent with other problem areas.