Sector integration, regulatory framework for hydrogen : final report.
Date: 2021-02-26
Institutions: Directorate-General for Energy
Subjects: energy grid, energy market, energy production, hydrogen, industrial infrastructure, pipeline transport, regulation (EU), renewable energy, report

Sector integration – 
Regulatory framework for 
hydrogen 

Final Report 

[Written by Trinomics and LBST] 
[December 2021] 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2021 

Directorate-General for Energy  
Internal Energy Market 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Authors: 

Luc van Nuffel (Trinomics) 
João Gorenstein Dedecca (Trinomics) 
Frank Gérard (Trinomics) 
Ondřej Černý (Trinomics) 

Ulrich Bünger (LBST) 
Matthias Altmann (LBST) 
Uwe Albrecht (LBST) 

December 2021 

EUROPEAN COMMISSION 

Directorate-General for Energy 
Directorate B — Internal Energy Market 
Unit B2 — Wholesale markets; electricity & gas 

European Commission 
B-1049 Brussels 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
   
Sector integration – Regulatory framework for hydrogen 

Sector integration – 
Regulatory framework for 
hydrogen 

 
 
 
 
 
 
 
 
 
 
 
 
  
 
 
Sector integration – Regulatory framework for hydrogen 

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Luxembourg: Publications Office of the European Union, 2021 
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Catalogue number: MJ-01-20-225-EN-N 
ISBN : 978-92-76-17846-0 
doi: 10.2833/411951 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

TABLE OF CONTENTS 

EXECUTIVE SUMMARY ..................................................................................................... I 

1 

PROTOTYPE PATHWAYS FOR HYDROGEN GAS INFRASTRUCTURE ................................. 1 

Approach ..................................................................................................... 1 
1.1 
1.2  Hydrogen gas infrastructure development pathways towards 2050 ..................... 4 
1.3 
Pathway justification ..................................................................................... 9 
1.4  Hydrogen import pathways .......................................................................... 32 

2 

PIPELINES AS A NATURAL MONOPOLY? .................................................................. 35 

2.1 
Approach ................................................................................................... 35 
2.2  Natural monopoly assessment ...................................................................... 35 
2.3  Conclusions ................................................................................................ 42 

3 

HYDROGEN NETWORK INFRASTRUCTURE REGULATION ............................................ 43 

3.1 
Experiences in the regulation of natural gas, electricity and telecom industries ... 46 
3.2  Unbundling ................................................................................................ 49 
3.3  Network access .......................................................................................... 60 
3.4  Revenue regulation ..................................................................................... 65 
3.5  Network planning ....................................................................................... 73 
3.6  Network charging ....................................................................................... 83 
3.7  Capacity allocation and congestion management ............................................ 88 
3.8  Regulation of distribution networks ............................................................... 90 
Transitional measures and regulatory experimentation .................................... 91 
3.9 

4 

HYDROGEN MARKET DESIGN AND DEVELOPMENT.................................................... 94 

4.1 
Introduction ............................................................................................... 94 
4.2  Market design elements ............................................................................... 98 

5 

DEVELOPMENT AND ASSESSMENT OF OPTIONS FOR A REGULATORY FRAMEWORK .... 119 

5.1  Context definition ..................................................................................... 119 
5.2  Objective setting ...................................................................................... 122 
Assessment methodology .......................................................................... 123 
5.3 
5.4  Regulatory framework options .................................................................... 125 
Assessment of hydrogen regulatory framework options ................................. 132 
5.5 

6 

KEY FINDINGS AND RECOMMENDATIONS ............................................................. 143 

ANNEX A DETAILED ASSESSMENT OF REGULATORY FRAMEWORK OPTIONS ..................... 147 

6 

 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

LIST OF FIGURES 

Figure 1-1 Hydrogen gas infrastructure specific assets from well-to-end-use .............................. 1 
Figure 1-2 Relation of different hydrogen definitions ................................................................ 2 
Figure 1-3 Differentiation and colour coding for hydrogen from various sources using allowed CO2-

emission levels ............................................................................................................ 3 

Figure 1-4 Large-scale energy infrastructures in an energy system dominated by renewable 

energies (CO2 for CCS) ................................................................................................. 4 
Figure 1-5 Tentative generic hydrogen gas infrastructure pathways and their coherence .............. 5 
Figure 1-6 EU renewable electricity generation potentials, by Member State (average of ranges per 
Member State) ........................................................................................................... 10 

Figure 1-7 Stacked renewable annual production vs firm electricity demand at country level in 

METIS scenario 2050 (n this case including the additional direct electricity demand by 2050 
but excluding demand from the electrolyser fleet) ........................................................... 11 
Figure 1-8 EC PCI’s European Gas Network map (2019) .......................................................... 12 
Figure 1-9 Population specific variable technical renewable electricity production potential and 

transmission grid length for all EU Member States + UK (sorted for pipeline length) ............ 13 
Figure 1-10 Production costs for hydrogen from NG-SMR, NG-Pyrolysis and water electrolysis ..... 16 
Figure 1-11 Hydrogen production costs from solar hybrid PV and onshore wind systems in the long-
term .......................................................................................................................... 19 

Figure 1-12 Suggestion for a future German gas grid infrastructure with close to zero hydrogen 

admixture at TSO level ................................................................................................ 20 
Figure 1-13 Map of European salt cavern structures across Europe ........................................... 23 
Figure 1-14 Seasonality of the energy demand for heating and cooling by Member States in Europe
 ................................................................................................................................ 27 
Figure 1-15 Definition of five EU regions with differing interests in gas infrastructures ................ 30 
Figure 1-16 Spiderweb graph of criteria valuation for five EU regions ........................................ 31 
Figure 1-17 Cost of hydrogen storage and transmission by pipeline and ship and cost of hydrogen 

liquefaction and conversion  ......................................................................................... 33 
Figure 3-1 Structure of this chapter and relation to regulatory elements ................................... 43 
Figure 3-2 Illustration of dimensions of intra- and cross-sectoral unbundling ............................. 49 
Figure 3-3 Regulation of the allowed / target revenues of network operators ............................. 66 
Figure 4-1 Hydrogen market design elements ........................................................................ 98 
Figure 4-2 Gas wholesale market volumes ........................................................................... 100 
Figure 4-3 Short Term Standardised Products definition ........................................................ 109 

LIST OF BOXES 

Box 3-1 Current regulation of hydrogen networks in the EU and US .......................................... 43 
Box 3-2 The importance of regulatory certainty and timing of EU and MS-level legislation ........... 44 
Box 3-3 Competition for-the-market and the regulation of hydrogen networks ........................... 53 
Box 3-4 Energinet as a regulated multi-vector operator in Denmark ......................................... 57 
Box 3-5 Emergent and isolated markets provisions in the Gas Directive .................................... 59 
Box 3-6 Regulatory tests for nTPA/rTPA regimes .................................................................... 63 
Box 3-7 The essential facilities doctrine and its application to hydrogen networks ....................... 64 
Box 3-8 CEER’s note on stranded assets in distribution networks.............................................. 66 
Box 3-9 CEER’s paper on whole-system approaches ............................................................... 74 
Box 3-10 The MosaHYc (Mosel Saar HYdrogen Conversion) project ........................................... 75 
Box 3-11 A proposal for an EU hydrogen TSO ........................................................................ 77 
Box 3-12 Regulatory experimentation: waivers, exemption procedures and regulatory sandboxes 93 
Box 4-1 Wholesale gas markets ........................................................................................... 99 
Box 4-2 Involvement of energy regulators in the establishment of exchanges .......................... 100 
Box 4-3 REMIT and hydrogen markets ................................................................................ 118 
Box 5-1 Sector development pathway according to EU hydrogen strategy ............................... 124 
Box 5-2 The Hydrogen Target Model ................................................................................... 127 
Box 5-3 Extension of the Gas Market Design to hydrogen ...................................................... 128 

 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

LIST OF TABLES 

Table 1-1 Criteria to explain the assets along relevant hydrogen value chains in more detail ........ 9 
Table 1-2 Population specific variable technical RES-E production potential by Member State [TWh/ 
(yr∙mio inhabitants)] ................................................................................................... 11 
Table 1-3 Assets along relevant hydrogen value chains for EU Member States ........................... 13 
Table 1-4 Member State specific evaluation of asset-based criteria list (“blanks” denotes no 

evaluation possible) .................................................................................................... 31 
Table 2-1 Hydrogen pipelines and pipeline systems in operation in Europe ................................ 40 
Table 3-1 Selected barriers and measures in the regulation and market design of EU electricity and 
natural gas sectors ...................................................................................................... 47 
Table 3-2 Unbundling for different future hydrogen network operators ...................................... 52 
Table 3-3 Unbundling options .............................................................................................. 52 
Table 3-4 Unbundling options for hydrogen based on natural gas regulatory frameworks ............ 59 
Table 3-5 TPA options for hydrogen / combined network operators ........................................... 62 
Table 3-6 Network access options for hydrogen based on natural gas regulatory frameworks ...... 65 
Table 3-7 Cost re-allocation options ...................................................................................... 69 
Table 3-8 Depreciation period (in years) of gas network assets ................................................ 72 
Table 3-9 Revenue regulation options based on the natural gas regulatory framework ................ 73 
Table 3-10 Network planning responsibility and oversight options ............................................ 78 
Table 3-11 Cross-energy carrier network planning options ....................................................... 80 
Table 3-12 Cross-border network planning ............................................................................ 81 
Table 3-13 Network planning options based on natural gas regulatory frameworks ..................... 83 
Table 3-14 Network charging model options .......................................................................... 85 
Table 3-15 Network charging options based on natural gas regulatory frameworks ..................... 88 
Table 3-16 CACM options in the EU hydrogen regulatory framework ......................................... 89 
Table 3-17 CACM options based on natural gas regulatory frameworks ..................................... 90 
Table 3-18 Common/different aspects for hydrogen distribution networks ................................. 91 
Table 4-1 Legal provisions of the Gas Directive relevant for hydrogen markets .......................... 95 
Table 4-2 Legal provisions of the Gas Regulation potentially relevant for hydrogen markets ........ 95 
Table 4-3 Key markets’ characteristics .................................................................................. 96 
Table 4-4 Value chain characteristics .................................................................................... 96 
Table 4-5 Potential market failures or barriers ....................................................................... 98 
Table 4-6 Types of wholesale energy markets ........................................................................ 99 
Table 4-7 Stakeholders’ opinions on OTC platforms and exchanges topics ............................... 102 
Table 4-8 Regulatory intervention in the establishment of hydrogen markets ........................... 104 
Table 4-9 Options for the establishment of hydrogen trading platforms and exchanges ............. 105 
Table 4-10 Gas market product types and their suitability for hydrogen trade .......................... 106 
Table 4-11 Wholesale hydrogen market product types standardisation .................................... 108 
Table 4-12 Stakeholders’ opinions on balancing rules and options .......................................... 111 
Table 4-13 Features and tools of the BTM for gas and suitability for hydrogen balancing ........... 112 
Table 4-14 Balancing rules and tools for the hydrogen system ............................................... 113 
Table 4-15 Storage technology options per market type ........................................................ 115 
Table 4-16 Options for access to underground hydrogen storage ............................................ 116 
Table 5-1 Indicators for impact assessment ......................................................................... 125 
Table 5-2 Overview of regulatory framework options assessed ............................................... 129 
Table 5-3 Detailed parameters of the regulatory framework options selected ........................... 130 
Table 5-4 Summary of impact of regulatory packages according to assessment criteria ............. 133 
Table 5-5 Transitional measures applicable per regulatory framework option ........................... 135 
Table 5-6 Summary of the pathway assessment ................................................................... 137 
Table 5-7 Regulatory framework options robustness ............................................................. 138 
Table 5-8 Roadmap for implementation of the regulatory framework options ........................... 141 
Table 5-9 Assessment of variants on the horizontal unbundling option for gas network operators

 .............................................................................................................................. 142 

 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

EXECUTIVE SUMMARY 

The main objective of this study is to develop and assess options for a potential EU regulatory 
framework for dedicated hydrogen networks and markets. The study provides inputs to pro-actively 
develop EU regulation that anticipates a significant development of dedicated hydrogen pipeline 
infrastructure to facilitate large-scale production and use of renewable and/or low-carbon hydrogen 
in the EU. 

Prototype pathways for hydrogen gas infrastructure 

In chapter 1, four generic pathways have been developed to describe the potential introduction of 
renewable and low-carbon hydrogen into the different national (or regional) energy systems in the 
EU to fulfil the 2050 decarbonisation policy targets. They comprise pathways starting from either a 
low or high RES-potential and a modestly- or well-established natural gas grid. 

The exercise to identify and analyse potential generic development pathways clearly results in the 
learning that an EU-wide harmonised regulatory approach would enable EU Member States to 
benefit from higher techno-economic benefits (economies of scale) and infrastructural synergies 
(cross-border hydrogen exchange) and hence from improved efficiencies and significant cost 
reductions, compared to a scenario with uncoordinated and hence possibly diverging national 
regulatory approaches.  

Non-exhaustive arguments for an EU hydrogen regulatory framework are: 

  Hydrogen production base: Member States with significant renewable electricity 

generation potential could aim to substitute their natural gas use by renewable electricity-
based hydrogen and even become net exporters, and consequently have an interest in 
repurposing their methane networks which would otherwise be decommissioned. This 
could help to efficiently facilitate the upscaling of hydrogen as an energy carrier in Member 
States with hydrogen-intensive energy strategies, which would in turn contribute to fulfil 
some of EC’s most important energy and climate policy goals (climate change mitigation, 
reducing energy import dependency and improve energy efficiency). 

  Hydrogen quality definition: An EU-wide hydrogen quality harmonisation may facilitate 
the development of hydrogen end-use equipment and appliances at larger production 
scales as well as foster the integration of the EU hydrogen market, helping to align 
national hydrogen pathways. 

  Hydrogen-blending level: Shared learning as well as an exchange on and testing of 

concepts will foster a rapid EU-wide implementation of blending hydrogen into the natural 
gas grid, which is an adequate option to facilitate the deployment of hydrogen. Several EU 
Member States are already taking initiatives to this end. As far as observed, all concerned 
grid operators have indicated their willingness for cooperation and EU-wide harmonisation. 
  Conversion of existing methane networks to hydrogen or new-build: Early analysis 
has shown that the conversion of existing methane infrastructure to hydrogen operation is 
significantly cheaper than new-build hydrogen pipelines. Common material standards and 
operating routines will support conversion activities across the EU. If deemed necessary, 
this will also help to develop well-defined interfaces to import renewable or low-carbon 
hydrogen through pipelines from outside of Europe. 

  Today’s hydrogen gas pipeline business: An early European regulatory framework 

could consider the long-term supply contracts and network assets of existing private 
hydrogen operators and, at the same time, build on the existing infrastructure to develop 
the wider energy system use of hydrogen in a stepwise manner. 

Pipelines as a natural monopoly? 

Chapter 2 analyses whether and to what extent dedicated hydrogen networks give rise to a natural 
monopoly justifying regulatory intervention. Although the hydrogen market development is in very 
early stages, there are strong indications that hydrogen transmission and distribution networks 
may constitute a natural monopoly in mature hydrogen markets, where hydrogen becomes or is 
close to becoming a traded commodity. This would coincide with phase 2 (2025-2030), and more 
broadly phase 3 (2030 towards 2050) defined in the European Commission’s Hydrogen Strategy. 
Also, in emerging markets, there is a relevant probability of natural monopolies to occur due to the 
sub-additive investment cost curves of pipelines, and the fact that repurposing methane pipelines 
to hydrogen will be less expensive than new-build and will hence provide a competitive advantage 
to the concerned owners/operators.  

The views of stakeholders diverge on the exact circumstances and the adequate timing for 
regulatory intervention with some stakeholders supporting rather early regulatory intervention, 

i 

 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

while others prefer late actions. A view voiced rather widely is to apply market tests, and to 
actively develop regulatory approaches step by step. Starting early with thorough tests and 
validations accompanied by scientific evaluation support is a robust no-regret approach before 
implementing any regulation.  

Regulatory elements for dedicated hydrogen networks and markets 

Chapters 3 and 4 develop a number of options for the different network regulation and market 
design elements shown in the figure below. The options developed for each regulatory element are 
either based on the EU natural gas regulatory framework or are developed as a ‘greenfield’ 
approach. While an analysis per regulatory element facilitates the development of the options, any 
EU regulatory framework for hydrogen must be developed and assessed holistically, given the 
interdependencies between the different regulatory elements. This global analysis is extensively 
presented in chapter 5 of this study. 

Network access

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n Unbundling
o
i
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a
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e
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l

Network planning

Network charging

Revenue regulation

t
e
k
r
a
M

n Trade platforms & exchanges
g
i
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e
d

Hydrogen balancing

Definition of market product types

Access to large-scale storage

Licensing for suppliers and traders 

Capacity allocation and congestion 
management

Distribution networks

Development and assessment of EU hydrogen regulatory framework options 

Hydrogen is poised to play an important role in the EU energy transition, as indicated by the EU 
Hydrogen Strategy, the impact assessment for the 2030 Climate Target Plan, and the Long-term 
Strategy. 

To facilitate the large-scale development of the hydrogen sector according to the pathways 
identified in chapter 1, adequate policies will be necessary to enable the deployment of hydrogen 
production, trade, supply, transmission/distribution, storage, as well as of end-use equipment and 
appliances at the pace required for the energy transition. Given the current absence of economic 
regulation of the hydrogen sector at the EU and Member State level, this study contributes to 
determining the appropriate level of EU regulation to facilitate the optimal development of 
hydrogen infrastructure and markets. 

The analysis of chapter 2 indicates that several factors may justify some level of hydrogen sector 
regulation, including the sub-additive investment costs of hydrogen network assets leading to the 
need to ensure non-discriminatory third party access to networks (and to large-scale storage), the 
societal benefits of integrated network planning, and the potential cost savings resulting from 
repurposing methane infrastructure to hydrogen compared to new-build. 

Both regulated and market actors of the EU energy sector highlighted the need for regulatory 
certainty at both the EU and national levels. EU regulatory action for hydrogen can be based on 
article 194 of the Treaty on the Functioning of the EU (TFEU), which is also the basis for the EU 
regulatory framework for electricity and natural gas. 

By providing a level playing field for all market participants and technologies across the EU, 
adequate EU action can provide regulatory certainty, promote integrated network planning and 
operation of the energy system, facilitate the integration of the future hydrogen market, and 
minimise the risks of distortion to the overall EU internal energy market. EU action should employ 
the best practices and lessons learned from the experience in the natural gas and electricity 
sectors, and also leverage existing EU-level organisations and institutions where appropriate. 

The design of a new EU regulatory framework for hydrogen needs to be robust (i.e. perform 
adequately in any foreseeable transition pathway) and properly take into account the high 
uncertainty level at this stage, the overall incipient stage of development of hydrogen 
infrastructure and markets, and the different development speeds across end-use sectors and 
Member States. Moreover, any hydrogen regulation should be aligned with other developments in 
energy regulation, particularly regarding the promotion of electricity and gas systems integration, 
the use of incentive-based network regulation, and the simultaneous provision of regulatory 
stability and flexibility. 

ii 

 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

The EU regulatory framework for natural gas has been introduced when the EU gas sector had 
already developed for several decades, which constrained regulatory options. The future hydrogen 
sector regulation is comparatively less constrained and must take a number of specific points into 
account. Repurposing methane infrastructure to hydrogen will facilitate the development of large 
segments of the future hydrogen networks, which will in particular support hydrogen-intensive 
scenarios. Hence, there is a significant potential role for methane network operators, but also for 
existing private hydrogen operators given their relevant assets and expertise. Moreover, trading 
hydrogen via organised market platforms and exchanges for methane gases can accelerate the 
development of a well-functioning, liquid hydrogen market. Finally, existing long-term supply 
contracts and network assets of private hydrogen network operators should properly be considered 
when implementing a regulatory framework.  

The EU regulatory framework options assessed in this study and summarised in the table below 
range from a de minimis intervention to avoid distortions of the internal energy market (the ‘EU 
light’ option), to a regulatory framework similar to that for natural gas (the ‘Full EU’ option), and 
finally an ambitious regulatory framework further advancing the integration of the internal energy 
market (the ‘Full+ EU’ option). Competition for-the-market (i.e. tendering hydrogen network 
concessions) could be used to introduce a competitive element and complement the regulation of 
hydrogen networks. 

There is still strong uncertainty regarding the energy transition pathways, but given the ambitious 
EU climate and energy targets, competition and energy sector-specific regulation at EU level should 
accommodate pathways where renewable and low-carbon hydrogen play an increasing role, while 
also respecting the right of Member States to pursue other decarbonisation pathways. 

The Full/Full+ EU options provide, from the start, an adequate regulatory framework for the timely 
development of an internal hydrogen market, supported by dedicated infrastructure accessible to 
all network users and coordinated with the electricity, methane, and heat sectors. These options 
also provide sufficient flexibility through transitional rules and a Hydrogen Target Model for the 
development of local hydrogen clusters or valleys and allow Member States to develop economies 
of scale and of scope with the methane sector, while also ensuring a level-playing field and 
respecting existing long-term hydrogen supply contracts and network assets. By being compatible 
with the long-term policy targets and providing flexibility to Member States, they minimise the ex-
post regulatory costs and provide regulatory certainty. 

By fostering integrated network planning and market coupling especially, the Full+ EU regulation 
would provide an improved level playing field for hydrogen market participants across Europe. 
However, harnessing the full benefits of the option implies addressing existing differences in the 
regulatory provisions and structure of the electricity and methane sectors. 

Chapter 5 provides a detailed assessment of the options, including the robustness to the pathways 
and a roadmap for implementation. Whichever regulatory approach is ultimately opted for, a 
number of key principles should be respected to enable the hydrogen sector to efficiently 
contribute to reaching the major EU and national energy and climate objectives: 

  Non-discriminatory third-party access to hydrogen networks (and large-scale storage) 
should be guaranteed for all market operators, with only limited and duly justified 
exemptions; 

  Network planning should be integrated across market areas, energy carriers, and network 
levels, with strong EU and national regulatory oversight and public consultation. It should 
also be aligned to policy objectives. The risk for stranded assets should be minimised, not 
only when considering conversion of existing methane infrastructure to hydrogen, but also 
when considering new investment in fossil gas or fossil-based hydrogen infrastructure. 
Given the EU decarbonisation targets and the pathways uncertainty, it is necessary to 
carefully assess the needs for fossil gas-based infrastructure and to apply adequate 
sustainability requirements to new energy infrastructure investments; 

  Member States should be allowed to realise efficiency gains and economies of scope 
through combined natural gas and hydrogen network operators. But this should not 
compromise transparency and cost-reflectiveness of grid tariffs; 
The regulatory framework should provide flexibility through transitional measures such as 
exemption procedures to isolated hydrogen clusters. A Hydrogen Target Model could be 
defined in order to guide Member States in developing regulation which is aligned with the 
EU framework and does not hamper the later interconnection of their hydrogen system. 

 

iii 

 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Overview of regulatory framework options assessed 

No immediate 
EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

Common operation of methane and hydrogen networks authorised by EU law 

+ EU-level H2 TSO 

Accounts 

Accounts 
Variant: legal + functional 

Exemption from unbundling, rTPA, 
rTariffs for specific cases 

Legal unbundling, rTPA and rTariffs 
Exemptions requires a market test / sunset clause 

rTPA / nTPA choice 

Regulated TPA 

Not regulated 
at EU level 

Harmonised principles and tariff 
structures 

Market coupling + Harmonised 
principles and tariff structures 

ENTSO-H2 
Requirements for national planning 

With EU TSO organisation 
Requirements for national planning 

Role of gas 
TSOs 

Horizontal 
unbundling 
from 
regulated CH4 
infra 

Role of 
private 
hydrogen 
networks 

TSO network 
TPA rules 

Network 
tariffication 

Planning 

CACM 

No H2 specific EU regulation 

Rules for cross-market area CACM 

Market coupling 
Rules for cross-border and domestic 
CACM 

Balancing 

Access to 
storage 

Organised 
market 
platforms or 
exchanges 

Individual balancing responsibility for 
market players 
Residual balancing by TSOs 
National/multinational balancing zones 

Individual balancing responsibility for 
market players 
Residual balancing by EU TSO 
EU balancing zone 

rTPA / nTPA choice 

Regulated TPA 

No H2 specific EU regulation 

Harmonised market rules 
REMIT scope includes hydrogen 

+ market area managers 

iv 

 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

1  PROTOTYPE PATHWAYS FOR HYDROGEN GAS INFRASTRUCTURE 

To draw up four representative generic pathways that may give rise to the development of a 
dedicated hydrogen network within the EU, the European hydrogen strategy along with the plans of 
individual Member States have been assessed. Several plans and strategies have been emerging in 
the recent past.1 During the course of the study five national strategies have been published (NL, 
DE, PT, ES, FR + NO) alongside the European Hydrogen Strategy (July 2020) and further ones are 
expected in the near future (AU, PO, IT).  

In view of a future European hydrogen gas infrastructure2 the specific focus of this analysis is on 
hydrogen pipeline infrastructure and seasonal hydrogen storage development. In addition, 
hydrogen gas strategies developed by national authorities, industry, or associations have been 
considered. The assessment is based on both desk research and interviews with stakeholders from 
the gas infrastructure business in various EU Member States. Finally, during the course of work for 
this study two European key documents have been published3 to which we have aligned our report 
in a final adjustment run. 

Figure 1-1 Hydrogen gas infrastructure specific assets from well-to-end-use 

1 International Hydrogen Strategies. A study by Ludwig-Bölkow-Systemtechnik (LBST) commissioned by and in 
cooperation with the World Energy Council Germany, September 2020, 
https://www.weltenergierat.de/international-hydrogen-strategies/. 
2 Different from the project for the Fuel Cell and Hydrogen Joint Undertaking (FCH JU) [Study on opportunities 
arising from the inclusion of Hydrogen Energy Technologies in the National Energy & Climate Plans. Study by 
Trinomics and LBST for FCH-JU, final report, August 2020], the focus of this assessment is on specific national 
strategies related to hydrogen gas infrastructure. In this respect, Germany has revealed its gas infrastructure 
ambitions in a consultation process. Other Member States have included specific hydrogen gas infrastructure 
aspects as part of their national hydrogen strategies or will do so in the near future, such as the Netherlands, 
Portugal, Spain and Italy.  
3 [COM(2020) 301 final]: Communication from the Commission to the European Parliament, the Council, the 
European Economic and Social Committee and the Committee of the Regions: A hydrogen strategy for a 
climate-neutral Europe, Brussels, 8th June 2020, https://eur-lex.europa.eu/legal-
content/EN/TXT/?qid=1594897267722&uri=CELEX%3A52020DC0301 and European Hydrogen Backbone – How 
a dedicated hydrogen infrastructure can be created. Study report by Enagás, Energinet, Fluxys Belgium, 
Gasunie, GRTgaz, NET4GAS, OGE, ONTRAS, Snam, Swedegas and Teréga, July 2020, 
https://gasforclimate2050.eu/sdm_downloads/european-hydrogen-backbone. 

1 

 
 
 
 
 
 
 
 
                                                
 
Sector integration – Regulatory framework for hydrogen 

In order to structure this approach, relevant and major hydrogen infrastructure assets from well-
to-end-use have been defined as presented in Figure 1-1. The dashed box indicates the general 
scope of this study, the dotted boxes indicate the additional assets considered in this chapter. The 
relevant technologies (= assets) will become major building blocks of the Member State strategies, 
covering both central and decentral domestic hydrogen production schemes as well as hydrogen 
trade across the EU and imports from outside the EU. Other technologies such as hydrogen 
production by gasification from biogas or from coal, or by other production technologies exist, but 
have been left out intentionally for the sake of simplicity. The different types of hydrogen have 
been defined by the European Hydrogen Strategy [COM(2020) 301 final] as ‘electricity-based 
hydrogen’, ‘renewable or clean hydrogen’, ‘fossil based hydrogen’, ‘fossil-based hydrogen with 
carbon capture’, ‘low-carbon hydrogen’ and ‘hydrogen-derived synthetic fuels’. In other strategies 
a colour coding has been applied to define hydrogen produced from different energy feeds: 

  Grey: by water electrolysis using an electricity mix4, including renewable electricity, but 
also coal, mineral oil, natural gas and nuclear energy, and by steam reforming of natural 
gas (SMR)5, partial oxidation of mineral oil (POX) or coal gasification, 

  Green: by water electrolysis using renewable (i.e. CO2-free) electricity,  
  Blue: by steam methane reforming of natural gas (SMR) combined with carbon capture 

and storage (CCS) (i.e. fossil-based and CO2-reduced emissions)6 and 

  Turquoise by pyrolysis of fossil methane with the by-product carbon deposited or secured 
against release to the atmosphere as CO2 any later time (i.e. fossil-based and CO2-reduced 
emissions). 

The relation of the different definitions is presented in Figure 1-2, headlines representing the 
European definition. It should however be noted that sometimes additional hydrogen ‘colours’ are 
used such as pink for hydrogen produced from nuclear electricity. Also, some sources suggest to 
also define hydrogen from biomass gasification as green hydrogen. Instead we here have kept to 
the strictest definition which has e.g. also been suggested by the German Federal Ministry of 
Education and Research7. 

Figure 1-2 Relation of different hydrogen definitions  

4 At growing renewable electricity shares this hydrogen may eventually become “green” depending on the 
effective share of RES-E in the electricity mix. 
5 The by far highest share of today’s hydrogen use is produced by steam methane reforming of natural gas. 
6 
 Blue hydrogen is strictly speaking no zero-carbon technology, as it comprises residual CO2-emissions along the 
energy chain. There is an ongoing debate on the potential sources and means/costs to reduce these CO2-
emissions to a minimum. A wide range of residual CO2-emissions of less than 10% (without NG provision, study 
for the UK by G. Allard Reigstad, P. Coussy, J. Straus, Ch. Bordin, St. Jaehnert, S.Ø. Størset, B. Ruff: Hydrogen 
for Europe Final report of the pre-study, August 2019) and up to 36% (new ATR-based processes according to 
St. Bukold: Kurzstudie – Blauer Wasserstoff – Perspektiven und Grenzen eines neuen Technologiepfades, study 
for Greenpeace Germany, January 2020) have been reported by literature for different assumptions, pathways, 
and cases/locations. 
7 See https://www.bmbf.de/de/eine-kleine-wasserstoff-farbenlehre-10879.html.  

2 

 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

In an attempt to avoid ambiguity, the European harmonisation approach for hydrogen certification 
CertifHy has suggested a differentiation by defining the specific CO2-emission levels more explicitly 
as shown in Figure 1-38. 

Figure 1-3 Differentiation and colour coding for hydrogen from various sources using 
allowed CO2-emission levels 

In the CertifHy classification, turquoise hydrogen from methane pyrolysis is not explicitly 
mentioned but instead part of the (blue) low carbon hydrogen from non-renewable energy. Also, 
according to this definition, hydrogen produced at a CO2-emission level of above 91 gCO2/MJH2 is 
dubbed “grey”, which is the current CO2-reference level from conventional steam reforming of 
natural gas, i.e. also defined as “not low-carbon” hydrogen. Also, “blue” and “green” hydrogen 
belong to the same “low-carbon” hydrogen class as they are connected with CO2-emissions equal 
or below today’s grey carbon emissions by -60%, or with a specific CO2-emission factor of below 
36.4 gCO2/MJH2.  

Figure 1-1 is centred around the development of the future European “Green Gas Grid”. This 
means that other energy carriers, including liquid hydrogen have not been considered. Also, as a 
third dimension, hydrogen can have different qualities, i.e. highly pure hydrogen as e.g. required 
by fuel cells for mobility or stationary applications and hydrogen for industrial end use requiring 
less purity. For completeness sake, Figure 1-4 summarises the potentially relevant energy 
infrastructures in a renewable based energy system. In addition, the box with the broken line 
shows the “supporting” gas or liquid CO2 infrastructure to dispose of CO2 in CCS schemes (blue 
hydrogen). Furthermore, the public energy infrastructures relevant for gas transmission and 
distribution are framed by the bold box, and the shaded box represents the existing hydrogen 
pipelines operated by industrial gases companies. The issue of hydrogen quality is further 
discussed in chapter 1.3.3, section “Blended hydrogen users or pure hydrogen users”. 

8 RED II in Article 25 requires hydrogen (or more generally RFNBOs) to have a GHG saving of “at least 70 % 
from 1 January 2021”. However, this does not apply to Guarantees of Origin, which are governed by RED II 
Article 19. Furthermore, the provision in art. 25 does not specify the applicable fossil fuel comparator. CertifHy 
has communicated that it would adjust the criteria for the two categories (renewable or low-carbon hydrogen) 
when the applicable fossil fuel comparator is defined as also this value has to be adjusted in CertifHy in order to 
have an operational definition of the GHG threshold compatible with RED II. Furthermore, CertifHy intends to 
enlarge its current scope from Guarantees of Origin (governed by art. 19) to also include supply certification 
demonstrating compliance with the provisions of RED II Art. 25-30 related to contributions to the renewable 
energy in the transport target for 2030. 

3 

 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Figure 1-4 Large-scale energy infrastructures in an energy system dominated by 
renewable energies (CO2 for CCS) 

In chapter 2.2, four generic development pathways from today through the transition year 20309 
to 2050 are defined. In chapter 2.3, the asset-specific considerations are assessed. They address 
the most relevant hydrogen value chains, from H2-production to H2 infrastructure (transmission, 
distribution, and seasonal storage) and finally H2-end-use in more detail, also considering their 
potential impact on the four defined generic pathways. Concluding the pathway considerations, 
chapter 2.4 highlights the concept of hydrogen imports through existing large-scale gas 
infrastructures and how they compare to alternative energy carriers import options.  

A set of four generic development pathways for integrating hydrogen into the gas infrastructure at 
large scale are depicted in the scheme presented in Figure 1-5, together with the underlying basic 
assumptions. The generic pathways have been developed to characterise strategic differences of 
individual EU Member States or Member State regions and to support the development of a 
regulatory framework for a future European hydrogen gas transmission infrastructure.  

9 2030 has been chosen as transition year as it is in focus of many national hydrogen strategies. 

4 

 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Figure 1-5 Tentative generic hydrogen gas infrastructure pathways and their coherence 

The definition of the four generic pathways tries to frame the possible general developments of a 
Member State’s transmission and distribution gas infrastructure until 2050 as follows: 

  Pathway 1 (PW1) – Full H2-grid integration: This pathway could be typical for Member 

States with a well-developed gas infrastructure today10 and understanding its current and 
future role to support the electricity system in its task to balance fluctuating renewable 
electricity loads as well as sustaining its economic value. PW1 foresees a continued use of 
the existing gas infrastructure or even a further build-out by capacity (gas to replace liquid 
energy carriers) and/or by regional extension (potential relocation of provision-to-demand 
relations) with a gradual but accelerating shift from fossil (or bio-) methane to green 
hydrogen by 2050. This pathway typically coincides with the full exploitation of hydrogen as 
energy vector in all end-use sectors. Therefore, sectoral integration applying hydrogen 
becomes a key target. 

  Pathway 2 (PW2) – H2 grid upscaling: Based on a limitedly developed natural gas 

infrastructure today but a high potential and/or ambition to utilise the available renewable 
electricity resources, some Member States may consider to reinforce their gas grid. This 
decision is typically based on the necessity to adapt the energy system to the renewable 
electricity load balancing needs and the appreciation of making use of the improving 
economics of green (and in the transition phase also blue) hydrogen serving multiple end-
use sectors from one common infrastructure. Poland can serve as an example for PW2. 
According to representatives from the gas industry, Poland plans to reinforce its gas grid 
extending its current transmission focus to gradually replace coal by CO2-lean or CO2-free 
gas serving its growing domestic energy needs. A national Polish Hydrogen Roadmap is 
expected to announce an important future deployment of hydrogen from wind energy or 
natural gas with CCS distributed through the gas infrastructure, the extent of which would 
still have to be developed. 

  Pathway 3 (PW3) – H2-grid downsizing: In some EU Member States, the current gas 

infrastructure is dominated by its use for heating purposes today. PW3 strategies may then 
be characterised by a shift to more electricity-based (electric heat-pumps) or central heat 
supply structures, releasing the gas infrastructure from some its current roles. This could in 
principle cause a devaluation of the existing gas infrastructures. Denmark can serve as an 
example for PW3; it has announced to reduce its current gas use by about 50% until 2050 
and would also for some areas favour centralised district heating-based residential heat 

10 E.g. in some central European Member States parallel transport pipelines are in favour of an early full shift to 
a full hydrogen transport. 

5 

 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

supply11. The role of its gas grids would hence change and need to accommodate hydrogen 
from wind-energy for load-balancing (transport grid) and to collect biomethane 
(distribution grid). In how far the emerging role of hydrogen as green gas will change this 
downsizing of the gas grid cannot be foreseen yet. 

  Pathway 4 (PW4) – Transit-focused H2-grid: Member States with a limitedly developed 
or gas transit-focused gas infrastructure and no need to back up the electricity system in 
its role to balance large shares of renewable electricity will lack the incentive to develop 
new gas grid infrastructures. These Member States could consider to use alternative energy 
transmission/distribution means to transport hydrogen (ship, rail, or road) and/or use other 
CO2-free energy carriers, still being capable of taking profit from the same efficient end-use 
technologies. At the same time, they may want to continue the transit and hence 
transmission task of their existing gas infrastructure.  

In this exercise, we have anticipated that in the future the development of transmission and 
distribution parts of the gas infrastructure will go hand in hand. This may or may not be the case in 
individual Member States. We are aware of strategies where a continuous strong role of the gas 
transmission grid is foreseen, while the outreach of the distribution grid is believed to be reduced 
by distributing heat instead of gas across the last meter12. This level of detail, together with many 
other possible development options and criteria for defining generic hydrogen development 
pathways would, however, have watered down the strategic proposition of our generic pathways-
definition. 

Important aspects in developing these generic pathways were: 

1.  Today: Concerning the starting point from which a Member State will consider the 

strategic development of its energy supply system and the underlying infrastructures, a 
large number of criteria could be applied to describe an energy system and its specific 
framework in view of a more or less further developed gas infrastructure. The unifying 
ambition is to develop green gases taken into account the current energy supply, 
infrastructures, and the end-users supplied through the gas grid. The ambition was to 
consider potential major and original as well as early drivers for the development of 
hydrogen gas. In this respect, two aspects have to be looked at, i.e. the needs to shift to 
hydrogen as molecule-based energy carrier and its most relevant opportunities. We 
understand that the major role of hydrogen in future energy systems will be to 
(a) universally combine the avoidance of end-use related climate and pollutant emissions, 
(b) smoothly but increasingly shape the transition from fossil fuels to renewable energy 
vectors, and (c) deliver economic advantages through a high continuity, including re-
utilisation of today’s industry structures and hence assets. The two most relevant factors, 
characterising the present situation as a starting point, are  
1.  the availability in most EU Member States of a dense gas infrastructure connecting 

energy production and user centres as well as dispersed users via a well-developed and 
interconnected gas transit and transmission grid (opportunity) and 

2.  the need to mitigate the economic and technical impacts on the electricity 

infrastructures from integrating large quantities of short-termed and seasonally 
fluctuating renewable electricity loads (need)13.  

Whereas one of the two aspects (opportunity) addresses an important economic asset, the 
second (need) takes a major EU energy policy target into consideration. In order to keep 
the pathway definition simple, all other criteria seemed to be of subordinate nature in this 
context but will be assessed in more detail in chapter 1.3.  

2.  Today  2030: On the verge of today’s energy infrastructures towards less fossil and 

substantially higher renewable energy shares already in the transition phase (2030), the 
introduction of green or blue hydrogen may also be eased by other factors, leading to a 
smoother transition. Therefore, the green and blue columns in Figure 1-5 indicate the 
opportunities of utilizing the early economic advantages of applying blue hydrogen from 
14. This may be either 
steam methane reforming combined with the sequestration of CO2

11 Energinet.dk: Long-term development needs in the Danish gas system - The green transition calls for new 
use of the gas system. Report by Energinet. Doc. 20/00788-57, September 2020, 
file:///C:/Users/buenger/AppData/Local/Temp/Long-term%20develeopment%20needs%20gassystem.pdf. 
12 The Danish energy strategy by 2050 suggests that the gas distribution grid may lose some of its role to 
distribute energy for heating to individual buildings, but would have ‘new’ tasks such as biomethane collection 
and supply to district heating installations [Energiscenarier frem mod 2020, 2035 og 2050, Energistyrelsen, 
March 2014].  
13 E.g. the use of blue hydrogen pathways does not correspond to a major EU 2050 energy and climate policy 
goal whereas the deployment of renewable electricity or hydrogen does. 
14 Could as well be the use of biomethane or low-carbon methane pyrolysis. 

6 

 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

done by domestic CO2-disposal or by CO2-disposal abroad, using a specific CO2-pipeline or 
ship transport to other countries within or outside the EU15. Another means for rapidly 
introducing hydrogen into a Member State’s energy system is the import of (certified) 
green or blue hydrogen from outside the Member State or outside of Europe16; it is 
expected that, in this timeframe, hydrogen imports will still be limited. 

3.  2030: Already in the transition target year 2030, the interest in the future role of the 
green gas infrastructure will become visible in EU Member States; it can be called 
ambitious (top) or less ambitious (bottom). Therefore, we have dubbed this phase the 
“sensitive” transition point as the general direction of the future gas infrastructure 
utilisation will already be decided by then. As a rough indication, the names of European 
regions have been added to the four hydrogen development pathway “terminal points” in 
blue font. The allocation of names does not have the purpose to foresee which gas 
infrastructure strategies will emerge in these regions towards 2050, but rather to indicate 
the starting point17. 

4.  2030  2050: A major development criterion will then also become the type of hydrogen 

use, i.e. in which sectors and to which extent green or blue hydrogen will be used, either to 
cover end-use needs or to exploit potential synergies by intersectoral integration (“sector 
coupling”). We understand that in the early introduction phase the considerations are 
rather supply- or capability-driven to reach the required scaling for significant and early 
cost-reductions in the supply chain, whereas in the longer-term, with key technologies such 
as fuel cells for mobile or stationary use becoming commercially and widely available, the 
ramp-up of the infrastructure may become more demand-driven. It is worthwhile noting 
that for today’s hydrogen pipeline operators, i.e. the technical gases industry, all 
infrastructure investments are solely demand driven.  

5.  2050: By 2050, we imagine three different states of development in the gas grid, probably 
also reflecting a country’s energy intensity as a whole: (a) heavily utilised to supply all 
energy sectors and in addition providing hydrogen as a base chemical, as well as 
interlinked with other Member States or for hydrogen imports from outside Europe at large 
scale, (c) little developed gas infrastructure, possibly with few island grids but lacking 
interlinkage, and (b) something in between, with gas grids either mostly operated at a 
national level or with some but limited gas exchange with neighbouring countries. 

In principle and due to the highly dynamic strategy development processes in the energy markets, 
EU Member States have demonstrated different engagement in hydrogen energy. This is well 
understood, taking into account the two major driving forces behind hydrogen energy as chosen for 
our pathway selection, i.e. the extent of today’s gas infrastructure and the potential or ambition in 
developing domestic renewable energies. Member States characterised by a PW1 or PW2 pathway 
typically have an obvious interest in safeguarding existing gas assets in the future whereas other 
Member States stronger depend on developments in other countries.  
To test our selection, we have tentatively applied the 4 pathway types to existing hydrogen 
strategies, based on our insights from desk research and stakeholder interviews: 

  Netherlands (NL): With a rather recent strategy to switch from a fossil to a RES based gas 

supply system and the need to combine the transmission/distribution of electrons and 
molecules in favour of an efficient RES based energy system18, the Netherlands are striving to 
integrate hydrogen into their gas infrastructure. Having pinpointed the re-utilisation of existing 
(gas) infrastructures, early hydrogen business cases have been earmarked19. The Dutch 
National Hydrogen strategy has recently been published20. It combines the (gas) infrastructure 

15 Examples are the H2omorrow (Open Grid Europe with Equinor, DE) https://oge.net/en/us/projects/h2morrow 
 and Magnum (Nuon, Gasunie, Equinor, NL) https://group.vattenfall.com/press-and-media/news--press-
releases/newsroom/2017/vattenfall-aims-for-carbon-free-gas-power projects. 
16 Typical examples are the suggested 40+40 GW electrolysis project proposal to import green hydrogen from 
North Africa or form Ukraine https://www.hydrogen4climateaction.eu/2x40gw-initiative 
17 Eastern European States could decide to import large amounts of renewable electricity by means of 
hydrogen-based gas infrastructure yet to be developed. 
18 Whereas the traditional energy supply was based on solid, liquid or gaseous energy carriers (i.e. molecules) 
with ‘built-in’ storage and flexibility capability (coal dumps, oil tanks, underground gas caverns, linepack) it is 
believed that the future energy supply system will be dominated by the supply of renewable electricity (i.e. 
electrons). In order to efficiently and economically combine the best of these two energy worlds, both electrons 
and molecule handling technologies need to be combined. 
19 J. Koornneef: Offshore wind meets hydrogen - Opportunities on short and long term. Presentation at Global 
Energy Village 2018 conference, Barcelona, Spain, 17-19th May 2018. 
20 Only recently, ongoing discussions fostering a strong gas grid connection between the Netherlands and 
Germany have been communicated. The national Dutch hydrogen strategy from 4th June 2020 has phrased: 
“The developments in Germany are highly significant to the Netherlands, given that it is likely that a portion of 

7 

 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

availability, large RES potentials, geographical setting as an energy hub, existence of large 
industrial clusters in need of fulfilling their CO2 obligations and served by dedicated gas 
infrastructures, and the capability to unlock RES and fossil based domestically produced as well 
as imported hydrogen. Finally, a joint political and industrially backing put the Netherlands into 
the position of making economic use of hydrogen early. The Netherlands are therefore seen as 
a representative of PW1 with a balanced share of green and blue hydrogen in the transition 
phase, turning to more green hydrogen in the long-term. Another aspect is the Netherlands’s 
position as energy hub, which will necessitate to develop strong gas infrastructure-based 
interconnections with its neighbours along the North Sea coast as well as in central Europe. 

  Germany (DE): The implementation of hydrogen into the national gas grid as part of the 

emerging national hydrogen strategy is an important element of the German energy strategy, 
as Germany today benefits from a dense natural gas grid supplying a large share of the final 
energy end-use in all sectors21. Also, it fulfils the criterion of both a large potential and 
ambition in developing its RES energy base. Even though the RES potential will not be 
sufficient to cover all of its energy needs given the country’s high energy intensity, the 
combination of both criteria is a sound starting point to integrate hydrogen into all sectors of 
the energy systems. With strong ambitions to combine early business cases with the fulfilment 
of the EU GHG targets, the chances are high to more than just substitute natural gas as the 
molecule-based energy transport and storage vector. Its use is foreseen to be extended to 
other energy uses such as power generation, mobility, industry, and at the distribution level 
also buildings (e.g. fuel cells for co-generation). By that, Germany will have the potential for 
developing along PW1, the future green hydrogen share ambition strongly based on the policy 
development. 

  Poland (PL): Being dominated by fossil and specifically coal based electricity generation 

today, as well as a gas transmission infrastructure developed to transport gas from Russia or 
Ukraine into central Europe, Poland could be seen as a typical representative of PW4. However, 
Poland has understood that with its high RES-E potentials (i.e. onshore and Baltic Sea offshore 
wind) tapped to gradually substitute electricity from coal, the need will increase for load 
balancing in the electricity system. Next to green hydrogen also blue or turquoise hydrogen 
sources will be developed further in the transition phase for economic reasons. How this will 
translate into further gas infrastructure development in detail is open as the national hydrogen 
strategy is still under development. In addition, continued natural gas imports e.g. from 
Ukraine or Russia also via Lithuania or the import and exchange of gas with Denmark through 
the Baltic Pipe after 2022 will provide access to potentially ‘cheap’ low-carbon hydrogen from 
Eastern Europe and the North Sea. Thus, the combination of future RES-E transmission (and 
seasonal storage) business cases and the domestic RES-E potential do support a potential H2-
conversion of today’s transit transmission gas grid and the development of the distribution grid 
much depending on the plans for hydrogen end-use. We therefore suggest to group Poland in 
PW2. However, the timeframe cannot be foreseen today.  

  Spain (ES): Representing South Eastern Europe, Spain intends to strongly develop its 

renewable energy resources, i.e. electricity from solar PV and CSP22 as well as from onshore 
wind. Spain intends to in the future produce hydrogen solely from renewable energy, supplying 
it to all end-users and even for export. Hydrogen from fossil energies is not seen as an option, 
as it is believed to block future investments in fully sustainable future-proof technologies. 
Sectoral integration is seen as a means to open economic synergies for the hydrogen 
businesses. The gas grid, even though tailor-made for today’s energy provision can in principle 
be used to transport hydrogen, blended to methane in the transition phase and converted to 
100% operation in the long-term. The awareness has grown that the gas grid should be seen 
as a valuable asset, worthwhile to be used for green energy transport, extending from islands 
initially and across European and non-European (North Africa) borders. As such Spain could be 
grouped in PW3. 

  United Kingdom (UK): The UK has developed from a natural gas export to a gas import 

country. Large shares of its final energy end-use are contributed by natural gas today. One 
important aspect here is the end-use seasonality dominated by the gas-consumption for 
heating. As a technology change to other heating systems would lead to massive investment 
needs, it is believed that re-utilising the existing process technology for heating (simple boilers) 
and gas infrastructure assets will be the most economic approach. In combination with its 
political and industrial will and its large RES potentials, the UK has developed an outstanding 

German demand will have to be met through imports that enter Europe through the Netherlands.” 
https://www.government.nl/documents/publications/2020/04/06/government-strategy-on-hydrogen 
21 In 2017 the contribution of natural gas of final energy use rose to 23.8% [Energy Consumption 
in Germany in 2017. AGEB, 2018, https://ag-
energiebilanzen.de/index.php?article_id=29&fileName=ageb_jahresbericht2017_20180420_englisch.pdf 
22 Concentrated Solar Power: In 2018, Spain accounted for almost half of the world's CSP capacity at 2,300 
MW, even though no new capacity has entered commercial operation since 2013. 

8 

 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

concept and strategy to utilise the capabilities of hydrogen in the gas grid mainly for heating 
purposes. As stated, its political ambitions coined by the development of fossil energies will 
cause a large share of blue hydrogen to be part of the energy strategy still by 205023. Even 
though being a representative of the PW1 group, the UK will therefore probably tend to a 
higher share of blue hydrogen over time. 

In addition to the four generic pathway types, further aspects will need to be taken into 
consideration to understand the differences between possible hydrogen gas infrastructure 
development routes which are relevant for elements of a European regulatory framework for 
dedicated hydrogen gas transmission and distribution infrastructure. Further to the general 
preparedness or ambition as well as the depth of integrating a hydrogen gas infrastructure as an 
important part of national energy systems, these criteria address details of the modes by which 
hydrogen would be  

1.  produced (fossil versus RES based energy source, share of domestic production versus 

imports, CH4 versus H2 as energy carrier, degree of centralisation),  

2.  transported, distributed, or stored (dedicated H2 grid versus admixture, distribution versus 

transmission grid focus) and  

3.  used in different energy sectors (type and share of end-use sectors to be supplied).  

The structure presented in Figure 1-1 is used as a basis to further explain how the most relevant 
hydrogen key technologies (= assets) along the hydrogen value chains coincide with the generic 
pathway types PW1 to PW4. The correlation of assets with pathways will be further explained by 
examples from individual national hydrogen strategies comprising hydrogen production (also 
competing technologies), infrastructure (dedicated and blended hydrogen transmission and 
distribution and storage), and end-use. Where meaningful, also contradicting government and 
industry strategies have been pointed out. 

The structured criterion list in Table 1-1 has been developed to explain potential hydrogen gas 
infrastructure development pathways of individual Member States in the timeframe until 2030. This 
chapter follows this criteria sequence. At the end of this chapter, the European regions will be 
assessed concerning their general position under consideration of these criteria. 

Table 1-1 Criteria to explain the assets along relevant hydrogen value chains in more 
detail 

General characteristics 

Potentials/ambition in renewable electricity development 

Extent of current gas transmission grid 

Extent of current gas distribution grid 

Hydrogen production 

Aspired green and blue/turquoise (SMR/CCS or methane-pyrolysis/C-use/deposition) hydrogen shares 

Decentral vs central hydrogen production 

Domestic vs imported hydrogen provision 

Hydrogen infrastructure (transmission, distribution and storage) 

Extent of dedicated hydrogen grid versus H2-blending at TSO-level 

Extent of grids with hydrogen blending versus dedicated hydrogen grids at DSO-level 

Existing private hydrogen grids 

New hydrogen infrastructure versus methane infrastructure refurbishment 

Existing seasonal hydrogen storage potential (salt caverns, other structures) 

Opportunity strategy typically through isolated installations vs nationally harmonised gas strategy 
development 

Interest in future transport of biomethane via gas grid  

Hydrogen end-use 

Share of end-uses served by hydrogen (industry, mobility, heat, power production) 

Seasonality of hydrogen demand 

23 By 2050 149 TWh/yr of blue hydrogen and 87 TWh/yr of green hydrogen are foreseen to provide about 28% 
of UK’s total energy demand in the “balanced scenario” [Pathways to Net-Zero: Decarbonising the Gas 
Networks in Great Britain. Study by Navigant for the Energy Networks Association (ENA), 21 October 2019]. In 
a recent study from Aurora Energy Research, it is claimed that up to 2050 about 480 TWhH2/yr could supply 
most of UK’s energy needs, but also this study concludes that it will be blue hydrogen [Hydrogen for a net zero 
GB: an integrative energy market perspective. Study by Aurora Energy Research, 24th June 2020, 
https://www.auroraer.com/insight/hydrogen-for-a-net-zero-gb/ 

9 

 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Dispersed small vs central large users 

Blended hydrogen users or pure hydrogen users 

1.3.1 General characteristics 

The first three general characteristics in this table have already been applied in developing the 
generic pathway graph in Figure 1-5: 

1.  Potentials and/or ambition in renewable electricity development, 
2.  Extent of current gas transmission grid and 
3.  Extent of current gas distribution grid, 

of which 2. and 3. have been combined for the purpose of the pathway graph. All criteria are 
further explained in this subchapter, without being directly linked to PW1 to PW4. Instead, these 
aspects have to be considered in addition when considering the potential strategy formulation in an 
individual Member State. 

Potentials/ambition in renewable electricity development 

We assume that in fulfilling EU’s policy targets by 2030, renewable energies shall become a major 
element of all Member States energy portfolios24. The renewable energy potentials have been 
recently assessed by various studies25. Whereas Figure 1-6 presents the technical production 
potential for renewable electricity, Figure 1-7 shows the renewable electricity production expected 
in the METIS 2050 scenario against the firm electricity consumption26. A comparison shows 
significant differences between the renewable electricity production potential and the expected 
production figures for 2050, demonstrating large electricity potentials in several Member States 
(such as Germany, Spain or France) for hydrogen production at larger scale27. 

Figure 1-6 EU renewable electricity generation potentials, by Member State (average of 
ranges per Member State) 

24 “A binding renewable energy target for the EU for 2030 of at least 32% of final energy consumption, 
including a review clause by 2023 for an upward revision of the EU level target. The original target of at least 
27% was revised upwards in 2018” https://ec.europa.eu/clima/policies/strategies/2030_en 
25 Among others Kanellopoulos, K.; Blanco Reano, H.: The potential role of hydrogen production in a sustainable 
future power system – An analysis with METIS of a decarbonized system powered by renewables in 2050, JRC 
study, 2019; and van Nuffel, L; Gorenstein Dedecca, J.; Yearwood, J.; Smit, T.; Bünger, U.; Altmann, M.; 
Fischer, Ch.; Michalski, J.; Raksha, T.; De Vita, A.; Zerhusen, J.: Impact of the use of the biomethane and 
hydrogen potential on trans-European infrastructure. Study for DG Energy, September 2019. 
26 The electricity base consumption does not contain the additional electricity consumption for the electrolysis of 
hydrogen energy. 
27 E.g., the European Hydrogen Strategy states: “In a third phase, from 2030 onwards and towards 2050, … 
renewable electricity production needs to massively increase as about a quarter of renewable electricity might 
be used for renewable hydrogen production by 2050. 

10 

 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Figure 1-7 Stacked renewable annual production vs firm electricity demand at country 
level in METIS scenario 2050 (n this case including the additional direct electricity 
demand by 2050 but excluding demand from the electrolyser fleet) 

From the gas infrastructure study for DG Energy, the technical renewable electricity production 
data per Member State were extracted and linked with the population data; the resulting RES-E 
potential per million inhabitants is presented in Table 1-228. 

Table 1-2 Population specific variable technical RES-E production potential by Member 
State [TWh/ (yr∙mio inhabitants)] 

Member State 

[TWh/(yr. Mio inh]  Member State 

[TWh/(yr. Mio inh] 

Austria 

Belgium 

Bulgaria 

Croatia 

Cyprus 

Czech Republic 

Denmark 

Estonia 

Finland 

France 

Germany 

Greece 

Hungary 

Ireland 

20.5 

3.3 

16.7 

16.1 

47.9 

13.2 

37.5 

64.9 

41.5 

30.8 

10.8 

51.7 

17.4 

116.2 

Italy 

Latvia 

Lithuania 

Luxemburg 

Malta 

Netherlands 

Poland 

Portugal 

Romania 

Slovakia 

Slovenia 

Spain 

Sweden 

UK 

EU 

14.7 

110.0 

94.5 

2.4 

4.3 

11.4 

23.0 

42.2 

20.3 

11.5 

7.8 

66.0 

68.1 

25.9 

27.7 

black: low spec. potential (< 20 TWh/(yr. mio inh.); red: high spec. potential (20 … 40 TWh/(yr. mio inh.)) and 
red+bold: very high spec. potential (> 60 TWh/(yr. mio inh.)). 

Extent of current gas transmission grid 

The extent of the European transmission gas grid is shown in Figure 1-8. It shows the coverage of 
the EU Member States by a Europe spanning gas transmission infrastructure, specifically illustrating 
the supply (= network) type character in Northwest and Central Europe as well as the transmission 
(= line type) character of the grid in Eastern European Member States. In assessing the 
transmission gas grid density of European regions, this map was taken as a general reference. 
From this map the high density of the transmission gas grid in the “central Member States” 
becomes obvious, spanning from France to the Benelux countries and down to Italy in the South to 
parts of Poland, Austria, and Hungary in the East. In addition, the UK comprises a dense and highly 
used gas grid. In contrast the “peripheral Member States” are characterised by a gas transmission 

28 The population number is only one criterion whether the technical RES-E of a Member State is specifically 
high. Another criterion is the specific energy end-use intensity. For simplicity, this level of detail is sufficient for 
the purpose of this study. 

11 

 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

grid of much less density. As pointed out in another study for DG Energy29, the highest gas end-
use intensity is observed in the following five European states: Germany (with a 24.5 % share in 
total EU gas demand in 2015), the UK (23.0 %), Italy (20.8 %), France (13.1 %), and the 
Netherlands (10.9 %). Due to their energy intensity, some of these countries may need to import 
green (or blue) hydrogen from within or outside the EU.  

Figure 1-8 EC PCI’s European Gas Network map (2019)30 

Extent of current gas distribution grid 

There are no exact figures for the extent of the gas distribution grid across the EU. In its latest gas 
statistical report, Eurogas reports for 2013 a total pipeline length in all EU Member States, 
transmission and distribution, of 2,171,002 km but only as a rough estimate (see Table 1-3)31. In 
Germany, the transmission grid is 38,500 km, while the distribution grid comprises a pipeline 
length of more than 512,000 km, which is about 13 times higher than transmission32. In Italy, 
200,000 km of distribution grid compare with 33,000 km of transmission grid length33. We simply 
assume that this rough relation also holds for most other Member States, and that the total 
pipeline length provides a good first order estimate for the distribution grid length, except for the 
gas transition countries in Eastern Europe.  

29 The role of trans-European gas infrastructure in the light of the 2050 decarbonization targets. Revised Report 
Tasks1 &2. Specific Tender under Framework Contract MOVE/ENER/SRD/2016-498 Lot 2, Trinomics, LBST, 
Artelys, E3 Modelling, Rotterdam, 19 June2018, 
https://ec.europa.eu/energy/sites/ener/files/documents/revised_tasks_1_2_gas_infrastructure_2050_final_clea
n_2_oct_add.pdf 
30 See https://ec.europa.eu/energy/infrastructure/transparency_platform/map-viewer/main.html, PCI – 
Projects of Common Interest. f 
31 Marcogaz presents different numbers for 2013: 217,685 km transmission grid  and 1,640,667 km distribution 
grid, adding up to a total of 1,858,352 km, which is 14.4% off the Eurogas figure for the same year 
https://www.marcogaz.org/app/download/7719248963/Technical_statistics_01-01-2013_revision_on_15-09-
2014_-_WEB_VERSION.pdf?t=1529588711. This reasonably close for the purpose of this study. 
32 Monitoring Report 2019, Bundesnetzagentur (see 
https://www.bundesnetzagentur.de/SharedDocs/Mediathek/Berichte/2019/Monitoringbericht_Energie2019.pdf;j
sessionid=D6D67CFF03E945F87E0CECAAC898CA2A?__blob=publicationFile&v=6, p. 347). 
33 This information was provided in an interview. 

12 

 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Table 1-3 Assets along relevant hydrogen value chains for EU Member States 

From Figure 1-9 it can be concluded that the countries with the most extensive gas distribution 
grids in Europe are Germany, the UK, Italy, France, Poland and the Netherlands based on total 
numbers, and Hungary, the Netherlands, the Czech Republic, Slovakia, Belgium, Germany, Croatia, 
Luxemburg, Austria, Poland, Italy and the UK (dashed box), on a population specific basis34. 
Summing up, both the renewable electricity production potential and the total gas pipeline length 
across all EU Member States and the UK are shown in Figure 1-9. As expected, the comparison 
demonstrates little correlation between gas pipeline infrastructure and renewable electricity 
potential. 

Figure 1-9 Population specific variable technical renewable electricity production 
potential and transmission grid length for all EU Member States + UK (sorted for pipeline 
length) 

34 Population density is not the only specific energy indicator for the gas grid density. Others are energy 
intensity to reflect energy intensive industries as well as climate conditions to reflect the heating needs. These 
factors have been skipped here for reason of simplicity. 

13 

 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

1.3.2 Hydrogen provision 

Three hydrogen production specific criteria have been assessed in more detail: 

  Aspired green versus blue (SMR/CCS or methane-pyrolysis/C-use/deposition) hydrogen 

shares, 

  Decentral vs central hydrogen-production and 

  Domestic vs imported hydrogen provision. 

Aspired green versus blue (SMR/CCS or methane-pyrolysis/C-use/deposition) 
hydrogen shares 

The most prominent and published green gas strategies demonstrate an obvious colour-ranking of 
the hydrogen production pathways of choice: 

1.  Green hydrogen: Two motivations for an early introduction of green hydrogen have been 

identified from the hydrogen strategies or the interviews: 

a.  Member States with a high renewable electricity production potential (or with 
obvious green hydrogen import opportunities) and the perspective of low 
production costs. Obviously, these are Southern European countries taking profit 
from high solar irradiation. 

b.  Member States with a visible technology development strategy for innovative 

technologies along the green hydrogen value chain. E.g. Germany has explicitly 
stated a combined sustainability and value creation focus of its national hydrogen 
strategy. 

2.  Blue hydrogen: A strong motivation for an early blue hydrogen provision can have two 

motivations: 

a.  Natural gas producers (outside the EU): The UK collaborates with Norway on the 

exploitation of combined autothermal reforming (ATR) and CCS technologies to 
provide cheap hydrogen at costs of 1.85 £/kgH2 down from 2.1 £/kgH2 today35, 
based on the availability of large natural gas resources. But, also EU Member 
States with a cost-efficient access to NG and the plan to export CO2 for storage 
(e.g. in Norway) such as Germany are currently discussing the inclusion of blue 
hydrogen in their gas strategies36.  

b.  Access to CO2 storage sites: With a focus on the transition period (2030), the 
availability of cheap and abundant NG as well as high CO2 taxes in Norway 
coincides with available storage sites under the North Sea. 

3.  Turquoise hydrogen: Specific interest for turquoise hydrogen has been prominently 

raised by the Russian gas industry to provide CO2-reduced (medium-term) and CO2-free 
(long-term) hydrogen. This has also recently provoked industrial interest by the European 
gas industry, specifically in Austria37 as it is believed to be simpler to dispose of solid 
carbon than CO2. It also appears in the German and European hydrogen strategies. The 
potential success for this type of hydrogen depends on the development success of the 
technical options, also timewise and how the target can be reached to provide the by-
product carbon in qualities relevant for competitive C-sales prices. Turquoise hydrogen will 
compete with the rather robust SMR process which has the advantage of a lower technical 
complexity and no by-product to be sold into the market at unknown economic 
consequences38. Given the early state of R&D and technical development, it is not clear 
yet, how large the contribution of turquoise hydrogen will be by 2030. 

Depending on the share of green hydrogen to be produced in the medium to long-term, 
electrolysers for PtX-schemes are posed to becoming one of the key technologies in RES-E-
dominated energy systems. Their contribution would be severalfold as they would not only provide 
hydrogen as an energy carrier, fuel, and base chemical for industry, but as well provide system 
services, in particular to balance the electricity system with increasing RES-E shares. Its success 
will therefore depend on hydrogen strategies building on one or several of four success factors: 

35 It is interesting to note that the authors of [Hydrogen for a net zero GB: an integrative energy market 
perspective. Study by Aurora Energy Research, 24th June 2020, [https://www.auroraer.com/insight/hydrogen-
for-a-net-zero-gb/] at the same time claim lower costs for electrolytic hydrogen of 1.6 £/kgH2 by 2050 down 
from 2.6 £/kgH2 today. 
36 Other EU Member States such as the Netherlands have their own CO2 sinks. 
37 [St. Petters: Rebalancing our Planet's Carbon & Water Cycle at no extra Cost. Carbotopia, December 2018]. 
38 Today’s carbon markets are much smaller in scale than if carbon is produced at energy market specific scale 
and would have a soon to be expected economic impact on the whole carbon market with unpredictable 
outcome. 

14 

 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

  An ambitious RES-E development goal supported by a relevant policy framework (mainly 

supply driven) much beyond the early discussions of surplus electrical energy39, such as in 
Southern Europe, where green hydrogen may not only be used for own end-use but also 
for export, 
The need of providing seasonally fluctuating energy, such as for heating purposes in 
various Northern European countries40, 
The role of hydrogen to decarbonise end-users, providing hydrogen to more than one of 
the energy users such as industry, buildings, mobility, and the power sector, mentioned by 
all emerging hydrogen strategies in central Europe41, and 
The comprehension of potential value creation in an innovative new technology segment, 
typically exploitable by all technology innovation focused Member States.  

 

 

 

Conditions for these success factors may therefore be met across all of Europe with shifting focus 
for each Member State, specifically as studies have indicated electrolyser cost reduction potentials 
which will eventually render green hydrogen cheaper than blue or turquoise hydrogen, depending 
on the region, i.e. from Southern (solar) or Northern (wind) regions42.  

With still abundant and cheap natural gas available in parts of Europe, also CCS- or C-deposition 
schemes can in combination with steam reforming or pyrolysis of natural gas support load-levelling 
in the transition period until 2050. Even though the positive contribution of electrolysers to single 
European electricity markets has been found to be beneficial, further studies will need to assess the 
parameter driven economic viability of the extensive use of RES-E for hydrogen production for 
individual Member States43. 

Concerning the costs of hydrogen production by different technologies, recent analysis for the time 
horizon 2030 and a set of realistic assumptions (see Figure 1-10) have shown that by today 
hydrogen costs from fossil natural gas with or without CCS are still lowest (2.5 / 3.0 €/kgH2), 
followed by hydrogen produced from electricity directly connected to renewable energy plants 
(3.5 €/kgH2)44 and from grid electricity (5.5 €/kgH2), by NG from pyrolysis (3.5…8 €/kgH2, with the 
large bandwidth in this case caused by large development uncertainties and based on cost 
estimates from literature w/o practical experience) and finally onsite NG-SMR plants (8.5 €/kgH2). 

39 The idea of producing hydrogen mainly from surplus electricity emerged from the need to produce green 
hydrogen at least costs and as driven mostly by operating, i.e. electricity, costs. As surplus electricity would 
however only be available during a limited number of hours, this would drive up the annuity related costs due 
to the low load factor of the electrolyser.  
40 This factor would also drive the provision of other non-green hydrogen technologies in the short-term. 
41 ditto 
42 
 E.g. [Path to hydrogen competitiveness: A cost perspective. Study by McKinsey for the Hydrogen Council, 20 
January 2020, download at: www.hydrogencouncil.com]. 
43 Bossmann, T.; Fournié, L.; Peña Verrier, G.: METIS Studies – Study S14- Wholesale market prices, revenues, 
and risks for producers with high shares of variable RES in the power system. Study by Artelys, December 
2018; Trinomics, Artelys and Enerdata: Energy Storage Study - Contribution to the security of electricity supply 
in Europe, 2020; and M. Roach, L. Meeus: The welfare and price effects of sector coupling with power-to-gas, 
2020. 
44 i.e. to avoid grid related fees 

15 

 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Figure 1-10 Production costs for hydrogen from NG-SMR, NG-Pyrolysis and water 
electrolysis45 

These results have to be interpreted with a great level of care. The data may change by climate 
region across Europe (costs of RES-E), by the fulfilment of technology development goals by 2030 
(pyrolysis and PEM electrolysis), by the CO2-price assumed46, as well as by other uncertainties of 
electricity prices for renewable electricity and the regulatory framework, which may change in 
general with potential regional spreads. In addition, the cost of hydrogen from NG-pyrolysis also 
depends on the by-product carbon price, which is currently serving rather small C-markets and 
may be significantly disturbed by large amounts of C entering these markets. Furthermore, there is 
a range of currently suggested pyrolysis processes, producing different types of C-structures 
(production costs!) and at different operating conditions (energy use, …). As a working hypothesis, 
the cost for hydrogen from electrolysis will further decline (technology development, renewable 
electricity costs, favourable framework) and the cost for hydrogen from natural gas will tend to rise 
by 2050 becoming a strong argument for the more sustainable technology earmarked for the 
future. Yet, a smooth transition from natural gas today to hydrogen gas in the future can be 
adjusted by the growing share of hydrogen versus methane gas over time. 

Decentral vs central hydrogen-production 

There is evidence from both national and industry-specific hydrogen strategies, that driving the 
green hydrogen production cost down will require to significantly scale up production technologies, 
less from a per-plant scale, but more from a production capacity perspective: 

  Scaling by plant size: The electrolyser developers’ and industry’s claim by tradition was 

that electrolysers are an intrinsically decentral energy technology with little energy 
efficiency differences related to the scale. In other words, from an energy resource 
utilisation perspective there is no reason to necessarily scale up a hydrogen production 
plant as it is the case with thermal power plants which typically take profit from an 
efficiency increase the volume-effect, combined with the advantage of low hydrogen 
transmission costs for decentral electrolysis plants47. 

  Scaling by electrolyser production level: Most Power-to-Gas (PtG) projects have been 
put into operation at small scale, i.e. until today in the 1…20 MW range, caused by the fact 

45 Taken from studies for industry by LBST (2020) and based on assumptions for central Europe. 
46 Here, a price of 180 €/kgCO2 has been applied as suggested by the German Environmental Agency UBA (see: 
https://www.umweltbundesamt.de/sites/default/files/medien/376/publikationen/factsheet_co2-
bepreisung_in_deutschland_2019_08_29.pdf). 
47 
 Instead of gas, electricity then needs to transported across long distances, rendering the degree of (de-) 
centralisation one of techno-economic optimisation. 

16 

 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

that at this plant scale investment risks are still low for the aspired technical/operational 
learning. According to the European Hydrogen Roadmap, scaling by production level from 
today’s European capacity of 1 GW to 40 GW by 2030 is expected to bring down specific 
electrolyser investment costs from 900 €/kW today to 450 €/kW or less in the period after 
2030, and 180 €/kW after 2040. With rising CO2 prices and increasing availability of 
renewable electricity at low prices in several EU Member States, green hydrogen would cut 
the cost curve of natural gas with CCS based hydrogen by around 2030. 

However, taken into account the ambitions of the industry and the authorities, it is expected that, 
next to the prototype scale projects, larger electrolysis plants will already be developed in the next 
decade. A clear signal of this development is also the interest in the development of hydrogen for 
  Mobility: the focus on hydrogen as a fuel for passenger cars has been scaled down in 

Europe in favour of applications for heavy-duty transport, with the effect of upscaled and 
better utilised refuelling stations (trucks, buses, trains, or even ships), 

  Stationary applications: the focus on small decentral PtG plants for load balancing to 

take profit from cheap and otherwise curtailed renewable energy has shifted towards larger 
hydrogen industry applications. This has raised industry expectations that central hydrogen 
production schemes and continuous and large quantity hydrogen supply with e.g. dedicated 
hydrogen pipelines will become economically viable soon specifically for hydrogen for 
applications in industry, assuming that favourable policy framework conditions are provided 
for by politics48. 

From the stakeholder consultation process for this study we have learnt that by 2030 both 
approaches may coincide: 

 

 

The installation of decentral plants in regions with a dispersed gas grid to kick-start 
hydrogen markets in islands, i.e. by the distribution grid, serving one or more end-uses, 
which is typically the case in peripheral Europe49 and 
The development of large-scale dedicated hydrogen pipelines, mainly for large industrial 
consumers, specifically when the option of parallel grids allows to continue the transport of 
methane and the refurbishment of the grid taking place at low costs50 rapidly allowing to 
extend the hydrogen gas grid, typically to happen in dense gas grid regions, i.e. in central 
Europe (Northwest).  

To improve the interoperability of European energy infrastructures, the specifications of gas 
infrastructures of central and peripheral Europe will need to converge, as load balancing renewable 
energies across Member State borders and green hydrogen imports across European borders will 
require accommodating a growing supranational hydrogen trade. The backbone for a Europe-
spanning hydrogen transmission pipeline infrastructure has in July 2020 been presented by 11 
large European TSOs from Belgium, the Czech Republic, Denmark, France, Germany, Italy, Spain, 
and Sweden51. For 2040 a dedicated hydrogen pipeline system of about 23,000 km52 has been 
devised to connect Eastern with Western and Southern with Northern Europe. 

Domestic vs imported hydrogen provision 

The interest in domestic or imported hydrogen goes hand in hand with the choice of green or 
blue/turquoise hydrogen. In principle, the following ambitions have been identified: 

  Domestic hydrogen: Typically, Member States with ample renewable electricity potentials 
(e.g. Spain, Portugal, Italy) foresee to exploit their domestic resources to both supply their 
own energy demand (e.g. Italy) and furthermore to supply renewable hydrogen to other 
Member States (e.g. Spain). But also Member States with limited renewable energy 
potentials but a high ambition to exploit these potentials for own purposes (e.g. Austria, 

48 Industry has understood this urgent upscaling need and approached politics to develop an adapted regulatory 
and financially viable framework allowing the operation of large-scale hydrogen supply chains, e.g. expressed 
by the recent consultation document of the German Gas Transport Association (FNB), collecting as many as 31 
industry proposals for reasonably sized PtG plants to be installed by 2030 the latest. The German National 
Hydrogen has now addressed the issue of electricity price support 
http://www.bmz.de/en/press/aktuelleMeldungen/2020/juni/200610_pm_031_Federal-Government-adopts-
National-Hydrogen-Strategy-and-establishes-National-Hydrogen-Council/index.html 
49 In these Member States, hydrogen transport pipelines will only be built after 2030 when the hydrogen 
demand will grow significantly. 
50 For their comprehensive consultation document, the German FNB has earmarked 1,284 km of transport 
pipelines to be converted to 100% hydrogen operation, the majority of which shall be refurbished methane 
pipelines at investment costs of no more than 10% as compared to new-built dedicated hydrogen pipelines.  
51 European Hydrogen Backbone – How a dedicated hydrogen infrastructure can be created. Study report by 
Enagás, Energinet, Fluxys Belgium, Gasunie, GRTgaz, NET4GAS, OGE, ONTRAS, Snam, Swedegas and Teréga, 
July 2020, https://gasforclimate2050.eu/sdm_downloads/european-hydrogen-backbone/. 
52 6,800 km by 2030. 

17 

 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

 

Germany and the Netherlands) have flagged their interest in domestic hydrogen 
production, typically but not limited close to the renewable energy sites53. 
Imported hydrogen: We have not identified a current or emerging hydrogen strategy 
which solely focuses on import of (green) hydrogen. Yet, for Member States with limited 
own renewable energy resources, most hydrogen would have to be imported unless 
produced from fossil-based energy (natural gas) with CCS or methane pyrolysis. In this 
respect, Member States such as Belgium, Luxemburg or Slovenia are typical future 
hydrogen import candidates. They are counterbalanced by Member States which explicitly 
view themselves as potential green hydrogen exporters such as Spain and Portugal. 
  Combination of domestic and imported hydrogen: As far as national hydrogen 
strategies are emerging, most of them understand the future potential of domestic 
production in view of economic value creation, if competitive. For economic reasons and 
the lack of sufficient own renewable electricity potentials, hydrogen imports are understood 
as a realistic option towards a CO2-free energy system. Depending on production costs, 
these imports can be from within Europe (e.g. Spain) or from outside of Europe (e.g. North 
Africa and Ukraine54). 

Also, the ambition in hydrogen import varies across the European regions: 

  Energy intensive Member States: hydrogen supply costs are the most important 

decision point, independent from the hydrogen source (from within EU, neighbouring 
countries by gas infrastructure or from international sources such as Saudi Arabia or 
Southern Africa55). 

  Member States with an obvious interest in domestic value creation: options for the 

provision of hydrogen from within the EU or neighbouring regions will develop from 
Member States offering their own domestic renewable energy sources for export (e.g. 
Spain or Portugal) or from providing hydrogen transmission services (e.g. Spain or Italy), 
favourably using their gas infrastructures.  

To demonstrate the differences in hydrogen costs per World region, IEA has reported hydrogen 
production costs from hybrid solar PV and onshore wind as shown in Figure 1-11. As can be seen, 
the only European Member States which may produce hydrogen at large scale at costs of as low as 
1.6 US$/kgH2 or below, are Spain, Portugal, and Southern Italy. This compares to much higher 
hydrogen production costs of 3-4 US$/kgH2 in most other parts of the EU. This gives rise to a 
general idea of the principal future hydrogen flows, i.e. from South (ES, PT, North Africa) to central 
EU (including East and West), partially also from North (North Sea neighbour countries, NO) to 
Central Europe as well as from East (Russia, Ukraine) through eastern to central Europe. Adding 
transport costs via pipeline (as gas) versus ship (as cryogenic liquid) is treated in a separate 
chapter. Here, it should only be added that for shorter transport distances (e.g. from within the EU 
or from neighbouring countries) hydrogen imports as a gas by pipeline would be cheaper by up to a 
factor of 10 than by cryogenic liquid via ship. 

53 For the case of northern Germany, the five northern German (= coastal) states have claimed in a separate 
regional hydrogen strategy to offer their on- and offshore wind production and its further distribution to other 
parts of Germany in the form of hydrogen, the electricity transport grid soon reaching its acceptable capacity 
ceiling. If the target of the federal German 5 GWH2 production capacity will be reached by 2030 the total 
German green hydrogen claimed by the national German hydrogen strategy will be provided from the north. 
The gas grid will need to provide the required transport capacity by then. [Norddeutsche Wasserstoff Strategie. 
Wirtschafts- und Verkehrsministerien der norddeutschen Küstenländer Bremen, Hamburg, Mecklenburg-
Vorpommern, Niedersachsen und Schleswig-Holstein, 7th November 2019]. 
54 E.g. [https://www.hydrogen4climateaction.eu/2x40gw-initiative].  
55 E.g. African Hydrogen Partnership project, https://www.afr-h2-p.com/; or K. Westphal, S. Doge, O. Geden:  
The International Dimensions of Germany’s Hydrogen Policy. Comment 2020/C 32 by Stiftung Wissenschaft und 
Politik (SWP), June 2020, https://www.swp-berlin.org/10.18449/2020C32/.  

18 

 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Figure 1-11 Hydrogen production costs from solar hybrid PV and onshore wind systems 
in the long-term56  

1.3.3 Hydrogen infrastructure 

Concerning hydrogen infrastructure, the following seven criteria are assessed further: 

  Extent of dedicated hydrogen grid at TSO-level 

  Extent of grids with hydrogen-blending at DSO-level 

  Existing private hydrogen grids 

  New hydrogen infrastructure versus methane infrastructure refurbishment 

  Existing seasonal hydrogen storage potential (salt caverns, other structures) 

  Decentral, opportunity strategy vs national, harmonised gas strategy development 

 

Interest in future use of biomethane in gas grid 

Extent of dedicated hydrogen grid at TSO-level 

This topic has partially already been addressed in chapter 1.3.1. When it comes to the issue of 
transporting hydrogen via the transmission grid, two basically different strategies have been 
observed. They depend on the intrinsic differences of Member State transmission grid structures 
and type of gas in the high-pressure transmission grid: 

  Dedicated TSO H2-grid: For Germany the FNB-report authored by the TSOs 57 (see Figure 

1-12) argues that that the admixture option in the transmission grid will be limited, as (a) 
sufficient parallel gas grid capacity would be available to operate methane and hydrogen 
grids in parallel in the transition phase and (b) the detrimental effects (materials, process 
equipment, end-user compatibility, …) of an admixture should be avoided. A 100% H2 
conversion is therefore the preferred option.  

  H2-blending at TSO-level: For Spain with (a) a gas transmission grid of less density and 
(b) the use of a high share of biomethane injected into the transmission grid today and in 
the future, blending of hydrogen with methane in the transmission grid has been 
mentioned as an option. For other peripheral Member States such as Italy the situation is 
believed to be similar. 

Whereas with a growing share of hydrogen in the methane grid, also the second type of Member 
States will start to build or to convert to dedicated hydrogen pipelines, but later. Member States 
will need to develop plans striking the right balance between keeping methane-rich transmission 
grid sections for the uptake of biomethane as well as developing an interconnected dedicated 
hydrogen grid. For this reason, it has been communicated in different stakeholder consultations for 
this study, that the gas industry in individual Member States foresees a period of focused national 
gas grid development, driven by individual gas regulatory regimes. Even though, the need for early 
harmonisation of specifications to ensure the interoperability of the European gas grid has been 
flagged in our stakeholder interviews in the interest to avoid later trade barriers for an EU spanning 
fully integrated hydrogen gas markets towards 2050. 

56The Future of Hydrogen - Seizing today’s opportunities. Technology report — June 2019, 
https://www.iea.org/reports/the-future-of-hydrogen#key-findings.  
57 See [Gas Development Plan 2020-2030, draft. FNB, 4th May 2020, https://www.fnb-
gas.de/media/fnb_gas_2020_nep_entwurf_en.pdf]. 

19 

 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Figure 1-12 Suggestion for a future German gas grid infrastructure with close to zero 
hydrogen admixture at TSO level58 

Extent of grids with hydrogen-blending at DSO-level 

The opportunities and challenges of admixture/blending of hydrogen to the methane distribution 
grid at medium and low pressures have also been described in a recent study commissioned by DG 
Energy59. Yet, in contrast to the challenges as reported for the transmission grid these appear to be 
less fundamental and can be overcome specifically for the transition period by the following 
approaches: 

 

Incompatibility with end-users: (a) (stepwise) adapt end-use appliances and 
instrumentation or (b) limit admixture to grid sections with no or only few challenges and 
(c) apply de-mixing equipment for H2-critical end-users in a grid section. 

  Missing regulatory framework: develop adapted national framework 
  Continuously constant admixture rate: regionally connect distribution grids to 

transmission grids which transport pure hydrogen as well as methane in parallel with 
sufficient (seasonal) storage capacity, allowing to level out any locally or seasonally 
fluctuating distribution grid gas blends and gas demand. 

Until now, practical experience with the blending of hydrogen to natural gas has been gathered in 
different Member States60. Admixture rates of 5, 10, 20 or even 30 vol%H2 have been mentioned. 
With 30 vol% of hydrogen admixture being the equivalent to a 10% CO2-emission reduction, the 
achievement towards the fulfilment of EU’s climate goals is however limited. This may be one of 
the reasons why beyond a 30 vol% H2-admixture a full hydrogen conversion seems the preferred 
solution. However, other than the 100% conversion strategy for the UK61, no single national 
strategy for a H2-blending pathway has yet been developed as the local conditions vary from 
distribution to distribution grid. 

Existing private hydrogen grids 

A limited number of hydrogen pipeline grids for industrial purposes have been developed over time, 
in areas with large chemical industry clusters. These investments are solely market-driven by 
hydrogen end-use and hydrogen production economics. Today, these grids, limited in size and 

58 See [GEODE Webinar, Towards the new age of gas networks. Presentation by J. Bergmann, Open Grid 
Europe, 5th May 2020].  
59 Van Nuffel, L; Gorenstein Dedecca, J.; Yearwood, J.; Smit, T.; Bünger, U.; Altmann, M.; Fischer, Ch.; 
Michalski, J.; Raksha, T.; De Vita, A.; Zerhusen, J.: Impact of the use of the biomethane and hydrogen 
potential on trans-European infrastructure. Study for DG Energy, September 2019. 
60 See [Nitschke-Kowsky, P.; Weßing, W.; Dörr, H.; Kröger, K.: Praxiserfahrungen mit der 
Wasserstoffeinspeisung in das Gasnetz, energie / wasser-praxis, 10/2015]; and [Snam: hydrogen blend 
doubled to 10% in Contursi trial: 8th January 2020, 
https://www.snam.it/en/Media/news_events/2020/Snam_hydrogen_blend_doubled_in_Contursi_trial.html]; or 
[Alter, L.: UK Pilot Project Mixes 'Green' Hydrogen With Natural Gas, 17th June, 2020, 
https://www.treehugger.com/uk-pilot-project-mixes-green-hydrogen-natural-gas-4856218].  
61 See H21 Leeds City Gate: https://www.h21.green.  

20 

 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

capacity compared to the natural gas grids62, are operated by industrial gases companies, with no 
Third Party Access and are transporting hydrogen qualities governed by industry specific safety 
rules and hydrogen purities63. The hydrogen price is set by the relevant pipeline operator 
(monopoly, no unbundling), infrastructure hardware depreciation is coined by industrial rules, i.e. 
at different time-scales than for natural gas grids today.  

The most extensive industrial hydrogen grids crossing public land in the EU are situated along the 
North Sea Coast, connecting conventional fossil-based hydrogen producers64 and industrial 
hydrogen users in France, Belgium, and the Netherlands (843 km, operated by Air Liquide), close 
to Rozenburg (the Netherlands, 50 km, operated by Air Products), in North Rhine-Westphalia 
(Germany, 24 km, operated by Air Liquide) and in the Bitterfeld-Leuna chemical industry triangle 
(Germany, 139 km, operated by Linde). In addition, some further but minor dedicated pipeline 
sections, such as one connecting the DOW with the Yara industrial sites (the Netherlands, 21 km, 
operated by a Gasunie subsidiary) and one connecting the chemical industry cluster in Brunsbüttel 
with a refinery in Heide (Germany, 38 km, operated by Linde) are in operation. Finally, several 
pipelines or systems are operated on private industry grounds. In total, the existing European 
industrial hydrogen pipeline grids comprise a length of ca. 1,500 km. Concerning the transported 
energy, the industrial hydrogen grids’ capacity is dwarfed by the quantity of natural gas 
transported through Europe today. With industrial pipeline diameters of 100-300 mm and gas 
transmission pipelines of 600-1,000 mm, the hydrogen transport capacities of the private industry 
pipelines are a factor of at least 10 lower and limited in regional outreach. 

In principle, the industrial gas industry would be open for an extension of its existing private grids, 
mainly focusing on the end-use development in different sectors. This could be the supply of 
hydrogen to further industry sites with emerging hydrogen energy or feedstock needs or to supply 
hydrogen to refuelling stations for mobility. Yet, due to the different hydrogen purity levels, in the 
latter case, hydrogen purification technology would have to be planned onsite the refuelling 
stations. 

Today, it is not clear whether and how the existing hydrogen pipeline grids could be connected to 
the to-be-developed dedicated hydrogen grids that would provide open access to multiple grid 
users. Major issues for discussion are of technical (hydrogen purity, delivery pressure, capacities, 
…) and regulatory nature (third party access/monopoly, regulation/unbundling, …). 

New hydrogen infrastructure versus methane infrastructure refurbishment 

The comparison of refurbished and new-built hydrogen pipeline systems to stepwise grow the 
amount of hydrogen in the gas grid, has been developed by gas industry on the basis of existing 
know-how: 
 

In the early phase of the gas grid, synthesis gas from coking processes has been applied 
with a high hydrogen content of 50 to 60 vol%.  

  Also, the idea of introducing hydrogen as green gas to substitute methane in the gas grids 
is more than 30 years old. Since the late 80s several studies and measurement campaigns 
have assessed materials and processes for operation in both methane and hydrogen 
environments.  

  With the idea of admixing hydrogen in increasing percentages new studies have been 

 

launched65.  
Finally, and as presented in chapter 1.3.3 private industry-based grids have been in multi-
year operation within large industrial centres across the world. 

62 Typical hydrogen industry pipeline sizes are 100-300 mm in diameter and medium pressure of 2-3 MPa, carry 
hydrogen at different purity levels which may even contain synthesis gas components such as CO, comparing 
with natural gas transport pipelines of 600-1,000 mm diameter and pressures of 8-10 MPa with much higher 
transport capacities by at least a factor of 10. 
63 Industry type hydrogen is considered as too impure for use in mobility and stationary hydrogen applications 
involving fuel cells. Industry type hydrogen is much cheaper than hydrogen that is suitable for fuel cells. 
64 Typically, from steam methane reforming but also hydrogen as by-product from industrial processes such as 
chlorine-alkaline electrolysis. 
65 See e.g. M. Henel, H. Bauer, M. Simm, E. Wanzenberg, O. Huising: Energiewende mit Wasserstoffrohren 
„H2Ready“ und Umstellung existierender Erdgasnetze. gwf-Gas + Energie, 03/2020, pp. 32-45] or [Appraisal of 
Domestic Hydrogen Appliances. Report by Frazer-Nash Consultancy, prepared for the Department of Business, 
Energy & Industrial Strategy, February 2018, 
https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/699685/Hy
drogen_Appliances-For_Publication-14-02-2018-PDF.pdf]; or [Heating with hydrogen: World’s first domestic 
hydrogen-powered boiler – pilot project in the Netherlands, https://fuelcellsworks.com/news/heating-with-
hydrogen-worlds-first-hydrogen-powered-domestic-boiler-pilot-project-in-the-netherlands/, 15th January 2020]. 

21 

 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

According to a German stakeholder, the recently presented NEP 2020 consultation report by the 
German Association of Gas Transmission Operators FNB66 has carried out a detailed calculation for 
the 1,294 km of pipeline to be operated on 100% hydrogen by 2030. For this purpose, the 
association members have been asked to provide data on the announced hydrogen project plans (a 
total of 31 PtG-plants) and the required hydrogen gas infrastructure has been modelled based on 
concrete existing or to-be-built hydrogen pipeline for transmission stretches. The result was a 
suggestion of 1,142 km of refurbished pipelines and 94 km of new hydrogen pipelines67. For these 
specific pipelines, the total refurbishment costs were estimated at 310 M€ and the new-built 
pipeline costs at 220 M€, resulting in specific refurbishment costs of 271 €/m of pipe and new-built 
costs of 2,340 €/m, i.e. a factor of almost 9 higher than the refurbishment costs. As a result, we 
can assume that refurbishing exiting methane infrastructure may offer a huge economic benefit 
compared to building new hydrogen pipelines. This result amplifies the understanding that the 
existing gas grid is a high value asset the use of which can be prolonged also in a hydrogen gas 
infrastructure. 

The European Hydrogen Backbone (EHB) report provides slightly different figures. Of the 22,900 
km total hydrogen pipeline grid envisioned for Europe, 18,000 km (75%) are assumed to be 
retrofitted NG pipelines, comprising about 50% of the total costs. The cost per km of refurbished 
hydrogen pipelines would hence amount to 33% of the cost of new-built hydrogen pipelines. As no 
further cost details are provided, we anticipate that part of this difference is based on the costs for 
compression which may have been accounted for in different ways in both calculations. As the 
current analysis has to be seen as preliminary with no experience from the field, a 9-33% 
bandwidth is taken as a reasonable initial cost differential range. 

Existing seasonal hydrogen storage potential (salt caverns, other structures) 

Seasonal underground storage of natural gas today uses large to very large porous or hollow below 
ground structures, which are limited to geologically relevant sites: 

 
 
 
 

aquifers, 
depleted gas fields, 
salt caverns and 
rock caverns. 

So far, safe hydrogen storage has only been confirmed and also mapped across the EU for salt 
caverns (see Figure 1-13), depleted gas fields and aquifers have been in the focus of recent studies 
and pilot test activities68. Currently, the FCH-JU has called for a research and mapping activity for 
Europe to better understand the potential of other than salt cavern hydrogen storage across all of 
Europe69. Even though not covering all of EU27, a view at the map shows that underground storage 
in salt caverns is limited to rather few locations and Member States. The largest potential is under 
the southern North Sea and its bordering countries. Therefore, if Europe’s salt cavern storage 
potential could be extended by storage in porous underground caverns, the applicability of 
hydrogen to cope with the seasonality of the heating demand and to support the electricity system 
in integrating high volumes of variable renewable electricity could be greatly enhanced. 

66 NEP – Netzentwicklungsplan: see [Gas Development Plan 2020-2030, draft. FNB, p. 148, 4th May 2020]. 
67 The balance was 57 km of new built H-gas pipelines. 
68 Estudio de Impacto Ambiental, Proyecto Piloto Almacenamiento, Subterráneo de Gas Natural e Hidrógeno. 
Project by Hychico S.A., Argentina, 2013; St. Bauer: Underground Sun Conversion: Erneuerbares Gas zur 
Speicherung von Sonne und Wind. 7.03.2019, 
https://www.innogy.com/web/cms/mediablob/de/3950142/data/3880198/2/esk-im-ueberblick/vortraege-zum-
download/Underground-Sun-ConversionStephan-Bauer.pdf.  
69 Annex to FCH-GB-2019-14.Fuel Cells & Hydrogen 2 Joint Undertaking (FCH 2 JU)2020 Annual Work Plan & 
Budget, p. 49, 
https://www.fch.europa.eu/sites/default/files/AWP%202020_final29112019_clean%20%28ID%207481618%29
.pdf.  

22 

 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Figure 1-13 Map of European salt cavern structures across Europe70 

In brief, the regional coincidence of seasonal hydrogen storage potential and the availability of 
renewable electricity potentials at large scale is a good prerequisite for avoiding expensive 
electricity grid extensions. This is the case for Spain, Denmark, the UK, the Netherlands, and 
Germany. Though not explicitly mapped, also Austria and Poland offer large underground storage 
potentials for hydrogen71. 

Cavern-based gas storage on a system level is one of the cheapest long-term energy storage 
options, specifically apt to cover seasonal imbalances which are typical for today’s and potentially 
also future gas markets (heating, electricity load balancing). Based on a full-cycle storage and 
re-electrification, costs for seasonal electricity storage in hydrogen/salt cavern-based systems were 
found to be 0.1…0.3 €/kWh for central European conditions72.  

70 [J. Simón; D. Albes; M. Ball; A. Becker; U. Bünger; S. Capito; L. Correas; R. Evans; A. Ferriz; I. Iordache; O. 
Kruck; H. Landinger; J.-C. Lanoix; A. Le Duigou; J. Michalski; H. Mozaffarian; T. Rudolph; D. Schitea; P. 
Speers; M. Weeda: Assessment of the Potential, the Actors and Relevant Business Cases for Large Scale and 
Long Term Storage of Renewable Electricity by Hydrogen Underground Storage in Europe. Study for FCH-JU by 
partner group, Deliverable No. 6.3 - Joint results from individual Case Studies, 14th July 2014, 
http://hyunder.eu/wp-content/uploads/2016/01/D6.3_Joint-results-from-individual-case-studies.pdf].  
71 R. Tarkowski, G. Czapowski: Salt domes in Poland e Potential sites for hydrogen storage in caverns. Int. J. 
Hydrogen Energy, 43 (2018), pp. 21414-21427.  
72 These costs include conversion and re-conversion of electricity to gas. F. Crotogino, S. Donadei, U. Bünger, 
H. Landinger: Large-Scale Hydrogen Underground Storage for Securing Future Energy Supplies. 18th World 
Hydrogen Energy Conference 2010 - WHEC 2010. 

23 

 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Decentral, opportunity strategy vs national, harmonised gas strategy 
development 

Background for this criterion was the question whether a national hydrogen strategy and – as part 
of it – the hydrogen gas infrastructure strategies are currently based on a local, company or 
industry sector-based strategy or whether a comprehensive national hydrogen strategy has already 
been formulated and published or is at the development stage. As the role of hydrogen as an 
energy carrier is currently gaining much interest combined with high learning gradients, this 
criterion is one of momentary nature. Nevertheless, it tells about the impact of a Member State’s 
ambition in having understood the potential contribution of hydrogen and its universal contribution 
as an energy carrier across all energy sectors (sectoral integration) and the implementation of a 
decision process. In our interviews we have learnt that a number of Member States foresee the 
development of a national hydrogen strategy to be published soon, even though so far only France 
(2018) Germany (2020), the Netherlands (2020) and Portugal (2020) have published their national 
strategies73. 
Screening the national hydrogen strategies or related recent publications, a strong interest in inter-
regional or supra-national cooperation within the EU and also international cooperation becomes 
apparent at this early stage of development going beyond the formulation of regional and national 
hydrogen strategies. The following examples underpin the different facets of cooperation 
anticipated: 
 

Inter-regional cooperation: The regional Northern German hydrogen strategy74 
explicitly points at a cooperation beyond their own territory within Germany (Brandenburg, 
North Rhine-Westphalia) as well as outside of Germany with the Northern Netherlands 
(region of Groningen) or Scandinavia and on a technology basis with countries like China, 
Japan, South Korea, and USA/Canada. For potential imports of hydrogen, North Africa, the 
Middle East, and Australia are mentioned. 

  One-sided cooperation proposal by one Member State: Spain offers to cooperate on 

the export of renewable electricity and green hydrogen on economic grounds75. 

  Bi-lateral cooperation between Member States: Both national hydrogen strategies of 

the Netherlands and Germany raise the need for bi-lateral cooperation on the basis of at 
least balancing energy supply and demand and the development of hydrogen 
infrastructures. 

  Multi-Member State cooperation: At EU level, multi-lateral cooperation initiatives have 
been published such as the “Joint Political Declaration of the Pentalateral Energy Forum on 
the role of hydrogen to decarbonise the energy system in Europe” between Austria, 
Belgium, France, Germany, Luxembourg, the Netherlands, and Switzerland76. 

Interest in future use of biomethane in gas grid 

As documented in the green gas study for DG Energy in 201977, assessing the future role of 
hydrogen and biomethane in the European gas infrastructure, it was found that the interest in the 
use of the gas grid for transporting biomethane varies across EU Member States. Whereas e.g. in 
Spain much of the biomethane is admixed to the NG grid at transmission level, it is fed into the gas 
distribution level in most other Member States. The impact of accommodating both green hydrogen 
and biomethane in the future, might hence be different depending on the Member State. As a 
general approach, stakeholders have argued that three options may be applied to accommodate 
both green gases: 

  Blending hydrogen and methane to methane grids, and – also depending on the local 

situation – in general with a higher focus on hydrogen over time (mostly at distribution but 
for the example of Spain also at transmission level), 

  Keeping or developing parallel methane and hydrogen grids depending on local production 

capacities and end-use development, hand in hand with the production of synthetic 

73 France: https://www.ecologique-solidaire.gouv.fr/sites/default/files/Plan_deploiement_hydrogene.pdf, 
Germany: http://www.bmz.de/en/press/aktuelleMeldungen/2020/juni/200610_pm_031_Federal-Government-
adopts-National-Hydrogen-Strategy-and-establishes-National-Hydrogen-Council/index.html 
74 See 
https://www.hamburg.de/contentblob/13179812/f553df70f865564198412ee42fc8ee4b/data/wasserstoff-
strategie.pdf 
75 See https://www.dw.com/de/spanien-braucht-neue-industrien-setzt-auf-grünen-wasserstoff/a-54035381 
76 See https://www.bmwi.de/Redaktion/DE/Downloads/P-R/penta-declaration-
signed.pdf?__blob=publicationFile&v=4 
77 Trinomics, LBST, E3M (2019): Impact of the use of the biomethane and hydrogen potential on trans-
European infrastructure, the Netherlands 
https://www.government.nl/binaries/government/documents/publications/2020/04/06/government-strategy-
on-hydrogen/Hydrogen-Strategy-TheNetherlands.pdf; Portugal: [Portuguese Government approves hydrogen 
strategy, €7b investments, 24th May 2020, https://fuelcellsworks.com/news/portuguese-government-approves-
hydrogen-strategy-e7b-investments/].  

24 

 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

methane from hydrogen in cases this is deemed a suitable and competitive transition 
option and 

  Gradually reducing the methane operated grid share78. 

Also, mixed approaches of the above options could be possible. E.g. for Spain with its central 
biogas schemes mostly for upgrading to biomethane and feeding it into the transmission grid, also 
characterised by a dedicated and well utilised gas infrastructure today, a 100% conversion to 
hydrogen is not in view in the short- or medium term. Therefore, a methane transmission grid 
needs to remain in place, unless alternative local end-uses will be identified or – with adapted 
technology and regulation – methane may be blended with H2-rich gas flows of 80 vol%. This 
situation would only change in the long-term, if additional and possibly parallel dedicated hydrogen 
transmission pipelines were built, e.g. to import green hydrogen from North Africa in the South or 
export it to central Europe in the North.  

1.3.4 Hydrogen end-use 

For better understanding the hydrogen strategy end-use specific considerations by EU Member 
States, the following four criteria were considered in more detail: 

  Share of end-use sectors served by hydrogen (industry, mobility, heat, power production) 
  Seasonality of hydrogen demand 
  Dispersed small vs central large users 
  Blended hydrogen-users or pure hydrogen users 

Share of end-use sectors served by hydrogen (industry, mobility, heat, power 
production) 

The majority of all hydrogen used today, is used as chemical feedstock for industry and typically 
produced from fossil energy, i.e. by steam reforming of natural gas (SMR). When Member States 
developed their early hydrogen energy strategies, these hydrogen quantities – equivalent to an 
annual EU market size of 325 TWhH2/yr. or 9.75 MtH2/yr. in 2015 – were not within the scope. 
Instead, the initial focus of future hydrogen end-use was on its use as a vehicle fuel or for mobility, 
and the inclusion of industry has happened only lately.  

This extended perspective to a wider use of hydrogen as universal energy carrier may be a 
consequence of understanding its potentially strategic role in the energy system. Major arguments 
in favour of applying hydrogen energy in the future include its use for load-levelling of variable 
renewable electricity, the need for sectoral integration to unlock economic synergies, the potential 
of the gas infrastructure (transmission and distribution) to transport/store energy in molecules 
efficiently, and its capability for long-distance energy transport, including for imports, etc. Based 
on their energy system structures today, individual Member States have recently begun to 
communicate different interests in which end-use sectors they envision hydrogen to be introduced 
at large scale. The following four fundamental drivers for an introduction of hydrogen energy in one 
or more sectors have been identified, with the initiating sector mentioned in parenthesis79: 
  Ample RES-E potential or ambitions as well as seasonal hydrogen storage 

potentials: apply hydrogen for load-levelling of fluctuating renewable electricity supply or 
for hydrogen export (power sector) 

  Technology innovation: develop opportunities for value creation from innovative 
technologies along the hydrogen value chain which can serve one or possibly 
simultaneously several end-use sectors (e.g. fuel cells or hydrogen storage equipment for 
transport and stationary applications80) (mobility and or residential heating end-use as well 
as manufacturing/processes for industry) 

  Existing gas infrastructures: sustaining existing high value energy assets of the Member 

States’ gas infrastructures refurbished for CO2-free gases (gas sector) 

  Existing hydrogen use in industry: transfer existing know-how in hydrogen process 

technology and safe operations to other energy applications (industry sector) 

78 
 For Germany an extreme position is the option that with hydrogen becoming the dominant gas in the gas grid 
towards 2050, biomethane injection may become limited and available biogas could rather be locally used for 
decentralised power (and heat) production.  
79 Naturally, EU Member States are unified by their ambition to fulfil their EU energy policy obligations across all 
end-use sectors. This ambition has therefore not been added to the drivers list. 
80 Only recently Daimler has announced a refreshed interest in the development of fuel cell technologies for 
mobile applications, e.g. in cooperation with Volvo, and for stationary CHP plant development in cooperation 
with Rolls-Royce Power Systems ([Jetzt aber Vollgas. Süddeutsche Zeitung, 30th June 2020]). 

25 

 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

The four drivers cannot be fully separated; the mix of hydrogen end-uses in any Member State will 
vary based on its existing energy (hydrogen energy) as well as industry structures (hydrogen as 
base chemical). The UK is an obvious example of a (former) Member State that focuses on the use 
of hydrogen for heating based on the strong traditional role of natural gas for this sector. As a 
consequence, hydrogen is posed to play an important role for this sector applying similar 
technologies (boilers)81. Residential energy supply being in focus in the UK, studies have indicated 
its use also for industry and mobility. The end-use profile for hydrogen is much less obvious in 
other countries with little or no hydrogen tradition. Portugal, much like Spain currently takes a 
fresh look at the potential contribution of hydrogen in their energy systems, starting from serving 
as energy carrier for the export of RES-E82 and rather open for its application mostly in mobility or 
industry (e.g. ammonia production). Flagging its interest in value creation from innovative green 
hydrogen technologies, the German national hydrogen strategy has put its economic ambitions 
high on the agenda, the second major ambition to fulfil its GHG targets across all energy sectors83. 
Germany’s hydrogen strategy is much facilitated by its tradition as largest user of hydrogen in the 
industry sector. So far, Austria and Poland have been unspecific concerning their future ambition 
for hydrogen end-use. From interviews and recent studies, it is understood that hydrogen might be 
applied across all end-use sectors but that industrial hydrogen use will stand out for both Member 
States until 2030 to reach economies of scale, and therefore obviously in early clusters84. The 
injection of hydrogen into the gas grid to also serve mobility and the residential sectors would be 
addressed in a consecutive step. More details are to be expected in the national hydrogen 
strategies of both Member States, expected to be published by the end of 2020.   

Seasonality of hydrogen demand 

The major driving force behind the seasonal variation of energy demand is the demand for space 
heating, typically representing a fourth of all energy use, and mostly covered by fossil energy 
today (natural gas, mineral oil, coal)85, and hence one of the major GHG emission sources. The 
seasonality in energy demand varies by region (North or South), the North suffering from the 
typically strong winter/summer variation, only partially buffered by higher building standards in 
some Member States. This dependency has recently been analysed for the FCH2-JU86 and is 
displayed in Figure 1-14. The graph does not necessarily represent the future energy demand for 
heating/cooling, possibly to be partially contributed by hydrogen, as other options have not been 
addressed such as behavioural energy savings, technical and operational efficiency, and electric 
heat pumps.  

The figure groups the prime candidate countries for the use of hydrogen for space heating/cooling, 
and shows the natural gas share in the heating sector versus the combined heating & cooling share 
as percent of total final energy demand, also indicating the total energy demand in 2015 as a third 
dimension by bubble size. According to this graph, the following Member States have a high 
potential for using hydrogen for heating/cooling purposes: Belgium, Croatia, the Czech Republic, 
France, Germany, Hungary, Italy, the Netherlands, Romania, Slovakia, and the UK, the underlined 
ones coinciding well with those countries having the densest natural gas grids today (chapter 
1.3.1). Out of these Member States, only France, Germany, and the Netherlands have published 
national hydrogen strategies while Belgium, Italy, and the UK are in the process of preparing one, 
NL however with little ambition in using hydrogen for heating purposes, insulation, energy 
efficiency and electrification apparently being the preferred options. 

81 See [Pathways to Net-Zero: Decarbonising the Gas Networks in Great Britain. Prepared by Navigant for 
Energy Networks Association, 21st October 2019]. 
82 Pedro Furtado (REN) and Christian Pho Duc (SmartEnergy): [World Hydrogen Congress, Green Power Global 
Webinar: Greening the gas grid, 11th May 2020]. 
83 Die Nationale Wasserstoffstrategie, Bundesministerium für Wirtschaft und Energie (BMWi), Juni 2020, 
http://www.bmz.de/de/zentrales_downloadarchiv/wasserstoff/Nationale-Wasserstoffstrategie.pdf.  
84 Wasserstoffstrategie für Österreich. Konzeptentwurf Sektion VI, Wirtschaftskammer Österreich (WKO), Wien, 
Mai 2020, 
https://www.google.com/url?sa=t&rct=j&q=&esrc=s&source=web&cd=&cad=rja&uact=8&ved=2ahUKEwinwNq
nzI7tAhXODOwKHQB1B2EQFjADegQIAhAC&url=http%3A%2F%2Fwko.at%2Fooe%2FBranchen%2FIndustrie%2
FZusendungen%2FKonzeptentwurf%2520Sektion%2520VI%2520Wasserstoffstrategie%2520f%25C3%25BCr%
2520%25C3%2596sterreich.pdf&usg=AOvVaw3xOpJIn7ZhWxxwwqbz6ve3; Andreas Veigl: Energiezukunft 
Österreich - Szenario für 2030 und 2050. Study commissioned by GLOBAL 2000, Greenpeace and WWF, June 
2015. 
85 Exceptions are France (nuclear electricity) and the Nordic countries (hydropower) for space heating. 
86 Hydrogen Roadmap Europe - A sustainable pathway for the European energy transition. McKinsey study for 
the Fuel Cells and Hydrogen 2 Joint Undertaking, February 2019, 
https://www.hydrogeneurope.eu/news/hydrogen-roadmap-europe-has-been-published.  

26 

 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Figure 1-14 Seasonality of the energy demand for heating and cooling by Member States 
in Europe87 

Dispersed small vs central large users 

Across EU Member States’ strategies both central and decentral ramp-up schemes have become 
apparent. A major decision criterion for emerging hydrogen energy applications in central schemes 
is the ambition for scaling up, which in turn is driven by the goal to drive down specific hydrogen 
production and infrastructure costs. The awareness of the necessary economies of scale has 
developed only recently in the growing interest of installing cheaper hydrogen refuelling 
infrastructures for mobility88 or building new or refurbishing existing NG transmission pipelines for 
full hydrogen operation89. The central concepts typically apply for Member States with existing 
large-scale energy infrastructures for energy production/provision and end-use. This is typically the 
case for central, i.e. North West Europe (including Italy).  

The major aspect behind decentral hydrogen supply schemes are missing opportunities to scale-up 
applications, such as the absence of large central potential short-term hydrogen users, i.e. large 
industry clusters (chemical industry, fertiliser industry, steel industry or large refineries). The other 
missing link is existing large-scale infrastructure to be readily converted from natural gas today to 
hydrogen in the near-term, as is e.g. the general case for the peripheral EU Member States. 
Whereas in central Europe gas transportation corridors comprise parallel pipelines, lending 
themselves for a stepwise conversion from methane gas to hydrogen, the transition is more 
difficult for transmission gas grids relying on single pipeline corridors, as the choice may then be 
either to apply H2-blending or otherwise converting from methane to hydrogen in one big leap. In 
contrast, the challenges for the distribution grid are similar for central and peripheral Member 
States, which typically supply dispersed customers. They have various options, from reducing the 
distribution grid extent, H2-blending or full H2-conversion. An example for a full conversion of 
distribution grids to hydrogen is the Leeds 21 City Gate project, whereas in Germany, some 
municipalities may opt for the blending option, supported by a stable H2-supply from the 
transmission grid. Denmark has stated in its national energy strategy, that with biomethane having 
a major role also in the future, a basic methane grid needs to be kept in operation for biomethane 
collection at distribution level. Also, hydrogen will only be transported in the TSO grid and “last 
meter” connections to individual houses will be given up in favour of electric heat pumps and 
district heating systems.  

Relevant examples for the different approaches are the hydrogen gas strategies in central Europe 
(Germany, the Netherlands, …) which target a mixed central/decentral hydrogen end-use 
development scheme to supply both large central hydrogen users (industry) and likewise dispersed 
users (heating, mobility). Supplying large users with hydrogen can then be achieved by direct 

87 Hydrogen Roadmap Europe - A sustainable pathway for the European energy transition. McKinsey study for 
the Fuel Cells and Hydrogen 2 Joint Undertaking, February 2019, 
https://www.hydrogeneurope.eu/news/hydrogen-roadmap-europe-has-been-published.  
88 E.g., hydrogen refuelling stations for rail applications tend to be better utilised and are more concentrated 
than the dispersed hydrogen refuelling stations for road vehicles. 
89 One medium transport pipeline has a capacity of 10 GWH2 or 300 tH2/h and therefore requires to develop one 
or several large industry consumers or a large number of dispersed users (heating, refuelling stations). In the 
latter case the simultaneous development of a gas distribution grid is required, such as proposed for the H21 
Leeds City Gate project [https://www.h21.green/projects/downloads/].  

27 

 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

hydrogen imports through the transmission grid or hydrogen from electrolysis in central plants 
close to the RES-E locations or by imports of natural gas, for hydrogen production combined with 
CCS schemes for CO2-disposal in other locations90. For both schemes the transmission grid has to 
be accommodated, either for hydrogen or for additional natural gas supply, the second option also 
in need of a new CO2 transport infrastructure (see Figure 1-4). A decentral hydrogen supply option 
is onsite-electrolysis at small scale to e.g. supply remote hydrogen end-users, such as e.g. 
refuelling stations for rail applications91.  

Likewise, Italy with industry clusters to use large quantities of hydrogen both in the South 
(refinery in Sicily) and the North (steelworks in Dalmine close to Milano92) has presented ideas of 
the future role of its transmission gas grid for transporting hydrogen produced from domestic RES-
E or imported from North Africa via Sicily93. But also decentral PV- or wind based electrolysis 
projects have been suggested for Italy94. Concluding, also Italy could develop a mixed central / 
decentral hydrogen use and provision approach, even though not formulated in its national 
hydrogen strategy yet. 

In contrast and documented in its national hydrogen strategy from July 202095, Spain foresees its 
hydrogen roll-out to emerge in a rather decentralised way to supply a few local industry clusters 
(refinery, fertiliser production) and to collect hydrogen from solar energy clusters for export to 
other EU Member States through the gas grid (blended to the existing gas grid in small amounts or 
as dedicated hydrogen through re-furbished or new-built pipelines)96. A conversion of the 
transmission grid to accommodate more than 2 vol% of hydrogen is therefore difficult to foresee 
before 2030. Instead, it is part of Spain’s vision to build/re-furbish distribution type hydrogen 
pipelines in local clusters for the decentral supply of hydrogen end-users from RES-E operated 
electrolysis. In its national hydrogen strategy, Spain foresees to invest ca. B€ 8.9 in hydrogen 
development activities over the next 10 years, large shares of which are expected to come from 
the private sector and supporting projects for value creation. By 2030, Spain aims to install 4 GWH2 
of electrolysers, one tenth of the EU's target of 40 GWH2.  

Blended hydrogen users or pure hydrogen users 

In the ongoing discussions about the impact of hydrogen development on the gas infrastructures, 
the following potential approaches could be identified: 

  Pure hydrogen end-use:  

o  high purity fuel for fuel cell vehicles and stationary fuel cells 
o 
o 

fuel for 100% H2 heating boilers 
combined chemical feedstock and energy carrier/fuel for industry (fertiliser 
production, refineries, steel industry) 

  Admixed hydrogen end-use: 

o  Up to 2 vol% max for use in CNG combustion engine operated vehicles97 
o  Fuel for heating boilers adapted to specific H2-blending-rate 
o  Fuel for the industry, max H2 concentration level to be agreed individually case by 

case 

90 In the case of the H2omorrow project, the plan is to convert the natural gas to hydrogen onsite and close to 
the hydrogen end-users, with CO2 produced to be liquefied onsite and shipped by river and ocean ship to the 
CO2-disposal site underneath the North Sea [https://oge.net/en/us/projects/h2morrow].  
91 As e.g. announced in https://www.evb-elbe-
weser.de/aktuelles/detail/?tx_news_pi1%5Bnews%5D=61&tx_news_pi1%5Bcontroller%5D=News&tx_news_pi
1%5Baction%5D=detail&cHash=6e5e8d0cd09d51672de5298e259a9936 for the first FC rail pilot project in 
Bremervörde in northern Germany. 
92 See presentation [TENARIS, techint and tenova: Zero CO2 emissions – EAF and Hot Rolling mill plant as 
presented at the IPCEI workshop in Brussels, 15th January 2020]. 
93 See [The hydrogen challenge: The potential of hydrogen in Italy, SNAM report, 10-11th October, 2019, 
https://www.snam.it/it/hydrogen_challenge/repository_hy/file/The-H2-challenge-Position-Paper.pdf]. 
94 See [P. G. Muraa, R. Baccolia, R. Innamoratia, St. Mariottia: Solar energy system in a small town constituted 
of a network of photovoltaic collectors to produce electricity for homes and hydrogen for transport services of 
municipality 6th International Building Physics Conference, IBPC 2015, 
[https://doi.org/10.1016/j.egypro.2015.11.002].  
95 Hoja de Ruta de Hidrógeno: Una apuesta por el hidrógeno renovable, Gobierno De España, Ministerio Para La 
Transición Ecológica Y El Reto Demográfico, July 2020, 
https://www.google.com/url?sa=t&rct=j&q=&esrc=s&source=web&cd=&cad=rja&uact=8&ved=2ahUKEwirjKf3
0o7tAhUEGuwKHdtVBCQQFjACegQIAxAC&url=https%3A%2F%2Fwww.miteco.gob.es%2Fes%2Fprensa%2Fulti
mas-noticias%2Fel-gobierno-aprueba-la-hoja-de-ruta-del-hidr%25C3%25B3geno-una-apuesta-por-el-
hidr%25C3%25B3geno-renovable%2Ftcm%3A30-513814&usg=AOvVaw0Q7lHdt_GUROH9fbJRA0Te. 
96 Based on information from stakeholder discussions by the authors. 
97 Limitation currently imposed by existing CNG tank specifications. 

28 

 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

All options have been mentioned within individual national hydrogen strategies, but only few 
Member States have specified their priorities, except the UK with its outstanding H2-for-heating 
conversion approach. The impact of the hydrogen specifications on the gas infrastructure both at 
transmission and distribution level is determined by the specific end-uses and end-use technologies 
in each Member State. It may also result in alternative hydrogen infrastructures to be developed, 
such that the gas industry needs to respect the individual frameworks (e.g. specifying hydrogen 
quality) as imposed by the individual end-use sectors.  

One specifically critical example is the potential use of hydrogen for fuel cell vehicles typically 
requiring high purity hydrogen which may be difficult to be provided through the gas grids. Should 
this become a major option, very pure hydrogen needs to be delivered at large scale, which 
requires the hydrogen gas specification to follow the harmonised hydrogen standards as a vehicle 
fuel98.  

 

The gas industry has been discussing the issue of hydrogen quality for two years. An apparently 
well-agreed gas industry opinion is that a two-quality hydrogen pathway needs to be aspired99: 
Industry-grade hydrogen100: The dedicated hydrogen gas grid should only carry one 
single hydrogen quality, well specified by the Member State’s and later European 
regulations/standardisation to avoid the necessity of parallel grids of different quality as 
used to be the case for natural gas. The agreed level would be minimum 98% purity. This 
is justified by two major reasons: (a) the fact that it will be difficult to respect a higher H2-
quality specifically in converted natural gas grid sections101, and (b) that higher grade 
hydrogen will be much too expensive for the average bulk hydrogen industry customer102. 
Through a tentative and informal comparison of internal research work, some European gas 
companies already agree that European harmonisation of hydrogen gas quality can be 
achieved in principle, e.g. through the support of EASEE-gas. As the international and 
European hydrogen gas requirement standards have served as guidance, the gas industry 
believes that barriers for reaching a European agreement are small.103 Also, the recent 
research results by the gas industry on impurity types and their maximum allowable levels 
in industry grade hydrogen undertaken so far can be seen as universally applicable. 

  Fuel cell-grade hydrogen: In the future, fuel cell vehicles may also be served by fuelling 

stations connected to the dedicated gas grid taking profit from the advantages of gas grid 
hydrogen delivery (cost, safety, public acceptance, …) compared to delivery by trucks. 
Also, some Member States might want to build on the application of fuel cell CHP units in 
the heating market. As both FC applications will require a significantly higher H2-quality of 
99.97% than served by the grid (98%), decentral or on-site, local gas purification units 
would be needed to separate the most relevant impurities, such as CO, H2O or O2. Other 
inert constituents, not harmful for the FC operation, such as N2 or Ar might just remain in 
the gas. These purification units will have to be built according to the H2 gas grid delivery 
specifications on the hydrogen-from-grid feed-side and to the FC operational requirements 
on the hydrogen-to-vehicle product-side. The responsibility for hydrogen purification could 
be in principle be in- or outside the scope of the gas grid operators. 

98 This specification is being developed in ISO 14687:2019 (Hydrogen fuel quality - Product specification for 
cars and stationary applications), ISO FDIS 19880-8:2019 (Gaseous hydrogen - Fuelling stations — Part 8: Fuel 
quality control) and EN 17124:2018 (Hydrogen fuel - Product specification and quality assurance - Proton 
exchange membrane (PEM) fuel cell applications for road vehicles). For Europe, the EC has ushered 
implementing agreement M533 (ANNEX 2 of the Alternative Fuels Directive (AFID) for hydrogen refuelling 
stations) to safeguard unified technical specifications and standards across Europe. 
99 The information is based on a discussion with a large European TSO in August 2020. 
100 As fuel cells will also be operated by industry, the term “industry-grade quality” has been used by the 
European Hydrogen Backbone study for a higher quality type of hydrogen. In this study “industry-grade 
hydrogen” is considered as the type of gas used by large-scale industrial end-users (e.g. chemical industry, 
refineries, steel production). As the quality level for this use can be significantly lower, it may also be 
significantly cheaper. It is suggested that an unambiguous definition will be aspired soon at European level. 
According to the current German rules & standards it has been dubbed “Group A” (98%) in contrast to “Group 
D” (99.97%) for the “fuel-cell grade” hydrogen. 
101 It is believed that all converted NG grids to dedicated hydrogen operation can fulfil this specification. 
102 The industry interviews carried out by the gas industry have considered aspects of 3 peer groups: (a) H2-
consuming industry : Specification of the type of impurities and their allowable maximum levels acceptable 
by the end-use applications; (b) H2-production processes: type and quantity of impurities from the known 
production processes (e.g. Cl2 from Chlor-alkali processes, to be confirmed), CO from SMR, H2O or O2 from 
electrolysis); (c) emerging as necessity from pipeline supplied gases to public users: operational safety 
(e.g. explosion limits) and environmental or human impact (e.g. max. allowable workspace concentration 
(MAC)). With this information the 98% specification envelope was further detailed for the allowance/limitations 
of individual constituents.  
103 For the H2 quality used in FCEVs (ISO 14687 Grade A) the DIN 17124 has been built on ISO 14687 almost 
one by one. 

29 

 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

From the above it can be concluded that to allow the development of a supra-national 
interconnected hydrogen grid and to facilitate cross-border trade, a process will need to be 
established to agree on a robust H2-quality definition104. This will then allow to fulfil the 
requirement which was expressed by the European Hydrogen Backbone report as follows: “A 
mature European hydrogen backbone assumes well-functioning interoperability across borders…”. 

1.3.5 Application of criteria to EU regions 

For a better understanding of how EU regions are preparing themselves for the introduction of 
hydrogen as green gas into their energy systems, a method has been developed comprising the 
following steps: 

  Definition of regions 

  Evaluating Member States’ situations 

  Graphical presentation of results 

 

Interpretation of results 

Simplifying the graphical presentation, the most suitable approach was by grouping individual 
Member States into European regions reflecting their current gas infrastructure intensity. For 
reasons of consistency, we have chosen the definition from the green gas meta study for DG 
Energy and presented it in Figure 1-15: 

  Northwest: BE, DE, DK, FR, IE, IT, LU, NL, SE, UK 

  Southwest: ES, PT 

  Southeast: mainly Balkan countries and AT 

  East: CZ, PL, SL 

  Northeast: Baltic countries and FI 

Figure 1-15 Definition of five EU regions with differing interests in gas infrastructures 

As the effort should not cover all single Member States, but instead provide a principle view to the 
development situation as “snapshot”, we have identified one or more Member States to be 
representative for each group for desk research. The interest in developing a hydrogen gas 
infrastructure currently being highest in central and Southwest Europe, the number of Member 
States assessed in these two regions has been higher, simply for the reason of sufficient 
information available.  

For these Member States we have then assessed their approach to the 17 asset related criteria 
from above. As single Member States can deviate from their Member state group, the conclusions 
drawn are of general nature. It is specifically pointed out that this evaluation of criteria represents 
the differences between regions and by no means a ranking, i.e. a “1” is not equivalent to “poor 
performance” and a “5” not equivalent to “excellent performance”. Instead the individual 
evaluation bandwidth (not “ranking”) is provided in Table 1-4.  

The result from the Member State specific evaluation has been aggregated for individual Member 
States to the umbrella region respecting an average for the Member States by own judgement105 

104 This will be the role of CEN, to be included in CEN TC 234/WG11, possibly in collaboration with JTC-6. 
105 The figures generated do not present a calculated average taking into account statistical figures (extent of 
gas grid, population or final gas demand) but is based on our personal evaluation. 

30 

 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

and the result is documented in Table 1-4. As this table is difficult to interpret, the data has been 
incorporated in the spiderweb graph in Figure 1-16. 

Table 1-4 Member State specific evaluation of asset-based criteria list (“blanks” denotes 
no evaluation possible) 

Potentials/ambition in renewable electricity development 

Extent of current gas transmission grid 

Extent of current gas distribution grid 

Aspired green or blue (SMR/CCS or CH4-pyrolysis/C-use/deposition) H2 
shares 

Decentral vs central H2-production 

Domestic vs imported H2 provision 

Extent of dedicated H2-grid or H2-blending at TSO-level 

Extent of grids with H2-blending or dedicated H2 grids at DSO-level 

New H2 infrastructure versus methane infrastructure refurbishment 

Existing private H2 grids 

NW 

SW 

4.5 

4.5 

4.5 

4 

4 

3 

4.5 

3 

3 

3 

5 

3.5 

2.5 

5 

2 

4.5 

1 

1 

1 

1 

Existing seasonal H2 storage potential (salt caverns, other structures) 

3.5 

4.5 

Decentral, opportunity strategy vs national, harmonised gas strategy 
development 

Interest in future use of biomethane in gas grid  

Share of end-use sectors potentially served by H2 (industry, mobility, 
heat, power production) 

Seasonality of potential H2 demand 

Dispersed small vs central large potential hydrogen users 

Blended H2-users or pure H2 potential users 

4 

2 

4.5 

3 

3.5 

3 

5 

3 

5 

3 

3 

2 

EA 

NE 

3 

3 

2 

4 

2.5 

1 

1 

1 

2 

5 

3 

2 

3 

5 

5 

1 

1 

3 

4 

5 

1 

1 

1 

5 

3 

3 

4 

2 

SE 

2.5 

4 

1.5 

3 

4 

3 

1 

3 

1 

4 

3 

5 

3 

3 

3 

4 

2 

(light blue: general aspects, light green: H2-production, light red: H2-infrastructure, light yellow: 
H2-end-use) 

Figure 1-16 Spiderweb graph of criteria valuation for five EU regions  

31 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

A careful interpretation of this evaluation results in the following conclusions: 

  General characteristics: As suggested by Figure 1-16, central (i.e. Northwest) Europe 
and Southwest Europe currently stick out concerning the combination of their dense gas 
grid and high potentials or ambitions to develop domestic renewable electricity as a basis 
for green hydrogen production, making them candidates for the PW1 approach. In the 
other three regions this criteria combination is less obvious and they are candidates for any 
of the other three PW types. Exceptions from this general approach are obvious, with e.g. 
Austria possibly also being a candidate for PW1.  

  Hydrogen production: Currently, no obvious correlation between the three H2-production 

specific criteria exists. They all stand for themselves. However, it is obvious that the 
“peripheral regions” in the Northeast, East, and South (Italy as outlier belonging to central 
Europe) have a significant interest of potentially importing green hydrogen from outside 
Europe with some interest also from central Europe in blue hydrogen. 

  Hydrogen infrastructure: The variation for most infrastructure related criteria is high 

across single regions106. One criterion however sticks out, the one concerning the strategy 
level at which hydrogen pathways or infrastructures are planned. It could be observed that 
a growing number of national authorities have identified hydrogen as an important energy 
carrier and fuel, going hand in hand with the increased production of variable renewable 
electricity. Among these, e.g. Portugal, which has recently released its national hydrogen 
strategy and Poland, which showcases that hydrogen is up on the current energy agenda, 
could be pointed out.  

  Hydrogen end-use: The regional four-criteria based analysis shows that the interest of 

the Member States assessed could support the hypothesis that by 2030 the introduction of 
hydrogen is not yet demand driven. In contrast to today’s hydrogen pipeline business, 
solely being demand-driven, the gas industry is in the process of identifying its position to 
make the most out of the existing gas infrastructure assets, i.e. capability-driven. Most of 
the Member States assessed, seem to tend for a mixed dedicated and blended-H2 hydrogen 
approach, the supply of a mix of large- (continuous for industry) and dispersed (fluctuating 
for heating, mobility) users supporting the assumption of a cost-driven ramp-up phase. The 
emerging supply infrastructure would thus need to supply hydrogen at a high level of 
flexibility (storage), both at small-scale (local, e.g. refuelling stations) and at large-scale 
(seasonal for space heating) storage capabilities. 

In various industry-based analyses over the years as well as recently, the authors have compared 
different transport modes for hydrogen import from North Africa. The probably most important 
insight from these exercises is that the import costs strongly depend on a large number of key and 
therefore influential parameters, some of which are presented in the following list: 

 

Import (= transport) of compressed hydrogen via pipeline (CGH2) versus liquefied 
cryogenic hydrogen (LH2) (versus LOHC, methanol, etc.) 

o  Transport distance (x km vs y km) and routes (pipeline vs ship routes vs …) 
o  Capacity scaling (x ton/yr. vs y ton/yr.) 

 

Local/regional distribution via pipeline (CGH2) versus road transport (CGH2 or LH2) 

o  Distribution distances (x km vs y km) 
o  Dimensioning (diameter, pressure, flow velocity) and design of pipeline system 

(new-built vs refurbished) 

  Hydrogen end-use 

o  High versus low H2-demand per site 
o  Required H2-supply pressure (high vs low pressure) 
o  Type of hydrogen end-use (CGH2 vs LH2) 

  Other 

o  Seasonality or fluctuation of hydrogen demand per day, week, month, year 

Some of these parameters can be of game changing nature, i.e. a general contents unspecific 
assessment can result in misleading conclusions, with the potential consequence of high sunk 
capital investments. Hence, a general comparison of global energy transport vectors is possible but 
potentially misleading, and a parametric and algorithm-based generic comparison of competing 
PtL-based energy transport with hydrogen by gas infrastructure will always be only general and 
indicative in nature. To understand the details, a regionally focused analysis will have to take 
multiple parameters into consideration, such as: source-to-target, relevant and non-relevant 
transport modes by road (rail, truck) or maritime paths, energy transfer quantities and their 
seasonality and daily/weekly fluctuations, direct versus real transport distances respecting possible 
and typical routes, end-use- vs energy carrier-based, pathway hurdles (political, …), and finally 
also a potential re-utilisation of otherwise stranded assets (e.g. LNG terminals).  

106 The analysis has shown that the variations are even strong within the five EU regions.  

32 

 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

For this report, we therefore present an analysis carried out by the international energy agency 
(IEA) which has compared the transport and conversion cost for importing hydrogen as gas or 
chemically embedded in ammonia (NH3) by pipeline, as hydrogen cryogenic liquid, and as ammonia 
or absorbed in the liquid energy carrier LOHC by ship.  

Figure 1-17 shows that the hydrogen pipeline related transmission costs scale strongest with the 
transmission distance, about a factor of 3 from 1,000 to 3,000 km107. As the two left graphs show 
the costs for transporting the energy carrier and not hydrogen as such, the conversion costs from 
the right graph need to be added. I.e. for a transport distance of 1,500 km, the specific hydrogen 
pipeline transmission costs are about 1.0 US$/kgH2 and 1.5 US$/kgH2 for ammonia. It should also 
be noted, that if the respective energy carrier needs to be re-converted to hydrogen gas if required 
by the specific end-use, then the additional re-conversion costs need to be added as well108. Hence, 
even at 3,000 km distance the hydrogen pipeline transmission costs are less than for piped 
ammonia. The economy of scale is less distinct for ammonia than for hydrogen transport by 
pipeline beginning at the same order of magnitude of transport costs.  

Both LOHC and ammonia transport by ship result in low specific transport costs for all transport 
distances whereas the cost for liquid hydrogen via ship comes out highest, specifically if the high 
conversion costs are accounted for. For all distances the transport costs of LOHC appear to be 
lowest. But, taking the potential re-conversion costs into account, connected to energy losses of 
about 15% of the transported energy, the gap at least for liquid hydrogen and ammonia closes. 
The economy of scale of specific transport costs is little for all three energy carriers. 

Figure 1-17 Cost of hydrogen storage and transmission by pipeline and ship and cost of 
hydrogen liquefaction and conversion 109 

This analysis concludes with a few general statements all having an impact on the development of 
future hydrogen import options: 
  Hydrogen import: 

• 

• 

Pipeline transmission requires an initially incrementally large source for 
hydrogen production and a high demand source simultaneously, which will 
require strategical (i.e. nationally backed) investment decisions110. 
The import of liquid cryogenic hydrogen (LH2) (and other liquid energy carriers 
in general) is more flexible as several import routes can be used from one 

107 Reason are the operating costs for hydrogen compression along the pipeline. According to IEA, other 
drawbacks are the high capital costs entailed and the need to acquire rights of way. 
108 This specifically holds for the use of hydrogen as a vehicle fuel or for heating and many other industrial 
applications (refineries, steel production, …). 
109 The Future of Hydrogen. Report prepared by the IEA for the G20, Japan, June 2019. 
110 As an example, the German gas transmission infrastructure development is agreed in a national 
development plan (NEP), based on real capacity development and investment plans.  

33 

 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

export location (e.g. for LH2 about 1/3 of the production quantity and 1/10 of 
the import capacity as compared to hydrogen pipeline transmission) and 

 

 

The subsequent hydrogen transmission and distribution option is of relevance when 
evaluating a full hydrogen import value chain. i.e., whether a transport and distribution 
grid is available or can be refurbished from methane operation at moderate costs or 
whether hydrogen will have to be distributed via road transport. Therefore, the share of 
distribution has a high impact on the full value chain economics and a seemingly cheaper 
import path can turn out to be an expensive one if road distribution cannot be avoided (not 
even considering the advantages of an LH2 refuelling station (no onsite compression, 
station footprint and hence site development costs, …). 
Finally, also hydrogen end-use considerations will have an impact, e.g.: 

• 

• 

Who will be the major hydrogen customers, e.g. industry with a demand of 
gaseous hydrogen, ammonia, methanol, … or the heating sector in need of low 
to medium pressure gaseous hydrogen? 
Hydrogen refuelling stations: liquid cryogenic hydrogen (LH2) versus 
compressed gaseous hydrogen (CGH2): if LH2 would be stored on board of 
vehicles (trucks, trains, ships), the LH2 transport vector would have significant 
economic benefits. 

As a consequence, for further analysis and planning import pathways, the ambition may have to be 
adapted to e.g. read “how much of what energy carrier” instead of “either energy carrier A – or 
energy carrier B”. Also, the opportunity of refurbishing existing natural gas pipelines to hydrogen at 
reduced costs (9-33% of new-built pipeline costs) is an important asset in comparing transporting 
hydrogen as a gas through pipelines versus as a secondary liquid energy carrier by ship or truck.  

34 

 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

2  PIPELINES AS A NATURAL MONOPOLY?  

Similar to natural gas, the viability of competition must generally be assessed separately for each 
segment of the envisioned hydrogen industry, i.e. for (i) production, (ii) storage; (iii) transport 
(pipeline/ grid including both transmission and distribution level, or other transport), (iv) trading 
and (v) supply to end-users. The focus of this analysis is on hydrogen transmission/distribution by 
pipelines. 

The ultima ratio for regulating network operations is to ensure that the natural monopoly that a 
network may represent does not foreclose downstream and/or upstream markets. Not all dedicated 
networks necessarily qualify as natural monopolies conferring market power, e.g. based on a sub-
additive cost curve, or depending on the number and type of connected users and market 
contestability. 

This chapter analyses whether and to what extent and under what circumstances the development 
of a dedicated network under the pathways for the transport of hydrogen gives rise to a natural 
monopoly justifying regulatory intervention. 

“It is generally assumed that monopolies and certain forms of market power (for example, created 
by cartels, switching barriers, barriers to entry) are harmful to social prosperity because they lead 
to sub-optimal production from a social perspective and therefore to welfare losses.”111 

Therefore, natural monopolies and further situations of imperfect markets described here justify 
regulatory intervention. 

As an example of the growing concrete interest of industry including regulated gas grid operators in 
pure hydrogen pipeline systems and the regulatory aspects related to it, the German initiative GET-
H2112 aiming at building up a national hydrogen transmission grid has recently commissioned and 
published a legal study on the German legal framework for such an endeavour.113 

The development pathways of hydrogen network systems developed in Task 1 are the basis for 
analysing the ‘natural monopoly’ topic. The results derived here are based on literature on the one 
hand, and on input provided by stakeholders in interviews on the other hand. 

While dedicated primary research with detailed quantitative analyses of e.g. subadditive cost 
curves are beyond the scope of this assignment, cost structures of hydrogen pipelines will be 
compared to natural gas pipelines quantitatively. In order to establish a relative comparison 
between hydrogen and natural gas network systems, further aspects such as number and type of 
network users (injection and take-off) etc. are assessed qualitatively. 

“The natural monopoly situation may have different sources […]. It may be associated to strong 
scale economies (due to the importance of fixed costs, average costs decrease following the 
increase of the production); […] and network economies (related to interconnection and system 
control) […].114  

The first source of a natural monopoly is commonly known as a ‘sub-additive cost curve’ 
characterised by a situation where “a single company produces with lower costs than a combination 
of smaller companies”115 (see section 2.2.2). The second aspect relates to the advantages of an 
optimised grid based on integrated planning for an optimised coverage of a given geographical area 
by a pipeline grid (see section 2.2.3). A third cause for natural monopolies is notably a 

111 Ecorys and TNO: Waterstoftransport – verkenning marktordeningsalternatieven; commissioned by Dutch 
Ministry for the Economy and Climate; Rotterdam/Delft, 31 May 2018; translation by LBST 
112 www.GET-H2.de  
113 IKEM: Rechtsrahmen für ein H2 – Teilnetz – Nukleus einer bundesweiten, öffentlichen 
Wasserstoffinfrastruktur; September 2019 
114 Bento, N.: Building and interconnecting hydrogen networks: insights from the electricity and gas ex- 
Perience in Europe. Energy Policy, Elsevier, 2008, 36(8), pp.3009-3018. 10.1016/j.enpol.2008.04.007. 
halshs-00266304 
115 Bento, N.: Building and interconnecting hydrogen networks: insights from the electricity and gas experience 
in Europe. Energy Policy, Elsevier, 2008, 36(8), pp.3009-3018. 10.1016/j.enpol.2008.04.007. 
halshs-00266304 

35 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

consequence of a situation where the market is not well developed and in a well-functioning ‘steady 
state’, but is building up based on a low (but growing) number of consumers and producers. Here, 
market power, market contestability and market inefficiencies are relevant aspects to consider (see 
section 2.2.4). 

One cannot speak of a natural monopoly for hydrogen transmission and distribution until pure 
hydrogen becomes or is close to becoming a traded commodity, meaning that in a defined space, a 
large number of buyers start to compete to acquire it and a certain number of producers compete 
for access to transport means. This would coincide with phase 2 (2025-2030), and more broadly 
phase 3 (2030 towards 2050) defined in the European Commission Hydrogen Strategy116. 

Pipeline transport may be characterised by a natural monopoly as a result of the large economies 
of scale resulting from the high fixed costs of pipeline construction. However, the other elements of 
the value chain (production and consumption) need to exist as well. The market should be in a 
situation where hydrogen production and hydrogen consumption become widespread, contrary to 
the current situation which is characterised by a very small number of sellers and a limited number 
of buyers. Developments as described in detail in Task 1 may be anticipated to take place until 
such a situation is in place. However, once this (expected long-term) situation has been reached, 
hydrogen is very similar to natural gas in terms of natural monopoly situations in gas grids. 

In essence, the development of a hydrogen market is interlinked with the development of the 
transport infrastructure and possible natural monopoly situations related to it. The evolution of the 
market for hydrogen will not be uniform, but different markets may develop, e.g. hydrogen for 
industry, hydrogen for transport, hydrogen for heating and cooling, etc., with different 
characteristics in terms of the infrastructure required, number of market players, number of 
consumers, volumes to be transported and even, potentially, the quality of the hydrogen required. 

In a scenario where hydrogen is a commodity in a liquid competitive market, “the hydrogen 
transmission network would need to be regulated in a similar way to the methane transmission 
network today, given its natural monopoly characteristics.”117 Such a liquid competitive market 
may develop earlier in some EU regions than in others, and thus EU level regulation would have to 
be available for the early regional markets. Also, the development of liquid markets and of 
regulation may go hand in hand. The most appropriate timing for the development of rules is 
difficult to define at this stage. 

Existing assessments for natural gas grids can be transferred to hydrogen grids as long as market 
conditions are similar: "In contrast to other grid-based industries such as for example 
telecommunications, the existence of an unquestionable natural monopoly in the area of transport 
and distribution gas grids is seen as empirically proven. […] Reasons for such a monopoly are 
advantages because of size and interconnectivity in pipeline transport of natural gas.”118 

At the moment, the business case for large scale hydrogen deployment beyond the current demand 
level is not yet positive. Public intervention is still necessary to support production and market 
uptake before the market described above (many producers and many buyers) will be established. 
While many stakeholders believe that business cases, based on competitive markets at upstream 
and downstream levels based on favourable and predictable market conditions (potentially 
including enabling regulatory regimes) are needed and are anticipated to develop, a significant 
increase in supply/demand driving the development of a liquid market should take place justifying 
regulation and the choice of the most effective regulatory regime.  

It should also be noted that the hydrogen market may be quite different from today’s natural gas 
markets in the production segment. While natural gas production consists of the large set of 
operations necessary to deliver natural gas to the wellhead, such as exploration, drilling, 
production, and gathering, potentially the approach for hydrogen production could well be more 
diversified and agile, and allow for a much higher number of producers (if the market conditions 
are set to allow for this; see point above regarding the existence of competitive business cases 

116 European Commission (2020): Communication from the Commission to the European Parliament, the 
Council, the European Economic and Social Committee and the Committee of the Regions – A hydrogen 
strategy for a climate-neutral Europe. COM (2020) 301 final Brussels, 8.7.2020. 
117 Frontier Economics (2018): Market and regulatory frameworks for a low carbon gas system”; contracted by 
the UK Department for Business, Energy & Industrial Strategy; 
https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/699678/Fin
al_BEIS_low_carbon_gas_070318_clean-STC.pdf  
118 Sondergutachten der Monopolkommission Strom und Gas 2007: Wettbewerbsdefizite und zögerliche 
Regulierung. https://www.monopolkommission.de/images/PDF/SG/s49_volltext.pdf; Translation by Matthias 
Altmann 

36 

 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

based on stable market conditions). Natural gas production, furthermore, is limited to geographies 
with relevant natural resources, while hydrogen can be produced from different primary or 
secondary energies, notably renewable energies, which makes it superior to natural gas in a global 
strive for climate protection, and which allows for hydrogen production at many different locations 
depending on many factors.119 This may require a more decentralised grid, but does not change 
the fundamental consequences of a natural monopoly. Also, while natural gas production is linked 
to the geography of the natural resources and may require longer-term commitments for transport 
capacity, hydrogen producers may be less willing to enter into long-term commitments, which 
would increase the importance of third party access. 

While there are major differences between the production characteristics of natural gas and 
hydrogen, pipeline/ grid transport of hydrogen, which requires a significant investment and enables 
very high economies of scale, would have similar characteristics. This shows that a natural 
monopoly on hydrogen pipelines/ grids can develop. And it shows that having hydrogen pipeline/ 
grid transport regulated could secure the investments necessary, both for transport and for 
production (and also for consumption). 

2.2.1 Different situations in pipeline transport of hydrogen 

In terms of pipeline transport of hydrogen, it is important to distinguish between four different 
situations: 

1. Blending of hydrogen in existing natural gas pipelines 
This situation is not relevant in the present context, and is covered by the current regulatory 
regime for natural gas grids. 

2. Retrofitted natural gas pipelines, converted to be used for pure hydrogen 
Future hydrogen transmission pipelines will in many cases be developed from existing natural gas 
pipelines by refurbishing them for hydrogen operation. This option has proven to be technically 
feasible and will in several EU regions be economically justified because the demand for fossil gas 
will as of 2030 decrease significantly.120 To a certain extent, the current switch of low calorific 
natural gas to high calorific gas in the Netherlands, Belgium and Germany is an analogy for the 
switch to hydrogen. This reduces additional investment needs significantly, lowering average costs 
of transported hydrogen compared to newly built hydrogen pipelines. This makes it even more 
difficult for new entrants in transportation to compete, thus extending the monopoly situation from 
natural gas to hydrogen. 

When retrofitting a natural gas pipeline and preparing it to be used for the transportation of pure 
hydrogen, the asset is, in effect, taken out of the natural gas market and out of the regulatory 
scope of natural gas. As a result, the question of what regulatory regime should apply to it 
becomes immediately relevant, together with the economic and legal consequences of this shift 
from a regulated to a (currently) non-regulated asset.  

As retrofitting natural gas pipelines to hydrogen, according to the current status of knowledge121, is 
much cheaper than newly built hydrogen pipelines, the hydrogen pipeline/ grid “inherits” the 
natural monopoly from the natural gas pipeline/ grid (see section 2.2.2).  

Many stakeholders believe that, similar to transmission and distribution of natural gas, a natural 
monopoly could exist in relation to hydrogen retro-fitted natural gas pipelines/ grids for pure 
hydrogen. 

119 Natural gas supply is only driven by demand and mainly imported via long-term contracts from non-EU 
countries, while hydrogen is expected to be to a large extent domestically produced, and driven by the 
availability of (renewable) electricity, short-term energy market conditions and hydrogen demand. Moreover, 
natural gas production is characterised by a rather limited number of fields and operators, while for hydrogen a 
large number of producers and installations are expected to emerge. Natural gas production spans a wide range 
of capacities: the very large Groningen field in the Netherlands had a capacity beyond 100,000 MW in the first 
decade slowing down thereafter. At the lower end, the small German gas fields had on average a capacity of 
some 10 MW per field in 2019 down from 22 MW a decade earlier. Hydrogen production, in contrast, can be 
done at scales from kW to GW with first installations beyond 10 MW in place. 
120 Trinomics, LBST, E3M (2019): Impact of the use of the biomethane and hydrogen potential on trans-
European infrastructure; contracted by the European Commission DG ENER; 
https://op.europa.eu/en/publication-detail/-/publication/10e93b15-8b56-11ea-812f-01aa75ed71a1/language-
en?WT.mc_id=Searchresult&WT.ria_c=37085&WT.ria_f=3608&WT.ria_ev=search  
121 Trinomics, LBST, E3M (2019): Impact of the use of the biomethane and hydrogen potential on trans-
European infrastructure; contracted by the European Commission DG ENER; 
https://op.europa.eu/en/publication-detail/-/publication/10e93b15-8b56-11ea-812f-01aa75ed71a1/language-
en?WT.mc_id=Searchresult&WT.ria_c=37085&WT.ria_f=3608&WT.ria_ev=search  

37 

 
 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

However, there is no natural monopoly yet in hydrogen pipelines, and a market test and more in-
depth analyses would be useful to determine the specific market situation in each case. 

3. Newly built pipelines for pure hydrogen 
The assessment with respect to newly built hydrogen pipelines is similar to retrofitted natural gas 
pipelines with the exception that investment costs are higher. Here, it depends on the regulation 
both for natural gas pipelines (as the to-be-retrofitted pipelines are in the regulated asset base) 
and for hydrogen pipelines as well as on the actual cost differential between retrofit and new build. 
It may, however, be assumed that retrofit will in most cases be significantly less costly than new 
build, which implies a market entry barrier for new entrants. However, also competition on 
hydrogen transport may be different with truck transport (hydrogen either in gaseous or in liquid 
form), rail or ship transport being potentially more relevant competitive options. Also, on-site 
production of hydrogen is a competing option (see also section 2.2.5). 

4. Existing pipelines serving existing hydrogen consumers 
Existing hydrogen pipelines (see section 2.2.5) are in general not open for third party access and 
are thus not an option to the hydrogen transport market in their current structure.  

2.2.2 Sub-additive cost curve 

Economic theory defines a natural monopoly as a situation where an industry is characterised by a 
sub-additive cost curve.122 Or in other words, a natural monopoly exists where total costs of 
production are lower for a single firm than for two or more companies with the same total 
production. This is frequently the case if initial investments are high creating economies of scale. 
While electricity and gas grids are typical examples of natural monopolies, telecommunications 
generally is not a natural monopoly: Gas pipeline operation is a “’typical’ natural monopol[y] with a 
high degree of network synergies. By contrast, long-distance telephone networks (“backbones”) 
have been transformed from monopolistic to competitive structures over the last decades due to i) 
a large surge in demand, and ii) decreasing costs. Since neither can be expected in natural gas 
transmission, the emergence of competition is unlikely in the future as well.”123
 In more detail: 
“The cost structure of a pipeline network is characterised by high capital intensity and low variable 
costs. The majority of investment costs are ‘sunk’ costs (in the true sense of the word). 
Transmission pipelines have long lives (35-60 years). Technical progress is slow, particularly when 
compared with the ever-evolving telecom industry. Thus, the gas sector is characterised by a low 
degree of innovation and relatively modest modernisation requirements. Total costs are composed 
of fixed costs (pipeline, compressor stations, metering) and operational costs (maintenance, 
variable fuel costs of compressor stations). Pipeline costs are mainly fixed costs, whereas in 
compressor station costs are mainly variable costs.”124 

However, gas pipelines do not under all circumstances represent a natural monopoly, and the 
situation can change over time: “A natural monopoly can dissolve notably in those elements of the 
value chain where the sub-additivity of the cost curve is not very strong, investments are only 
partly irreversible and possibility for innovation exists. […] This does not exclude a situation where 
in the long-term a very dynamic demand growth could lead to a competitor building pipelines in 
parallel where demand cannot be satisfied by the incumbent alone.”125 Independent of how realistic 
such a situation may be for hydrogen, this argument shall only serve to highlight the limitations of 
the sub-additive cost curve criterion. 

Structurally, hydrogen pipelines are very similar to natural gas pipelines in mature markets.  

A rough estimate may illustrate semi-quantitatively the sub-additivity of the cost curve for 
hydrogen pipelines: At a diameter of 400 mm, one meter of transmission pipeline at 100 bars 
requires an investment of some 1.000 €; for 700 mm diameter pipelines, an investment of 1500 € 
per meter is required126. Assuming that hydrogen flows through a pipeline are proportionate to the 
cross section of it (pi times the radius squared), then the investment per meter of length and per 

122 von Hirschhausen, Neumann, Ruester: Competition in Natural Gas Transportation? Technical and Economic 
Fundamentals and an Application to Germany; Dresden, July 2007 
123 Ibidem 
124 Ibidem 
125 Sondergutachten der Monopolkommission Strom und Gas 2007: Wettbewerbsdefizite und zögerliche 
Regulierung. https://www.monopolkommission.de/images/PDF/SG/s49_volltext.pdf; Translation by Matthias 
Altmann 
126 Trinomics, LBST, E3M (2019): Impact of the use of the biomethane and hydrogen potential on trans-
European infrastructure; contracted by the European Commission DG ENER; 
https://op.europa.eu/en/publication-detail/-/publication/10e93b15-8b56-11ea-812f-01aa75ed71a1/language-
en?WT.mc_id=Searchresult&WT.ria_c=37085&WT.ria_f=3608&WT.ria_ev=search  

38 

 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

square millimetre of cross section is a measure of the investment per cubic meter of gas 
transported. With the numbers above, the investment for three 400 mm pipelines is double that of 
one 700 mm pipeline, while the gas throughput is roughly the same.127 Actually, it is lower in the 
smaller pipeline as the flow resistance of smaller pipelines is higher that that of larger pipelines. 
The situation is very similar for distribution pipelines, which, due to the lower pressure, have lower 
investment costs per meter of length at the same diameter. Other cost elements are operation & 
maintenance costs, investment and operation & maintenance costs for compressor stations for 
transport pipelines (not required for distribution pipelines), and metering & instrumentation costs. 
Annualised investment costs are typically at a similar level as the other cost elements, which are, 
furthermore, proportionate to the initial investment. As a consequence, in this hypothetical case, 
the annual costs including all cost elements, are very roughly double as high for two smaller 
pipelines of similar hydrogen throughput as for one large pipeline. This rough estimate shows very 
clearly that hydrogen pipelines typically have a sub-additive cost curve. 

Where a natural gas pipeline is retrofitted for transport of pure hydrogen, one-off retrofit costs are 
much lower than investment costs for new pipelines. Depending on the age of the pipeline and the 
depreciation already taken place, pipeline retrofit is much cheaper than building new pipelines. So 
in a hypothetical situation where a regulated natural gas TSO converts a natural gas pipeline to 
pure hydrogen operation, this would have the double cost advantage compared to new investments 
in two smaller pipelines of the same throughput of lower investment costs (even if the natural gas 
pipeline is not fully depreciated yet), and of economies of scale (lower CAPEX and total costs of one 
large pipeline compared to two smaller pipelines). 

In view of overall cost optimisation, it should be kept in mind that regulated assets are in general 
depreciated over longer periods of time than assets in competitive activities, and that in principle 
profit margins should be lower because of the reduced commercial risk.128 As a consequence, 
regulated assets represent lower costs than commercially operated assets (all other aspects kept 
equal). 

2.2.3 Network planning and operation as underlying cause for a natural monopoly 

ACER and CEER in their recent conclusions paper on decarbonisation and decarbonised gases note 
a “growing recognition that the ‘natural monopoly’ element of TSOs lies really in network planning 
and operation. Current trends in the industry such as digitalisation and decentralisation allow 
bypassing of some networks or of network components.”129 The natural monopoly arising from the 
need for integrated planning and operation is a complementary aspect to the economic perspective 
described above.  

In any case, ACER and CEER emphasise the need for a system perspective, which goes beyond 
economic theory in including the geographical dimension, both within the geographical area of a 
monopoly, and more importantly in the collaboration of the various geographical monopoly areas 
across the European Union. 

Network planning for electricity and gas grids has been unified in the course of recent years at 
European level. Integrated planning for grids including electricity, natural gas and hydrogen could 
be beneficial from several perspectives, but may also present risks.  

Integrated planning of natural gas and hydrogen would provide for a process where the decline of 
natural gas consumption and the growth of hydrogen consumption could be anticipated by the 
relevant stakeholders, and could thus be managed in an optimised way. However, there could both 
be tendencies to block or slow down the development of hydrogen in order to protect the existing 
business, or to unduly accelerate it in order to create new business under lower risks. Also, there 
would have to be a process to define who would participate in the integrated planning for the 
hydrogen side. One of the challenges would thus be to design a process of selecting incumbents 
from the regulated natural gas sector, and/or of selecting new players interested in becoming 
hydrogen grid operators. A regulatory environment, in any case, would and should not only define 
rights of monopoly holders, but also obligations including the building-up of hydrogen grids based 

127 400 mm diameter is equivalent to a cross section of 125,664 mm², roughly 3 times lower that the cross 
section of a 700 mm diameter pipeline (384,845 mm²). Three 400 mm pipelines have a CAPEX of 3,000 €/m, 
double that of one 700 mm pipeline at 1,500 €/m. 
128 In company valuation, higher risks are taken into account in the so-called beta factor, which is used to 
calculate the appropriate rate of return for an investment into that company. Higher risks lead to higher return 
targets by investors into the company. Therefore, the business carried out by that company needs to generate 
these higher returns. In regulated markets, the rate of return is defined by the regulator, which takes into 
account the lower risk level of the regulated market. 
129 ACER, CEER: The Bridge Beyond 2025 – Conclusions Paper; Ljubljana, Brussels, 19 November 2019 

39 

 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

on thorough planning based on clear principles such as security of supply, non-discriminatory third-
party access, congestion avoidance/ minimisation, etc. 

Operation of gas grids has seen innovations related to market-based instruments complementing 
and partly eliminating physical gas flows. In this sense, gas grid operation has developed from a 
pure technical operation to a combined technical and market-based operation, partly disconnecting 
gas grids from the physical reality. These aspects need to be taken into account in the assessment 
of natural monopolies. This may not be fully possible today in a situation where an open hydrogen 
energy market does not exist yet, but anticipated to develop.  

2.2.4 Market power, contestability and inefficiencies 

The economic perspective of the sub-additive cost curve (see section 2.2.2) is qualitatively 
confirmed by [Ecorys and TNO, 2018], but extended to more general aspects of market power and 
market inefficiencies or failures: “In sectors where a physical network plays an important role 
(such as gas, electricity) there is often market power as a result of the existence of a natural 
monopoly, economies of scale and scope, vertical integration and asymmetrical information.”130 

In addition to the cost structure characterising natural monopolies, a lack of real or potential 
competition is a related criterion for natural monopolies justifying regulation. With respect to 
natural gas transmission pipelines, a “necessary, but not sufficient, condition for workable 
competition is that a dominant part of the exit points must be accessible to more than one 
subsequent market network or that such access can be established under ‘reasonable business 
conditions’”131. In other words, if there is a liquid integrated market served by several transmission 
pipelines, then there is also competition between transmission pipelines.  

As a fundamental basis for the development of a natural monopoly in hydrogen transport pipelines/ 
grids, hydrogen must be a traded commodity, i.e. there must be production and demand in large 
quantities for hydrogen of a defined quality. As mentioned above, this would coincide with phase 2 
(2025-2030), and more broadly phase 3 (2030 towards 2050) defined in the European Commission 
Hydrogen Strategy. A further pre-requisite is that the number of sellers and buyers is high, or has 
the potential to grow to a level allowing for a liquid market (see also the introduction to section 
2.2). 

Competition for hydrogen transport is not only between several (potential) pipelines or grids, but 
also with road, rail or ship transport. And there is the option of onsite production (notably from 
electricity). Hydrogen as a facilitator of system integration thus opens up new possibilities, which 
on the other hand make the situation more complex, and due consideration should be given to this 
additional complexity. 

2.2.5 Existing hydrogen pipelines and pipeline systems 

In the EU countries where hydrogen is produced and used in large quantities by a limited number 
of companies, pipeline systems have been established to transport it. The following Table 2-1 
shows hydrogen pipelines and pipeline systems in operation in Europe, some of them since many 
decades. The hydrogen pipeline system in the German Ruhrgebiet, for example, has been operated 
safely since 1938. 

Table 2-1 Hydrogen pipelines and pipeline systems in operation in Europe132 

Network 

Country  Length (km) 

Operator 

North Europe 
(BE+NL) 

Dunkerque 

France East 

France Centre East 

France South East 

Le Havre 

Ruhrgebiet 

Monthey 

BE, NL 

949 

Air Liquide 

FR 

FR 

FR 

FR 

FR 

DE 

CH 

14 

37 

57 

42 

Air Liquide 

Air Liquide 

Air Liquide 

Air Liquide 

4 

Air Liquide 

240 

Air Liquide 

2 

Air Liquide 

130 Ecorys and TNO: Waterstoftransport – verkenning marktordeningsalternatieven; commissioned by Dutch 
Ministry for the Economy and Climate; Rotterdam/Delft, 31 mei 2018; translation by LBST 
131 von Hirschhausen, Neumann, Ruester: Competition in Natural Gas Transportation? Technical and Economic 
Fundamentals and an Application to Germany; Dresden, July 2007 
132 Own data collection based on various publications and sources. 

40 

 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Network 

Country  Length (km) 

Operator 

Priolo 

Rozenburg 

Teesside 

Porto Marghera 

Leuna-Bitterfeld 

Teesside 

Stenungsund 

Heide 

Burghausen 

Hoek-Sluiskil 

Total 

IT 

NL 

UK 

IT 

DE 

UK 

SE 

DE 

DE 

NL 

6 

Air Liquide 

50  Air Products 

5  Air Products 

2  Air Products 

Linde 

Linde 

135 

35 

18 

30 

8 

12 

1 646 

The Hoek-Sluiskil pipeline in the Netherlands, which was the subject of agreements signed in March 
2018 between Dow, Yara, ICL-IP and Gasunie Waterstof Services, has been commissioned in late 
2018. It stands out from the hydrogen pipeline systems as the pre-existing natural gas transport 
pipeline was modified at a few points making it suitable for transporting hydrogen, while the other 
pipeline systems have been purpose-built as hydrogen pipelines. The Hoek-Sluiskil pipeline is now 
being used commercially for transporting more than four kilotons of hydrogen per year. 
Transporting hydrogen to ICL-IP at a later stage is also part of the plan. 

The existing hydrogen pipeline networks are not regulated. A recent study concludes: “Given the 
current market context, this type of market failure [market power leading to access limitations, 
unfair conditions, discriminatory or improper use of information, or price-related competition 
problems, such as excessively high rates and price discrimination] has limited relevance for 
additional government intervention. The current pipeline networks for hydrogen transport are 
primarily aimed at supplying large industrial parties and often have limited geographical coverage. 
When constructing these networks, long-term agreements were made by (industrial) parties with 
sufficient knowledge. If competition problems arise, the Competition Act (…) is in principle the 
appropriate instrument for intervention. Neither have any concrete cases emerged from the 
interviews in which there is clearly abuse of market power.”133 In other words, the market does not 
seem to be distorted as there are long-term contracts and no information asymmetries, at least in 
the current Dutch hydrogen transport pipeline system, where the number of market operators is 
still very limited. 

It should be noted that the current hydrogen pipelines in general do not offer third-party access. 
The business model is based on economies of scale from centralised production of hydrogen for 
some large industrial users; transport is done by pipelines as this is the cheapest option to 
transport the relatively large quantities of hydrogen from the supply to the consumption sites. This 
competes with large-scale on-site hydrogen production through natural gas steam methane 
reforming, or in the future through electrolysers using electricity. Therefore, current hydrogen 
pipelines are in general competitive where by-product hydrogen is available in large quantities. For 
smaller quantities of hydrogen, road transport is in general cheaper than pipeline transport, in 
particular if customers are located at large distances from each other to render pipelines 
uneconomical. This competes with onsite hydrogen production based on electrolysis or natural gas 
steam methane reforming, where the competitive advantage depends on transport distances, 
competition, quantities, contract duration, and further parameters. 

However, a future hydrogen transport system may be expected to have different characteristics 
than today’s commercial hydrogen pipelines: “This does not alter the fact that, as the hydrogen 
transport market grows, competition problems may indeed arise in the future. When the supply of 
and demand for hydrogen increase, the importance of transport via pipeline networks also 
increases, and with it the risk of access-related or price-related competition problems. The 
protection of the various interests may then be better regulated through a specific set of regulatory 
instruments […]. When hydrogen becomes more widely used by consumers, for example in the 
built environment, the importance of consumer protection increases.” 134 

133 Ecorys and TNO: Waterstoftransport – verkenning marktordeningsalternatieven; commissioned by Dutch 
Ministry for the Economy and Climate; Rotterdam/Delft, 31 mei 2018; translation by LBST 
134 Ecorys and TNO: Waterstoftransport – verkenning marktordeningsalternatieven; commissioned by Dutch 
Ministry for the Economy and Climate; Rotterdam/Delft, 31 mei 2018; translation by LBST 

41 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

ACER and CEER come to the key conclusions that “decarbonised gases should be able to be 
integrated into existing gas markets […] New assets and activities should be facilitated through 
regulation, including a sandbox model at EU level for pilot, small scale projects and appropriate 
differentiation between competitive and monopoly activities. […] While it is too early to be 
definitive, large-scale hydrogen networks could be expected to provide regulated third party 
accessing.”135 It needs to be taken into account here that decarbonised gases may be physically 
different products: decarbonised methane based on biogas or based on Power-to-Hydrogen with 
subsequent synthesis to methane on the one hand, and pure hydrogen on the other hand. 
Nonetheless, the same or similar market platforms and processes may be used for the different 
products.  

A number of stakeholders have expressed similar views. There is a general tendency to assume 
natural monopolies to exist for transport and distribution in mature hydrogen markets, and also in 
emerging markets there is a relevant probability of natural monopolies to occur. However, mature 
markets are not there yet, but are anticipated to develop. Where the number of market players, 
both on the production side and on the demand side, is low, there is a lower chance of having a 
natural monopoly. In contrast, high numbers of market players relate to a high probability of 
natural monopolies. Thus, the critical, and difficult to answer, question is under which 
circumstances exactly natural monopolies emerge, and when exactly regulatory intervention would 
be justified. Learnings from natural gas grids can be applied to hydrogen, with the limitations 
discussed above. The views diverge on the exact circumstances and the exact timing of regulatory 
intervention with some stakeholders supporting rather early regulatory intervention, while others 
prefer late actions. A view voiced rather widely is to apply market tests, and to actively develop 
regulatory approaches step by step starting early with thorough tests and validations along the 
way with scientific support as a robust no-regret approach to regulation. 

While existing hydrogen pipeline infrastructure is currently not characterised by a natural 
monopoly, it is expected to represent in the future market situation a natural monopoly, based on 
the following elements which would justify regulatory intervention: 

• 

Pipelines have a subadditive investment cost curve, and other transportation 
means would for most uses not provide suitable or competitive alternatives;  
•  Hydrogen is expected to become a traded commodity with a high number of 

producers/sellers and buyers; 

•  Refurbishing natural gas pipelines to hydrogen operations will be less expensive 
than new-build pipelines, and will hence offer a competitive advantage to the 
concerned owners/operators. 

135 ACER, CEER: The Bridge Beyond 2025 – Conclusions Paper; Ljubljana, Brussels, 19 November 2019 

42 

 
 
 
 
 
 
 
 
  
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

3  HYDROGEN NETWORK INFRASTRUCTURE REGULATION 

The aim of this chapter is to develop options for the regulation of hydrogen infrastructures at the 
EU level, with a focus on networks, for a range of regulatory elements. This chapter is separated 
into the following sections: 

  Section 3.1 reviews relevant experience in the regulation of natural gas, electricity and 
telecom industries to identify encountered barriers and measures relevant for hydrogen 
networks regulation and market design (the latter is further analysed in chapter 4); 

  Sections 3.2 to 3.7 analyse regulatory elements for hydrogen network infrastructure, with 

the following structure for each element: 

1.  An introduction and discussion of the regulatory aspects relevant to hydrogen 

networks; 

2.  The analysis of regulatory options for a greenfield hydrogen network regulation, 

that is, without assuming current natural gas regulation would be applicable to 
hydrogen networks also; 

3.  The analysis of regulatory options assuming the current EU and national regulatory 
frameworks for natural gas were applied to hydrogen networks (with necessary 
modifications), to enable efficient investments and operation, and incentivising the 
conversion of methane networks when optimal from a societal point of view. 

  Section 3.8 analyses the potential regulation of hydrogen distribution networks; 

  Section 3.9 discusses transitional measures and regulatory experimentation. 

Figure 3-1 presents the structure of the chapter and the main network infrastructure regulatory 
elements which are analysed in detail. Balancing of hydrogen systems is addressed in chapter 4. 

Figure 3-1 Structure of this chapter and relation to regulatory elements 

The main options for each regulatory element are presented in the respective section, without each 
option forming a coherent ensemble – for example, option A for unbundling and option A for 
network access are not linked. Coherence between the options for each regulatory element is 
considered in the assessment of regulatory frameworks conducted in chapter 5. 

The focus on the EU level means that the options for each regulatory element may provide overall 
guidelines to Member States (to be implemented through EU directives) or regulate more 
specifically hydrogen networks in the EU (through EU regulation). Hence, certain options may leave 
significant room for Member States if regulation at the EU level is not warranted. 

Box 3-1 Current regulation of hydrogen networks in the EU and US 

Currently, dedicated transport and distribution of hydrogen in the EU are covered by different 
legislative acts:136 

  Directive 2008/68/EC on the inland transport of dangerous goods, based on and further 
specifying provisions of UN agreements, addresses transport by road, rail or inland 
waterway within or between Member States; 

  Directive 2010/35/EU on transportable pressure equipment, setting requirements for 

manufacturers, importers, distributors and owners for the conformity of such equipment, 
used in road, rail or inland waterway transport; 

136 Floristean et al. (2019). HyLAW Deliverable 4.4 EU regulations and directives which impact the deployment 
of FCH technologies. 

43 

Elements for a hydrogen regulationSection 4.1Relevant experiencein the regulation of network industries Introduction and discussion of relevant regulatory aspects Greenfield hydrogen network regulationNatural gas regulatory frameworks as a basisSections 3.2 to 3.9: regulatory elementsUnbundlingNetwork accessNetwork planningRevenueregulationNetwork chargingCapacity allocation and congestion managementDistribution networksTransitional measures and experimentation 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

  Directive 2014/68/EU complements the Directive on transportable pressure equipment, 

establishing essential safety requirements for stationary pressure equipment and 
assemblies with a maximum allowable pressure greater than 0.5 bar; 

  Commission Regulation (EU) No 453/2010 amending Regulation (EC) No 1907/2006 on 
the Registration, Evaluation, Authorisation and Restriction of Chemicals (REACH); 

  Regulation (EC) No 1272/2008 on classification, labelling and packaging of substances, 

establishing rules for the harmonised classification and labelling of hydrogen 

 

The ATEX directives 2014/34/EU address equipment, protective systems intended for use 
in potentially explosive atmospheres, and work in such atmospheres. 

Hence, only technical aspects of hydrogen transport and distribution are specifically regulated in 
the EU. The situation is the same for the US, which counts with the longest hydrogen pipeline 
network in the world, and where technical aspects related to hydrogen transport are regulated at 
the federal level especially by the Title 49 of the Code of Federal Regulations.137 Therefore, the 
current hydrogen network regulation has limited relevance for the potential regulation 
of TPA and other elements to existing or future hydrogen energy networks.  

The following elements are not addressed in this study, except where punctually relevant: 

 

Public support to hydrogen production and demand, such as target setting and economic 
support; 

  Consumer protection; 

  Safety aspects; 

  Standardisation of gas quality, equipment and appliances; 

 

Interoperability of energy networks; 

  Conversion or replacement of end-use equipment and appliances; 

 

Legal status of energy conversion. 

New EU-level regulation for hydrogen should avoid the risk of foreclosing regulatory and 
technological innovation. There is currently no experience with the regulation of hydrogen networks 
and markets in any Member State (or non-EU countries, for that matter), and EU-level legislation 
will inevitably set boundaries to the available options for Member States to regulate hydrogen 
networks and markets. 

By focusing on the regulation of hydrogen network infrastructure, the present chapter 
complements the analysis of chapter 4 on the design of hydrogen markets. The following 
assumptions base the analysis: 

 

If hydrogen networks and markets are regulated to some extent, the present European and 
national energy regulators will also be tasked with the oversight of the hydrogen sector – 
no separate hydrogen regulator would be set-up, given the synergies with electricity and 
methane sectors, even if the regulatory framework would be separated. Hence, at the EU 
level it is assumed that new regulatory tasks would be assigned to ACER; 

  Energy conversion (e.g. power-to-gas) is considered primarily a competitive activity; 

 

The regulatory choices should be stable and unforeseen changes should not undermine the 
viability of assets and business models of regulated and market actors. 

Box 3-2 The importance of regulatory certainty and timing of EU and MS-level legislation 

Deploying large-scale hydrogen projects in 2025-2030 as planned by some Member States and 
suggested by the European Commission in its Hydrogen Strategy138, requires experimentation by 
actors now in order to develop the necessary knowledge, as well as adequate regulatory 
frameworks already in the coming years. Kick-starting the deployment of hydrogen systems at a 
larger scale will require 1) the clear demarcation of what are considered competitive or regulated 
activities, and 2) adequate regulation to foster efficient infrastructure development. 

While EU legislation on the regulation of hydrogen networks is not expected to enter into force 
before 2023, some countries are already taking steps to adapt their national regulation to foster 
deployment of dedicated hydrogen infrastructure. 

137 CFR Title 49, Part 192: Transportation of natural and other gas by pipeline: minimum federal safety 
standards. 
138 European Commission (2020). A hydrogen strategy for a climate-neutral Europe 

44 

 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

In the Netherlands, the Energy Transition Act of 2018139 allows network companies, 
netwerkbedrijven to be involved in alternative energy carriers infrastructure (hydrogen, biogas, 
heat and cold). These companies are part of the same group as network operators, 
netwerkbeheerders, but may not exert regulated electricity and gas network nor energy trade 
and supply activities. The government can assign to the network companies temporary tasks in 
that regard. The Dutch NRA closed a stakeholder consultation in April 2020 on a guidance 
establishing what the network companies are effectively allowed to do in the domain of these 
alternative energy carriers.140 Specifically netwerkbedrijven: 

  May establish and manage infrastructure for alternative energy carriers; 
  May transport alternative energy carriers in that infrastructure, but are not allowed to 

supply or trade in alternative energy carriers; 

  May establish and manage, but not exploit production and storage facilities for 

alternative energy carriers. 

Following an agreement with the Dutch NRA, the netwerkbedrijf Gasunie Waterstof Services 
changed its name to Hynetwork in order to avoid any confusion with the regulated TSO 
(netwerkbeheerder) Gasunie Transport Services.141 Netwerkbedrijven can manage electrolysers 
and provide conversion services. 

The German Hydrogen Strategy also foresees regulatory experiments (‘sandbox’) in order to 
enable hydrogen projects. German branch organisations have also requested for regulatory 
changes in the current parliamentary term.142 

Hence, certain Member States such as Germany and the Netherlands are considering to or have 
already regulated aspects concerning hydrogen networks and associated infrastructure, ahead of 
any EU legislation on the matter. Some national stakeholders argue that this is necessary to 
provide certainty for hydrogen investments in front-runner Member States. While national 
developments allow for regulatory experimentation and increase certainty, it will be necessary to 
minimise the risks of ex-post regulatory changes to national frameworks due to EU measures. 
Also, other Member States may see significant deployment of hydrogen networks only after 
2030. Therefore, the target regulatory framework and market design for hydrogen should be 
agreed upon at EU level allowing action by front-runners and flexibility for different energy 
strategies, while minimising the risk of national regulatory divergence: 

  Continuous discussion by EU institutions and Member State policy makers and regulators 

for sharing best practices and agreeing on established principles for network regulation, 
such as use of objective criteria, transparency, non-discrimination and cost-reflectivity; 

  Early identification of regulatory aspects where EU action is warranted to promote 

market integration and avoid distortions, such as regarding cross-border issues (an 
important objective of the present study); 

  Employ experimentation mechanisms such as regulatory sandboxes, further discussed in 

section 3.9, to promote projects without extensive regulatory changes. 

Stakeholders’ opinions on general aspects of hydrogen network regulation 

Stakeholders are divided on the suitability of the current natural gas regulatory framework for 
hydrogen networks in general and regarding unbundling and third party access provisions in 
particular. GEODE supports a single gas definition comprising both methane and hydrogen 
gases,143 and others also noted that most mentions to natural gas could be changed rather easily 
to expand the scope to other gases. Otherwise, they argue that network operators would have to 
comply with two sets of regulation, which would considerably complicate the operation of the 
respective networks.  

However, multiple other stakeholders favour a separate approach (either through new chapters in 
the Gas Directive and Regulation or through new legislative pieces). For example, a national 
regulator argued that for the sake of transparency it would be more appropriate to define hydrogen 
as a separate gas, with regulation in a dedicated chapter in the national gas law or with an 
altogether new law, even if the regulatory approach for natural gas is deemed to be generally 

139 Wet tot wijziging van de Elektriciteitswet 1998 en van de Gaswet (voortgang energietransitie) 
140 ACM (2020). Consultation on “Leidraad netwerkbedrijven en alternatieve energiedragers” 
141 ACM (2020). Toezeggingsbesluit GTS over gebruik naam en beeldmerk. Available on 
https://www.acm.nl/nl/publicaties/toezeggingsbesluit-gts-over-gebruik-naam-en-beeldmerk 
142 Federal Ministry for Economic Affairs and Energy (2020) The National Hydrogen Strategy. 
FNBGas et al. (2020) Auf dem Weg zu einem wettbewerblichen Wasserstoffmarkt Gemeinsamer 
Verbändevorschlag zur Anpassung des Rechtsrahmens für Wasserstoffnetze 
143 GEODE (2020) Towards the New Age of Gas Networks: Proposal on the Regulation of a 
European Hydrogen Infrastructure 

45 

 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

adequate for hydrogen. Gas TSOs argue that the regulatory framework should adhere, as far as 
possible, to the regulatory principles and technical rules that underpin the Internal Energy Market 
for gas. 

Stakeholders are consensual on the need for the speedy definition of the hydrogen regulatory 
framework in order to provide certainty to regulated and market actors, and to avoid divergence of 
the national regulatory frameworks. Private hydrogen network operators, however, favour later 
regulatory intervention, as this would, it is argued, allow for these operators to realise the 
necessary investments to meet the decarbonisation needs of industrial customers. 

Stakeholders are also unanimous on the need for transitional measures which phase in 
requirements according to the different stages of the hydrogen market development in the (groups 
of) Member States. Taking this into account, setting a Hydrogen Target Model would be beneficial, 
drawing on best practices from the methane sector. Multiple stakeholders also highlight the need 
for room for regulatory learning and adaptation of the regulatory framework according to new 
lessons learned. 

This section briefly reviews relevant experiences in the regulation of natural gas, electricity and 
telecom industries to identify encountered barriers and measures relevant for hydrogen networks 
regulation and market design. 

The review of the barriers and measures in the natural gas and electricity sectors is focused on the 
3rd Energy and the Clean Energy for All Europeans packages, and the associated studies and 
evaluations which served to identify the barriers and justify the measures of the packages. The 
barriers and measures are presented in Table 3-1. Market aspects are also indicated in the table 
and analysed further in chapter 4. 

The 2005-2007 inquiry on the energy sector identified important barriers which were not 
adequately addressed in the 2nd energy package. While the 3rd energy package managed to 
significantly overcome multiple barriers, progress is still on-going with e.g. network codes and 
guidelines development. Moreover, the 3rd Energy Package did not adequately address issues which 
became apparent with the acceleration of new developments, such as the increasing share of 
(variable) renewable energy in the energy system, the associated deployment of uncoordinated 
capacity remuneration mechanisms, and further technological developments such as demand 
response, storage and power-to-X. 

Attention has been increasing to the need for regulators to accompany fast-changing market 
conditions, technological developments and increased decarbonisation of the energy system, 
providing flexibility to new business models while assuring the transparency, predictability of the 
regulatory framework.144 To this end, regulators have been employing different mechanisms for 
regulatory experimentation (discussed in section 3.9).  

The reform of and technological developments in the telecom sector provide further lessons which 
can be considered for the regulation of hydrogen networks: 

  Telecom equipment has become increasingly decentralised, modular and mobile. 

A similar development will occur with energy technologies, such as electrolysers and fuel 
cells, to varying extents, depending on the scenario and speed of R&D efforts and 
development of market designs enabling ‘new’ business models. Regulation of hydrogen 
infrastructure will need to account for the possibility of rapid upscaling of equipment and 
appliances connected to the network, as well as increased interaction (and arbitrage) with 
the methane and electricity systems; 

  Competing technologies for conventional telecom services, especially mobiles and the 
internet, along with sector reform, have led to a sharp reduction in the number of 
fixed phone users and to the entry of new market actors, while incumbents were 
reticent to risk their core business activities; 145 The roll-out of hydrogen networks could 
lead to rapid migration of users from methane networks (as long as other necessary 
elements such as hydrogen appliance technologies are also in place) and to the entry of 
new actors, eroding the customer base of methane network operators. 

144 See for example CEER (2019) 3D Strategy (2019-2021) - Digitalisation, Decarbonisation, Dynamic 
regulation 
145 Munns (2017) What the US Electricity Sector Can Learn from the Telecom Revolution 
http://blogs.edf.org/energyexchange/2017/02/28/what-the-us-electricity-sector-can-learn-from-the-telecom-
revolution/ 

46 

 
 
 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Table 3-1 Selected barriers and measures in the regulation and market design of EU electricity and natural gas sectors 

Barrier type 

Causes 

Measures 

Potential hydrogen measures 

Vertical 
foreclosure 

 Low level of unbundling, discrimination by operators for access to 
electricity and gas networks (and gas storage and LNG terminals) [1] 
 Vertical integration of production/import and supply [1] 

Lack of or 
distorted 
competition 

 Market concentration in forward and spot markets [1] 
 Bias in connection conditions [1] 
 Price regulation below market prices [1] 
 Legacy long-term contracts on import/transit pipelines not subject to 
TPA [1] 
 Legacy long-term contracts on energy markets [1] 
 Ineffective congestion management mechanisms [1] 
 Insufficient indication of the origin of electricity [2] 
 Slow deployment of innovative retail products [3] 
 Market design focused on centralised generation [3] 
 Distortive effect of RES support mechanisms [3] 

Limited cross-
border 
market 
integration 

 Different market designs [1] 
 Insufficient/unavailable physical and/or contractual cross-border 
capacity [1,3] 
 Bias in network planning [1,5] 
 Contractual restrictions on re-sale of energy [1] 
 TSOs and regulators focus on national concerns and on reducing 
system risks rather than on optimising market integration [2-3] 
 Uncoordinated capacity remuneration mechanisms [2,3] 
 Failure to address emergency aspects [3] 

 Effective unbundling of network and 
production/supply activities 
 Regulated access at non-
discriminatory conditions 
  Enhanced powers for NRAs 
  Active competition policy in 
foreclosure cases 

 Capacity and/or commodity release / 
contract swap 
 Contract / gas release as condition 
for approving mergers / acquisitions 
 Ceilings on ownership of electricity 
generation / long-term upstream gas 
contracts 
 UIOLI and other provisions 
 Incentivise investment in generation 
/ infrastructure 
 Implicit capacity day-ahead auctions 
 REMIT 
 Enhanced TPA requirements and 
Commission oversight on exemptions 
 Binding guidelines for transparency 

 Enhanced consistency of regulation 
in cross-border issues 
 Regional initiatives 
 Network codes and guidelines 
process 
 Binding guidelines for transparency 
 TYNDP process 

 Non-discriminatory and transparent access to 
networks (and large-scale storage) will be 
required 
 Ownership unbundling may be required for 
networks (and large-scale storage), but well-
designed requirements for legal unbundling may 
be sufficient 
 Some unbundling options have high (regulatory) 
cost and might hinder hydrogen deployment 
 Competition policy can complement sector 
regulation after its implementation 

 Legacy commodity and capacity contracts may 
foreclose competition 
 GOs important for development of renewable 
and low-carbon hydrogen 
 Renewable hydrogen support must be market-
oriented 
 Binding transparency guidelines relevant for any 
market development 
 Implicit hydrogen transport capacity allocation is 
preferred 

 Establish network codes / guidelines  
 Leverage regional initiatives for experimentation 
in front-runner regions, sharing of best practices 
and then upscaling to EU level 
 Enable cross-border trade (forward, spot and 
balancing) 
 Develop regional/EU level network planning, with 
bi-annual process leading to gradual 
improvements. 

47 

 
 
 
Sector integration – Regulatory framework for hydrogen 

Barrier type 

Causes 

Measures 

Potential hydrogen measures 

Inadequate 
regulatory 
oversight 

 Uncoordinated actions by MS and voluntary EU guidelines not able to 
promote harmonisation of e.g. CACM [6] 
 Insufficient competences of the regulators [2] 

 Enhanced powers for NRAs 
 Reinforced coordination between 
NRAs (ACER) 
 Reinforced cooperation between 
TSOs (in ENTSOs and at regional 
level) 
 Reinforced cooperation of DSOs (in 
EU DSO entity and regional) 
 Enhanced consistency of regulation 
in cross-border issues 

Insufficient 
transparency 

 Lack of network availability data, especially cross-border [1] 
 Lack of generation and storage data [1] 
 Little harmonisation on transparency requirements [1] 
 Information asymmetry between incumbents and others [1] 
 Lack of regulatory framework for data protection and exchange [3] 
 Lack of information regarding assets for which waivers apply 

 Binding guidelines for transparency 
 ENTSOs transparency platforms 
 Further TSO unbundling 
 Antitrust regulation 
 Monitoring of cross-subsidies, tariffs 
and access to customer data 

 Assign regulatory powers to NRAs and 
cooperation through ACER and new hydrogen EU 
TSO or ENTSO and EU DSO entity 

 Binding transparency guidelines relevant for any 
market development 
 Consider at least accounts unbundling for 
transparency of networks with TPA 
 Ensure publication of relevant information by 
incumbents (data quality included) 
 Include hydrogen in EU monitoring procedures 
(MMR, others) and potentially REMIT 

Lack of 
adequate 
price 
formation 

 Limited trust in price formation mechanisms [1] 
 Gas contract indexing to oil derivatives [1] 
 Lack of gas hub liquidity [1] 
 Lack of liquid DA and/or ID markets 
 Price regulation, including setting price caps [1-3] 

 Assessment and removal of 
distortions due to regulated supply 
tariffs 
 De-linking gas and oil commodities 
 Increase of interconnection capacity 

 Forbid regulated supply tariffs 
 Enhance market liquidity to have representative 
wholesale prices 
 Prohibit indexing to other commodities 
 Support interconnection capacity development 

Lack of 
enabling 
balancing 
rules and 
inexistence of 
liquid 
balancing 
markets 

 Small size of balancing zones [1] 
 Strict balancing rules (e.g. hourly balancing for gas, lack of re-
nomination possibility) 
 Requirement to book capacity at every interconnection point [1] 
 Non-transparent charges, clearing costs and (unjustified) penalties 
[1] 
 Lack of liquid balancing market, e/g/ due to electricity generators 
and/or gas supply market concentration [1] 
 Lack of cross-border harmonisation [1] 

 Widening of balancing zones 
 Regional initiatives 
 Network codes and guidelines 
process 

 Avoid small balancing zones / integrate where 
possible 
 Leverage regional initiatives for experimentation 
in front-runner regions, sharing of best practices 
and then upscaling to EU level 

 Ownership by incumbents [1] 

Inadequate 
TPA access to 
gas storage 
and LNG 
terminals 
Sources: [1] DG COMP (2007) Report on energy sector enquiry; [2] EC (2007) communication – Prospects for the internal gas and electricity market; [3] EC 
(2016) Evaluation of the EU's regulatory framework for electricity market design and consumer protection in the fields of electricity and gas; [4] Talus (2016) 
Introduction to EU energy law; [5] ACER/CEER Bridge beyond 2025; [6] stakeholder inputs  

 Unbundling rules  
 Regulated TPA at non-discriminatory 
conditions  

 Set minimum TPA requirements and unbundling 

48 

 
 
 
Sector integration – Regulatory framework for hydrogen 

Unbundling regulation aims achieving partial or total separation between the regulated and 
unregulated activities of an economic operator, as well as in some cases between different 
regulated activities. Regulated activities in the gas sector may include, besides the investment and 
operation in transmission & distribution assets, and planning and operation of the system, also gas 
storage and liquefaction/re-gasification. Unregulated activities comprise energy 
production/conversion, trade and supply, as well as gas activities/assets (e.g. transmission, 
storage, LNG terminals) for which an exemption from regulated TPA has been granted or 
negotiated TPA applies. 

Unbundling may apply not only to vertically integrated undertakings active in a sector, but also 
those active in multiple sectors, such as the electricity, natural gas and hydrogen sectors.  
Figure 3-2 illustrates the possible dimensions of unbundling: 

  Vertical unbundling, between the regulated and unregulated activities. Can be either intra- 

or cross-sectoral; 

  Cross-sectoral horizontal unbundling, between regulated activities for two or more different 

 

energy carriers; 
Infrastructure activities unbundling, i.e. separation of some of the regulated activities of 
system planning & operation, and investment & operation in storage, terminals and/or 
network assets. 

Figure 3-2 Illustration of dimensions of intra- and cross-sectoral unbundling 

Without effective unbundling and adequate oversight, there is a risk that network operators 
discriminate third parties regarding connection and/or access to the network in favour of their own 
(including affiliated) production and supply activities, cross-subsidise certain activities, and/or 
over- or under-invest in their energy network leading to higher overall system costs.  

With the increasing implementation of energy technologies such as electricity storage and demand 
response, which provide flexibility services to the system and, to a certain extent, substitute the 
need for investments in energy networks, it is necessary to adequately consider the costs and 
benefits of network investments vs competing alternatives across different energy sectors. To 
optimise the overall network configuration, one could consider unbundling network planning from 
network investment and operation, or at least organise a strong oversight with the necessary 
powers to e.g. verify correctness of data provided by regulated operators. 

Unbundling may be achieved, in decreasing order of the extent of unbundling, through: ownership, 
legal, functional or accounts separation of regulated and non-regulated activities. With ownership 
separation, the same company is not allowed to own both regulated and unregulated assets, 
although e.g. the ownership of minority shares without rights to vote or appoint board members 
may be allowed. Legal separation involves the separation of the regulated activities in a distinct 
legal entity, which may nonetheless be owned by a parent company with interests in production or 
supply. Functional unbundling is achieved by the effective separation of the decision making rights 
between unregulated and regulated activities, and of the human, technical (e.g. IT infrastructure), 
physical (such as buildings) and financial resources, as well as possibly the use of a separate 
corporate identity and/or assigning an unbundling compliance officer. Finally, accounts unbundling 
involves the use of separate accounts for the regulated activities, while the remaining activities 

49 

Methane systemSystemplanning & operationNetwork assets investment & operationSupplyProduction & tradeStorage asset investment & operationRe-gasification asset investment & operationVerticalunbundlingMethane infrastructureVerticalunbundlingHydrogen systemSystemplanning & operationNetwork assets investment & operationSupplyProduction & tradeStorage asset investment & operationRe-gasification asset investment & operationVerticalunbundlingHydrogen infrastructureVerticalunbundlingCross-sectoral horizontal unbundling 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

may make use of consolidated accounts. This allows to apply cost-reflective tariffs while avoiding 
cross-subsidisation between regulated and non-regulated activities.  

Unbundling and dedicated hydrogen networks 

The issue of whether to unbundle or not the functions related to hydrogen networks is influenced 
by a number of factors: 

 

For pathways and countries/regions with an important hydrogen development, significant 
investments will take place; 

  An important share of these investments may occur through conversion of methane 

networks to hydrogen. In the biomethane and hydrogen study,146 investment annuities in 
the hydrogen scenario for the EU28 were estimated at 4.7 billion €/a until 2050, split 
between 1.4 billion €/a for converted hydrogen pipelines and 3.3 billion €/a for new ones. 
The cost of repurposing networks from methane to hydrogen transport can be as low as 
10% of the cost of building new hydrogen pipelines.147 This would mean that in the study, 
for the EU28, converted pipelines would account for more than 50% of the hydrogen 
network length in 2050. It is very likely that also new network assets will be required, e.g. 
to connect specific converted pipeline sections or to connect hydrogen production plants; 
The type and number of hydrogen network users (national producers/importers on the one 
hand and consumers on the other hand) will evolve over time, not only as a result of the 
specific national strategies (focusing initially for example on production and imports of 
fossil-based low-carbon hydrogen and its use in industry and transport), but also 
depending on the efficiency of the regulatory framework (including unbundling measures) 
to incentivise new hydrogen producers and users; 
The planning, investment, and system and asset operation of regulated, large-scale 
hydrogen and natural gas systems would be to a significant extent similar. The expertise of 
existing natural gas system operators would be relevant for implementing these functions, 
but operators of existing private hydrogen networks have of course also relevant expertise; 
The development and operation of dedicated hydrogen systems will need to be realised in 
conjunction with the natural gas and electricity systems in order to minimise the overall 
energy system cost. There are hence important synergies in the planning and system 
operation of hydrogen, natural gas and electricity (and heat) systems. 

 

 

 

The central question regarding unbundling concerns the application of unbundling measures to 
owners/operators of future hydrogen networks. The following unbundling dimensions should be 
addressed: 

  Vertical unbundling within the hydrogen sector: this would address the separation of 
hydrogen production, trade and supply activities from network-related activities; 

  Unbundling between hydrogen network-related functions: the functions of planning and or 
operation of the hydrogen system could be separated from the functions of investment in 
and operation of the network assets; 

  Cross-sectoral vertical unbundling: could be required for undertakings active both in 

hydrogen-network related functions and in production, trade and supply activities in the 
natural gas or electricity sectors; 

  Cross-sectoral horizontal unbundling: could be required between the electricity, natural gas 
and hydrogen sectors, with legal or accounts separation between the network operators for 
each or a combination of those sectors.  

The possible unbundling of private hydrogen networks is a related, but secondary question. As 
presented in chapter 2, important hydrogen networks already exist in Belgium, Germany and the 
Netherlands, operated by a handful of companies. There is at present no unbundling of these 
networks, with each company owning and operating production and transport assets. Specific 
unbundling exemptions for private hydrogen networks are considered in the development of the 
different options below. 

Stakeholders’ opinions 

Stakeholders largely support vertical unbundling provisions for network infrastructure in the 
hydrogen sector, coupled with non-discriminatory third-party access. Stakeholders highlighted that 
unbundling provisions (and related third-party access) would be necessary at the European level 
and in the short-term (three to five years) in order to provide the investment certainty necessary 
for the development of hydrogen networks. One actor noted that if unbundled network operators 
would have a legal monopoly (where, by law, they would be the only ones authorised) or factual 
monopoly in a certain area of operation, this could be counterbalanced by them being assigned a 

146 Trinomics, LBST and E3-M (2019) Impact of the use of the biomethane and hydrogen potential on trans-
European infrastructure 
147 European Commission (2020) Hydrogen generation in Europe: Overview of key costs and benefits. 

50 

 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

number of responsibilities regarding e.g. regulation of revenues and tariffs, security of energy 
supply standards.148 

Nonetheless, one national regulator indicated that, while adequate third party access and tariff 
regulation could be sufficient to provide non-discriminatory, transparent access to the network, 
unbundling requirements could allow the third party access and tariff regulation to be less strict. 
This would be based on the well-established rationale that actions such as unbundling that directly 
alter the market structure can reduce the market power of operators as well as their interest to 
abuse it, thus reducing the need for more strict regulation and monitoring. 

Concerning horizontal unbundling, multiple stakeholders (including incumbent natural gas TSOs) 
support that the incumbent natural gas TSOs would be responsible for the planning, investment 
and operation of future hydrogen networks. They did not specify whether this role should be 
assigned through a legal initiative or would result from a factual monopoly. Arguments include the 
benefits of an integrated planning of natural gas and hydrogen infrastructure, the fact that the 
conversion of natural gas infrastructure is the lowest-cost option for developing hydrogen 
infrastructure, and the overall experience of gas TSOs with planning, investing and operating 
regulated networks. 

Other stakeholders indicated that while natural gas TSOs should be allowed to invest in and 
operate hydrogen networks, they should not necessarily be granted a legal monopoly with 
unjustified ex-ante exclusion of other interested parties, as e.g. existing private hydrogen network 
operators also have significant expertise that might be valued in future hydrogen systems. Private 
hydrogen network operators themselves indicated to be interested in investing in renewable and 
low-carbon hydrogen solutions. A stakeholder noted that there could be a conflict of interest for 
incumbent natural gas TSOs to also own and operate hydrogen networks. Nonetheless, no 
stakeholder argued for the co-existence of parallel hydrogen networks, although there could be 
competition with other means of transport – by road, rail or water. 

A gas TSO expressed his opposition to accounts unbundling between hydrogen and methane 
assets, noting that TSOs are already planning the repurposing of methane networks. This would be 
complicated by mandatory accounts unbundling, and moreover joint accounts would promote an 
efficient and rapid development of hydrogen infrastructure. 

3.2.1 Greenfield hydrogen regulation: unbundling 

The options developed for the unbundling requirements for hydrogen networks consider two 
dimensions: 

  Whether hydrogen networks planning, investment and operation is considered a 

competitive or regulated activity, or a combination of both (i.e. where regulated and non-
regulated actors are allowed to co-exist), and to what extent some form of unbundling 
(ownership, legal, functional or of accounts) is required between hydrogen networks and 
hydrogen production/trade/supply activities; 

  Whether some form of unbundling (ownership, legal, functional or of accounts) is required 

between methane and hydrogen networks. 

In the future, four types of operators for new hydrogen networks could exist, depending on 
unbundling and TPA rules (structured in Table 3-2): 

1.  Vertically integrated undertakings (VIUs), combining hydrogen 

production/trade/supply activities with hydrogen networks investment and operation. 
Would be allowed only in case hydrogen networks are not considered a regulated activity; 

2.  Hydrogen network operators, exerting only hydrogen network activities. Requires that 

hydrogen networks are considered a regulated activity; 

3.  Combined gas network operators, exerting both hydrogen and methane network 
activities. Requires that hydrogen networks are considered a regulated activity; 

4.  Merchant operators, developing specific transmission interconnectors in case hydrogen 
transport is considered an exclusively regulated activity and upon authorisation from 
regulators. 

148 Currently, energy network operators in EU MSs have a factual monopoly, but also in some cases a legal 
monopoly, such as the Finnish electricity TSO. 

51 

 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Table 3-2 Unbundling for different future hydrogen network operators 

Hydrogen network operator 

Vertical unbundling 

Unbundling to methane 
networks 

1. Vertically integrated 
undertakings 

2. Hydrogen network operators 

3. Combined gas network 
operators 

4. Merchant operators 

None / any 

None / any 

Preferred: Ownership 
Variant: Legal 

Ownership / legal 

Preferred: Accounts 
Variant: None 

Ownership / legal 

Further exemptions or waivers could be granted in national regulatory frameworks to operators of 
existing hydrogen networks and to direct pipelines. These are discussed below. 

Considering these dimensions, the main options are: 

  Option A: Hydrogen network-related activities are considered of a competitive nature and 

thus no vertical/horizontal unbundling is required; 

  Option B: Hydrogen networks are regulated, but the sector entry by non-regulated actors 

is allowed (represented here by VIUs). Vertical unbundling is required; 

  Option C: Hydrogen networks are regulated, excluding the participation of non-regulated 

operators. Horizontal and vertical unbundling are required; 

  Option D: Hydrogen networks are regulated, excluding the participation of non-regulated 

operators. Vertical unbundling only is required. 

Table 3-3 Unbundling options  

Hydrogen 
networks 
regulation 

Unbundling to 
methane 
networks 

Option A 

Option B 

Option C 

Option D 

Competitive activity 

Non-exclusive 
regulated activity 

Exclusive regulated 
activity 

Exclusive regulated activity 

No vertical/horizontal 
unbundling required 

Vertical unbundling 
required 

Horizontal and vertical 
unbundling required 

Vertical unbundling 
required 

Allowed 
operators 

1. VIUs 

1. VIUs 
2. H2 network op. 

2. H2 network op. 
4. Merchant 

Advantages 

 Enables private 
investment in 
networks 
 MS may still regulate 
at national level 
 Allows for innovation 
by private actors 
 Low regulatory costs 

 Enables private 
investment in 
networks 
 May leverage 
knowledge of CH4 / H2 
network operators 
 Allows for innovation 
by private actors 

 Entrants allowed 
 Lower cost of capital 
 Increased certainty 
for network users 
 May leverage 
knowledge of CH4 / H2 
network operators 

Disadvantages 
/ risks 

 Potential for market 
power and welfare loss 
due to sub-additivity 
 Difficulty to quickly 
upscale hydrogen 
networks, including 
across borders 
 Uncertainty due to 
competition of 
regulated and non-
regulated activities in 
certain MSs 

Mitigation 
measures 

 Competition law 
enforcement 

 Uncertainty due to 
competition of 
regulated and non-
regulated activities 
 Potential for market 
power 
 High regulatory costs 

 Requires transfer of 
NG infrastructure 
assets for conversion 
 Medium regulatory 
costs 

 Require a positive 
cost-benefit analysis 
for regulated NG TSO 
 Tender concessions 
for regulated hydrogen 
network operation 

 Tender concessions 
for hydrogen network 
operation 

2. H2 network op. 
3. Combined gas network 
op. 
4. Merchant  

 Facilitates conversion of 
NG infrastructure 
 Lower cost of capital 
 Reduced administrative 
burden compared to 
option C 
 Increased certainty for 
market actors 
 Leverages knowledge of 
CH4 network operators 

 Competitive advantage 
to incumbent methane 
network operators 
 Complicates cost 
allocation between 
hydrogen and NG 
infrastructure 
 May incentivise 
excessive repurposing by 
combined gas network 
operators 
 Medium regulatory costs 

 Require accounts 
unbundling. 
 Require a positive cost-
benefit analysis for 
authorising a combined 
gas TSO. 

For option A, regulated electricity and methane network operators could be involved with hydrogen 
networks, if allowed by their national regulatory framework and hydrogen activities were legally 
unbundled, at least. 

52 

 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

The advantages and disadvantages of the options are indicated in the Table 3-3. The following 
main aspects should determine the adequacy of each option: 

 

It is expected that, due to the natural monopoly characteristics of hydrogen networks, 
private and regulated networks will not co-exist in the same geographic area (although 
specific merchant pipelines could co-exist with a regulated network). Hence, allowing both 
non-regulated and regulated hydrogen networks should consist in a competition for the 
sector rather than in the sector, possibly through a cost-benefit analysis (CBA) by policy 
makers or regulators in order to consider a specific area as (un)regulated (see Box 3-3); 

  Even if hydrogen transmission/distribution was defined as a competitive activity, methane 

network operators authorised in certain Member States to be involved in certain 
unregulated activities could still compete as a non-regulated actor; 

 

Incumbent regulated natural gas network operators and private hydrogen system operators 
can both bring significant expertise to the planning, investment and operation of hydrogen 
networks. The first regarding not only technical expertise but also familiarity with network 
regulatory models and aspects such as stakeholder consultation in planning processes; 

  While market parties may have an interest in developing limited hydrogen networks for 
their local clients or own end-uses, they are unlikely to be interested in developing and 
operating large scale hydrogen networks per se. This may be the case of existing private 
hydrogen network operators, that may wish to devolve their networks to regulated network 
operators. Specific exemptions/waivers to unbundling can be considered in options B-D; 

 

 

Predictability of the regulatory framework should be guaranteed. Regardless of whether 
hydrogen network-related activities are considered a regulated or competitive activity, this 
should not be subject to posterior change, unless clear conditions are set ex-ante, in order 
to provide certainty for developing the network; 

Third-party access, revenue and network charging regulation would to some extent need to 
be imposed to regulated network operators, in order to ensure non-discrimination of 
network access and charges.  

Box 3-3 Competition for-the-market and the regulation of hydrogen networks 

A distinction can be made between competition in-the-market, where economic operators 
compete to supply a certain share of the market, and competition for-the-market, where 
economic operators compete to be able to be the sole supplier for a specific market. Energy 
networks are generally considered a natural monopoly and thus there is no competition in-the-
market. However, the right to own and operate an energy network in a specific territory can be 
seen as a market for candidate network operators, if such right is tendered by the authorities. 
Competition for-the-market “may be the  only  option for  creating a competitive incentive” for 
economic operators of natural monopolies.149 

Competition for the hydrogen network “market” does not preclude network regulation – they 
could be combined to ensure networks are allocated to the most suitable operator, providing a 
level playing field and addressing potential competitive advantages of incumbent regulated 
methane network operators or pre-existing hydrogen network operators, if it would be socially 
beneficial. 

Policy makers could consider to tender the hydrogen network investment and operation for a 
determined period of time, refraining from regulating the network afterwards (only re-tendering 
the right to invest in and operate the network at the end of the concession period). If hydrogen 
networks are not further regulated after the tendering of the concession, the only recourse 
available would be general competition policy, potentially making use of the Essential Facilities 
Doctrine. This has a number of disadvantages for hydrogen networks in hydrogen-intensive 
pathways, as discussed in Box 3-7 below. Such an approach would have risks associated with 
auction design - badly designed tenders may for example maximise public revenues from the 
tender, but network operators will recover their additional costs from network users, leading to 
higher tariffs. 

Generally, competition for the market is not seen as a substitute for regulation of an activity with 
natural monopoly characteristics. Network tariff and third-party access regulation are often still 
necessary to avoid the abuse of dominant position by the concessionary.150 Competition for-the-

149 OECD (2019) Global Forum on Competition - Competition for-the-market. Executive Summary - Key findings 
from the discussion held during Session IV of the 18th meeting of the Global Forum on Competition on 5-6 
December 2019. 
150 OECD (2019) Global Forum on Competition – Competition for-the-market. Background note by the 
Secretariat 

53 

 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

market can nonetheless be an interesting complementary approach to introduce an element of 
competition. 

Unbundling type 

Options B-D imply some form and extent of unbundling of the hydrogen network operators. Vertical 
unbundling of the hydrogen network activities from production, trade and supply activities in the 
hydrogen and other energy sectors is considered to be applied to all options. 

Cross-sectoral unbundling of network activities could be achieved through ownership, legal, 
functional and accounting unbundling. Here, functional unbundling is considered only in 
combination with legal unbundling, as a more effective and efficient way to separate network from 
unregulated functions, minimising regulatory costs compared to only functional unbundling. While 
ownership and legal + functional unbundling represent the strongest forms of unbundling, they 
would require additional administrative costs for existing hydrogen system operators. 

There is a possible risk that a significant fall in methane gases demand would incentivise 
incumbent methane network operators to over-invest in hydrogen networks (i.e. ‘gold plate’ them), 
if allowed to, including through repurposing methane pipelines, even where not optimal from the 
social perspective. While repurposing methane networks will be, in hydrogen-intensive pathways, 
an efficient way to facilitate hydrogen development, there will be cases where decommissioning of 
methane pipelines is a more appropriate option from a societal perspective. Accounts unbundling 
between hydrogen and methane networks would not address this moral hazard of methane 
network operators. Even legal unbundling could prove to be insufficient given the 2007 sector 
inquiry found third-party access rules and legal unbundling requirements of the 2nd energy package 
were not sufficient to prevent network operators of discriminating against other network users in 
certain cases.151 

The remaining unbundling option to eliminate the moral hazard for methane network operators to 
over-invest in repurposing existing assets is separate ownership of methane and hydrogen 
networks. However, this option has a number of negative impacts and implications not related to 
the moral hazard of incumbent network operators. Enforcing ownership unbundling for hydrogen 
networks would not have as high administrative costs as for natural gas networks when the 2nd and 
3rd energy packages were introduced but would limit the knowledge transfer from existing methane 
and hydrogen system operators. 

Non-discriminatory and transparent planning, network access and charging can be achieved by less 
strict unbundling requirements coupled with other means. While the moral hazard of incumbent 
methane network operators is a legitimate concern, it should preferably be addressed through 
other regulatory elements. Ownership unbundling can reduce over-investment risks, but this does 
not constitute as such a sufficient reason for enforcing it. 

Some form of H2-CH4 unbundling as required in options B and C would nonetheless facilitate proper 
cost allocation between the two networks, which would be complicated in case Member States 
choose to implement single accounts for combined gas network operators under option D. 
Simplified (i.e. accounts) unbundling requirements between hydrogen and methane networks 
would have a similar effect of facilitating conversion, while improving the transparency of cost 
allocation compared to no account unbundling. 

Methane assets could also be transferred, upon fair compensation based on the residual asset 
value (residual accounting value), to the hydrogen network operator, in case of ownership or legal 
+ functional unbundling. This would involve higher administrative and regulatory costs, to realise 
the transfer and determine the fair residual value but would not restrict ex-ante the development 
of hydrogen networks to incumbent NG network operators due to administrative reasons. It would 
be compatible with the introduction of a competitive element with competition-for-the-market. 

Methane network operators would foreseeably oppose to sell infrastructure assets, or to sell them 
at the residual accounting rather than market value. Property laws could affect the possibility of EU 
provisions to enforce the sale of assets or legal or ownership unbundling of gas networks. The third 
energy package, enforced OU, but offered less intrusive alternatives to pre-existing undertakings 
(the ISO and ITO models).152 Moreover, the energy sector-wide enforcement of unbundling was 

151 Jones (2016) EU Energy Law, Volume 1: The Internal Energy Market 
152 Diathesopoulos (2010) Ownership Unbundling in EU & Legal Problems 

54 

 
 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

based on a thorough sector inquiry and later supported by competition cases which led to further 
divestiture by incumbent operators in certain Member States.153 

Lowe et al. (2007)154 indicates that “the right to property is not an absolute right but must be 
viewed in relation to its social function. Consequently, its exercise may be restricted, provided that 
those restrictions in fact correspond to objectives of general interest pursued by the Community 
and do not constitute a disproportionate and intolerable interference, impairing the very substance 
of the rights guaranteed”. 

Olesiewicz (2015)155 lists a number of criteria that EU energy sector unbundling measures should 
satisfy regarding property rights: 

- 

The EU must have the competence to regulate on energy sector as well as property rights 
allocation matters; 
The measures must be proportional with the expected social benefits; 

- 
-  Owners must be suitably compensated. 

The author argues that the ownership unbundling provisions of the 3rd energy package probably 
satisfied the first two principles, but that it is unclear whether ‘suitable compensation’ can be 
provided merely by the assets sale price (even if case law indicates that sale under the market 
value could still be considered ‘fair’). Again, the existence of the ITO and ISO alternatives 
facilitated the compatibility of the 3rd energy package with national property laws. 

EU provisions imposing ownership or legal unbundling to the hydrogen sector could face a number 
of additional difficulties compared to the 3rd energy package OU provisions. First, there are no 
demonstrated market failures yet, given the incipient development stage of the hydrogen sector 
and the lack of any competition inquiries. Second, demonstrating that ownership or legal horizontal 
unbundling are socially beneficial may be more difficult, as alternatives exist to ensure social 
welfare, such as accounts unbundling and strong planning oversight. This can be further 
complicated as in certain cases there may be synergies in having combined (accounts-unbundled) 
ownership and operation of methane and hydrogen networks. Third, it is unclear whether selling 
assets at the residual accounting value would be considered a ‘fair compensation’, even though the 
RAB model remunerated the depreciation of the assets and the capital cost. The alternative of 
selling assets at market value would be socially unfair, as TSOs would be compensated for 
depreciated regulated assets which would lead to higher hydrogen network tariffs. 

If provisions on ownership or legal unbundling from methane networks were established for the 
hydrogen sector, the risk of legal challenges could be reduced by providing an alternative allowing 
Member States to opt for accounts unbundling, if a cost-benefit analysis demonstrates this option 
would be socially beneficial. In case such a test would have a negative outcome, it would support 
the proportionality of the unbundling measures.  

Exemptions and waivers to unbundling requirements 

In the case of options B-D, private hydrogen network operators existing at the time of entry into 
force of the new regulatory framework, could be exempted (or not) from unbundling requirements 
through an exemption procedure, or waivered automatically. 

As discussed above, in order to regulate on the unbundling of pre-existing hydrogen networks, the 
EU needs to have the competence to regulate on energy and property rights matters, and any 
unbundling provisions need to be proportional to the expected social benefits. There is a strong 
parallel between unbundling provisions in the 3rd energy package and potential new ones for pre-
existing hydrogen network operators. Similar to the 3rd energy package, it can be argued the EU 
does have the competence to act in this new matter, at least for cross-border hydrogen networks 
(as energy is a shared competence between the EU and Member States) and as long as the 
principle of neutrality is respected (that no privatisation or nationalisation of property is 
enforced).156 

The unbundling of private hydrogen networks, and more broadly their regulation, could be 
implemented if this would increase social welfare resulting from 1) the integration of private and 
new hydrogen networks, 2) the elimination of discriminatory treatment of network users (new 

153 Talus (2016) Introduction to EU energy law 
154 Lowe et al (2007) Effective unbundling of energy transmission networks: lessons from the Energy Sector 
Inquiry. Competition Policy Newsletter no. 1 2007 
155 Olesiewicz (2015) Property Law and Free Movement of Capital Limits to the Implementation of the 
Ownership Unbundling in the Energy Sector. Aberdeen Student Law Review vol. 6. 
156 Olesiewicz (2015) Property Law and Free Movement of Capital Limits to the Implementation of the 
Ownership Unbundling in the Energy Sector. Aberdeen Student Law Review vol. 6. 

55 

 
 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

and/or existing), and/or 3) addressing under-investment in private hydrogen networks (due to a 
potential lack of interest from the private operators, or difficulties in acquiring right of way, as 
expropriation based on public interest is in principle not possible. Hence, the proportionality 
principle could be respected even if unbundling is enforced. 

Suitable compensation would need to be provided to pre-existing private hydrogen network owners 
that have property rights. This could possibly be satisfied by the revenues received from the sale of 
the assets at a market price. However, this specific point deserves further attention. 

It must be considered that existing hydrogen networks have limited transport capacity compared to 
the planned future hydrogen networks. For example, the energy content of hydrogen production in 
Germany is equivalent to only 1.5% of the national natural gas consumption in 2018.157 Therefore, 
in countries such as Germany, Belgium and the Netherlands, existing hydrogen networks would, 
without expansion, not provide a significant contribution to large-scale hydrogen deployment. Also, 
although existing private networks have a single supplier, they supply large industrial consumers, 
and therefore the hydrogen transport system owner has not necessarily significant market power. 

In case private hydrogen networks are exempted or waivered from certain regulatory elements 
such as third-party access, measures could be taken to increase transparency, facilitate monitoring 
by competition authorities and reduce costs for posterior regulatory intervention. Such measures 
could include requirements for transparency on supply contracts (e.g. via REMIT), or at least 
accounts unbundling of network activities. 

Furthermore, measures could be put in place to incentivise private hydrogen network operators to 
place their transport activities under a regulated regime. This could be done either by unbundling 
or by selling their network assets to an existing regulated operator. Incentives could include 
streamlined permitting for regulated networks (as some private operators may have difficulties in 
obtaining right of way or providing them preferential access through long-term capacity contracts 
to meet existing or new supply contracts. As the new hydrogen regulation could trigger a faster 
development of the hydrogen market, this could be in the interest of the existing private network 
operators as their primary business is rather hydrogen supply. 

For the case of Germany, Benrath (2019)158 proposes an alternative: the demarcation of legislation 
between energy and feedstock pipelines. In this proposal, existing private hydrogen networks 
would not be covered by the new regulation as they mainly serve to transport hydrogen used as 
feedstock. Future pipelines supplying hydrogen to be used exclusively as feedstock would also not 
be regulated, while pipelines that supply hydrogen as feedstock as well as for energy purposes 
would be considered as energy pipelines and would hence be regulated. The existence of 
unregulated feedstock pipelines could worsen the business case for regulated energy pipelines. 
Moreover, such an approach might lead to a suboptimal grid configuration, as potential economies 
of scale resulting from the sub-additive cost curve of gas pipelines might not be valued.  

Some form of unbundling (at least accounts) should be imposed for new direct pipelines linking 
small groups of hydrogen producers and consumers in options B-D where unbundling is enforced to 
network operators – as these direct lines would constitute transmission or distribution pipelines 
much like the rest of the system, and in order to avoid the proliferation of direct lines which would 
compromise the development of an interconnected system. Direct pipelines could be exempted by 
national regulators from unbundling and other requirements (especially third-party access) for a 
defined period of time (i.e. with a sunset clause) and with the possibility of renewal of the 
exemption (this is not foreseen in the current EU natural gas regulatory framework). A similar 
regulatory test could be applied like for existing private hydrogen network operators, but subject to 
additional conditions such as the refusal or impossibility to connect to the regulated hydrogen 
network, or that this would not unduly affect security of supply, or the regularity, quality and price 
of supplies to other hydrogen users (similar to art. 9 of the current Electricity Directive). 

These provisions are similar to the existing EU natural gas regulatory framework for direct lines, 
except for the potential exemptions foreseen and the right of Member States to refuse to authorise 
a direct line due to public service obligations considerations (the latter does exist in the Electricity 
Directive).159 The direct line provisions and exemptions in the EU natural gas regulatory framework 
are considered to achieve an adequate balance between the rights of suppliers to develop direct 
lines and the broader interests of all system users.   

157 Based on IEA (2020) World energy statistics indicating a natural gas consumption of 813.6 TWhlhv. 
158 Benrath (2019) Applicable law to hydrogen pipelines for energy purposes in Germany. Journal of Energy & 
Natural Resources Law. 
159 Jones (2016) EU Energy Law, Volume 1: The Internal Energy Market 

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Sector integration – Regulatory framework for hydrogen 

3.2.2 Natural gas as a basis for hydrogen network regulation: Unbundling 

The current regime regulating separation of gas infrastructure assets is set out in the Gas Market 
Directive (2009/73/EC). There are three vertical unbundling regimes allowed. Firstly, the option of 
legal unbundling with full separation of asset ownership is the standard option. The two other 
options allow legal and functional unbundling through separation of network assets from the 
system operation function (creating an Independent System Operator, ISO) or through full 
management separation (where the vertically integrated company is mandated to create a 
subsidiary Independent Transmission system Operator, ITO). The ISO and ITO models are only 
possible if the transmission system operator was part of a vertically integrated undertaking at the 
time of entry into force of the Gas Directive. According to a Commission interpretative note, new 
transmission systems will have to follow the ownership unbundling regime160. Reviewing a number 
of studies, Meletiou et al. (2018) indicate that “OU and ISO models are considered more stringent 
unbundling forms when compared to the ITO model”.161 

From the 58 gas transmission system operator certifications, there were, in 2015, 23 operators 
under OU regime, 26 under ITO regime and 6 under ISO regime162. Since the implementation of 
the 3rd energy package, the European Commission has until 2019 issued 139 opinions regarding 
the certification of TSOs. During this period, 4 TSOs changed their unbundling model, including 2 
gas TSOs and one gas interconnector operator. All four changed their regime to the ownership 
unbundling model163. 

Box 3-4 Energinet as a regulated multi-vector operator in Denmark 

The Danish TSO Energinet is ownership unbundled. It combines the activities of electricity and 
gas transmission with that of gas storage and distribution. It took over gas distribution activities 
from DONG Energy as part of government plans to consolidate the gas sector. The government 
plans also included the use of incentive regulation to improve the efficiency of regulated 
companies.164 In 2018 Energinet restructured itself around independent business units, “to 
improve transparency around decision-making and allow the Energinet group to perform its 
many and varied functions in a more focused and efficient way”.165 

The Act on Energinet indicates that the company should undertake electricity and gas 
transmission activities “on the basis of coherent and holistic planning”.166 Energinet’s 2018 
System Plan puts an emphasis on the holistic planning aspect and indicates that the company is 
developing, in cooperation with policymakers, a process for developing multi-annual investment 
plans with increased transparency.167 This includes the approval of the development plans by 
competent authorities.168 

In its PtX Strategic Action plan of 2019,169 Energinet again highlights the need for integrated 
energy infrastructure planning as well for independent hydrogen infrastructure operators. It 
furthermore notes that the Danish regulatory framework does not address whether hydrogen 
transport should be a regulated activity, and does not affirm that Energinet should necessarily be 
tasked with this activity – proposing to collaborate with policymakers in defining the conditions 
which would require third-party access regulation for hydrogen networks. 

160 EC (2010). Interpretative note on unbundling in the electricity directive and the natural gas directive. 
Available at https://ec.europa.eu/energy/sites/ener/files/documents/2010_01_21_the_unbundling_regime.pdf. 
161 Meletiou et al. (2018). Regulatory and ownership determinants of unbundling regime choice for European 
electricity transmission utilities. 
162 EC. List of certification notifications received (2011-2015). Available at 
https://ec.europa.eu/energy/topics/markets-and-consumers/market-legislation/third-energy-package_en 
163 CEER (2019). Implementation of TSO and DSO Unbundling Provisions. Available at: 
https://www.ceer.eu/documents/104400/-/-/f69775aa-613c-78a5-4d96-8fd57e6b77d4. 
164 Energinet (2018). Energy across Borders – Strategy 2018-2020.  
165 Energinet (2018). Energy across Borders – Strategy 2018-2020. 
166 Act on Energinet No. 1384/2004. Consolidated version LBK nr 118 of 06/02/2020. Available on 
https://www.retsinformation.dk/eli/lta/2020/118 
167 Energinet (2018). System Plan 2018– Electricity and Gas in Denmark 
168 Trinomics, LBST, Artelys and E3Modelling (2018). The role of trans-European gas infrastructure in the light 
of the 2050 decarbonization targets. 
169 Energinet (2019). Winds of Change in a Hydrogen Perspective - PtX Strategic Action Plan. 

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Sector integration – Regulatory framework for hydrogen 

These considerations highlight a number of interconnected aspects at play for the regulation of 
energy infrastructures: 

 

 

 

 

The use of incentive-based revenue regulation and sector consolidation to achieve 
efficient investments and operation; 
The need for transparency in electricity and gas transmission, including regarding 
planning processes; 
The importance of integrated network planning across energy sectors, and the potential 
role of regulation in establishing planning requirements; 
The lack of regulation for the hydrogen sector and the current consideration by Member 
States whether and how to regulate it. 

Extending the current regulatory approach to (newly built or converted) hydrogen networks would 
not change the situation for incumbent transmission system operators if the hydrogen networks 
were considered as an extension of the already existing gas (methane and hydrogen) system. Only 
completely new hydrogen transmission systems would have to be subjected to the ownership 
unbundling regime if they were considered separate from the natural gas system. For each 
TSO/NRA, this approach offers the continuation of the freedom to choose the unbundling model 
most suitable to its particular situation.  

This approach would also avoid the transactional cost of adapting to a new regulatory regime and 
possibly enable the transition of established natural gas system operators to hydrogen 
infrastructure. On the other hand, this approach would decrease the transparency of network 
infrastructure management, as it would not allow for distinguishing between natural gas and 
hydrogen networks accounts. 

The Gas Directive contains provisions for the exemption of unbundling requirements for new 
natural gas infrastructure built after the entry into force of the Directive, but not for existing 
natural gas infrastructure. Hence, without further adaptation, the application of this regulatory 
framework to hydrogen would require the unbundling of existing private hydrogen system 
operators. 

Options formulation 

It is assumed that: 

  All currently available unbundling options (OU, ITO, ISO) are sufficiently effective; 
  Cross-sectoral horizontal hydrogen/NG network activities are allowed; 
  Cross-sectoral vertical unbundling is enforced; 
  Only existing gas TSOs that currently operate under one of the functional unbundling 

regulatory models, can keep this model also for hydrogen networks. 

Thus, the central question is the legal status of hydrogen pipelines – are they considered a new 
infrastructure? Or are they an addition to an existing gas network and can currently existing 
natural gas operators build and operate hydrogen networks with their legal status unchanged? If 
hydrogen is included in the definition of gas in the Gas Directive and Regulation, new hydrogen 
infrastructure can be considered as an extension of existing methane networks, and the currently 
existing network companies operating under a functional unbundling regime, might be allowed to 
keep their current ownership structure. A regulatory test could be used to check whether the social 
benefits of such an approach outweigh its costs. In case hydrogen and natural gas are considered 
as separate gases, tenders could be employed to award the networks to the most suitable 
operator, taken into account the competitive advantage of methane network operators. This 
approach is further discussed in Box 3-3 above regarding competition for-the-market.  

58 

 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Table 3-4 Unbundling options for hydrogen based on natural gas regulatory frameworks 

Unbundling 

Option A 

Option B 

Option C 

Hydrogen gas 
definition 

Hydrogen and natural gas are 
separate gases 

Hydrogen is a separate gas 

Methane gases and hydrogen 
are defined as a single gas 

Hydrogen 
networks are 
new networks? 

Unbundling from 
methane 
networks 

Advantages 

Disadvantages / 
risks 

New 

May be considered as 
extension of methane grid 

Extension of methane grid 

Ownership unbundling 
obligatory 

Legal+functional / accounts / 
none 

None / accounts 

 Improved level playing field 
for entrants 
 May not leverage knowledge 
of NG TSOs. 

 Facilitates conversion of NG 
infrastructure 
 Allows entrants 

 Facilitates conversion of NG 
infrastructure 
 Reduced administrative 
burden 

 Conversion of NG 
infrastructure entails 
administrative burden and 
potential compensation 
 Increased transactional 
costs of adapting to new 
regulatory regime 

 Incumbent methane 
network operators have 
competitive advantage. 

Mitigation 
measures 

 Tender concessions / 
require a positive CBA for 
awarding operation to NG 
TSO 

 Tender concessions / 
require a positive CBA for 
awarding operation to NG 
TSO 

 Entry of new network 
operators very difficult 
 Complicates cost allocation 
between hydrogen and NG 
infrastructure. 

 Require accounting 
unbundling. 
 Require a positive CBA for 
authorising a combined gas 
TSO 

In Germany, the gas TSOs as well as other energy associations have recently proposed to change 
the national legislation so that current natural gas network operators are able to also operate 
hydrogen networks with accounts unbundling.170 

In the Netherlands, a study on the regulatory framework for hydrogen networks indicates that if 
current natural gas network operators were to be assigned a mandate to develop and operate 
hydrogen networks, existing private hydrogen operators could wish to devolve their networks to 
the regulated operators as their core busines is hydrogen supply rather than network operation. 
Nonetheless, specific exemptions could be foreseen from unbundling, third party access and tariff 
regulation.171 

Box 3-5 Emergent and isolated markets provisions in the Gas Directive 

Article 49 of the 2009 Gas Directive includes a number of provisions related to emergent and 
isolated markets. Emergent markets may exist in ‘Member States in which the first commercial 
supply of its first long-term natural gas supply contract was made not more than 10 years 
earlier’ (art. 2(31)). Isolated markets are ‘Member States not directly connected to the 
interconnected system of any other Member State and having only one main external supplier 
[…]. A supply undertaking having a market share of more than 75 % shall be considered to be a 
main supplier’ (art. 49(1)).  

The provisions include derogations on unbundling of TSOs, direct lines provisions, and DSO 
obligations (including unbundling), which expire when Member States cease to qualify to the 
conditions above. 

The emergent and isolated markets provisions may be an interesting solution for making the 
applicability of certain regulatory elements such as unbundling and third-party access conditional 
to the interconnection of national hydrogen systems. This would provide clarity for Member 
States on the requirements once their hydrogen systems develop, without imposing restrictions 
to local hydrogen clusters. 

The application of the derogation provisions to the hydrogen sector would at least need some 
adaptations, e.g. as the more domestic and decentralised nature of hydrogen production would 
reduce (external) suppliers’ dependency and thus make it more difficult to qualify to the 75% 
threshold, while multiple national hydrogen systems could remain isolated for a long period. 

170 FNBGas et al. (2020) Auf dem Weg zu einem wettbewerblichen Wasserstoffmarkt Gemeinsamer 
Verbändevorschlag zur Anpassung des Rechtsrahmens für Wasserstoffnetze 
171 Ecorys and TNO (2018). Waterstoftransport – verkenning marktordeningsalternatieven 

59 

 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Third-party access (TPA) rules aim to guarantee to network users non-discriminatory access to the 
transmission and distribution network, by forbidding network operators to refuse or favour access 
to certain network users, without reasonable technical or economic justification. This includes the 
obligation to allow for the non-discriminatory connection of users to the network. 

Third-party access rules are intrinsically linked to unbundling requirements, with both having the 
ultimate goal of facilitating fair competition amongst network users. Third-party access rules and 
functional vertical unbundling are generally considered insufficient to guarantee that incumbent 
network operators do not discriminate other network users versus their own or affiliated 
undertakings. The 2007 sector inquiry found that the third-party access and legal unbundling 
requirements in the 2nd energy package were insufficient to ensure non-discriminatory third-party 
access.172 

Third-party access is in the current EU legislation not required for all energy networks. Existing 
private energy networks (such as existing hydrogen networks) are not regulated, and regulators 
may furthermore provide (partial) exemptions to natural gas direct lines (connecting one producer 
to one or a group of specific customers) or to merchant interconnectors, due to considerations on 
the economic feasibility of the investment. 

Under regulated third-party access, infrastructure operators are required to provide non-
discriminatory access to users on the basis of published terms and conditions, including tariffs, set 
or approved by the regulator. Negotiated third-party access constitutes an alternative to regulated 
third-party access; under this regime the infrastructure operator and users negotiate in good faith 
the access to the infrastructure, with terms and conditions being published ex-post or not 
published. 

In the case of transmission networks, third-party access may require, for specific corridors and 
cross-system interconnection points, the establishment of rules on booking (i.e. reservation) and 
nomination (i.e. actual use) of the transport capacity: so-called capacity allocation rules. 
Additionally, it is necessary to define rules for the management of eventual physical or contractual 
congestion which may take place in such corridors and interconnection points. Capacity allocation 
rules are not necessary within entry-exit systems which should theoretically be characterised by 
the absence of internal (structural) congestion, although congestion management rules are still 
necessary for transitory, non-structural congestion which may take place. Capacity allocation and 
congestion management are described in more detail below. 

Network access and dedicated hydrogen networks 

Network access for new dedicated hydrogen networks could range from a fully regulated to an 
unregulated approach. The ultimate criterion to establish the adequate level of third-party access 
regulation is that the system benefits should outweigh the costs. Whichever the choice, TPA 
requirements (or their absence) have a direct impact on the business case of network investments 
since they determine how capacity should be contracted to network users, and would have to be 
defined early on as they would affect hydrogen networks of all scales, including initial hydrogen 
clusters. 

As hydrogen networks are expected to constitute a natural monopoly, TPA requirements are 
essential to enable the development of a liquid hydrogen market, with multiple network users 
having access to hydrogen networks as a pre-condition to participate in the market. This would 
need to be combined with effective vertical unbundling to assure that network operators do not 
discriminate other network users in favour of their own or affiliated undertakings. 

As a trade-off for being granted a factual or legal monopoly in a given area of operation, an 
obligation could be imposed to hydrogen network operators to connect all hydrogen network users 
that request so, in addition to providing access at tariffs that reflect their actual costs and a 
regulated market-based margin to remunerate their equity. This would provide increased certainty 
for the migration of users from natural gas networks and increase the protection of end-users 
connected to the distribution grid, which would have less available alternative options than large 
industrial consumers. Therefore, such a legal obligation to connect all users at their request could 
be considered depending on the expected uptake of hydrogen. 

As it is expected that long-term hydrogen supply agreements may be a main driver of investments 
in production capacity and of the shift of end-users to hydrogen, third-party access to networks 
should be coupled to some degree with long-term network capacity contracts. Conversely, such 

172 Jones (2016) EU Energy Law, Volume 1: The Internal Energy Market 

60 

 
 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

long-term supply contracts would signal demand for network transport capacity and thus minimise 
the risk of stranded hydrogen network investments. This must be outweighed by the (low) risk of 
foreclosure of capacity and the impact on the development of a liquid hydrogen market. A 
mechanism similar to the current incremental capacity procedures in the CAM network code173 
could be employed to provide long-term capacity contracts for new or repurposed hydrogen 
networks (see section 3.7 for further details). 

The existing private long-distance hydrogen networks supplying industrial customers have been 
developed without regulated third-party access, with hydrogen suppliers and consumers freely 
agreeing integrated long-term supply and transport tariffs. No evidence was indicated by 
stakeholders of abuse of the position of hydrogen suppliers in the past. However, the suitability of 
such an approach needs to consider the profile of the customers, exclusively composed of large 
industrial consumers, and the size and capacity of the networks, with are extremely limited 
compared to the regulated electricity and gas networks. 

Exemptions could be foreseen from regulated third-party access for a number of cases, including 
for previously existing private hydrogen systems (when it is demonstrated that the social benefits 
of TPA rules would not outweigh its social costs. Some private operators could for commercial or 
economic reasons be interested to provide third-party access (with unbundling) to their networks, 
or even to devolve their networks to another party (further analysed in section 3.2). Potential 
exemptions to TPA are further detailed in the next section. 

Priority connection to and use of the network could also be foreseen for renewable and/or low-
carbon hydrogen, in order to incentivise them and foster the substitution of fossil fuels or hydrogen 
with a high-carbon footprint. This has been proposed by a number of studies to facilitate the 
development of dedicated hydrogen systems, and there are precedents in the electricity and 
natural gas sectors.174 The impact of such a measure would however be very limited, as grid 
congestion is not expected to be a major issue. 

Stakeholders’ opinions 

As noted in the unbundling sub-section above, stakeholders, including natural gas network 
operators and market actors, overwhelmingly support non-discriminatory third-party access (and 
associated vertical unbundling) for new hydrogen networks. A stakeholder highlighted that such 
measures would be necessary at the European level and in the short-term (three to five years) in 
order to provide the investment certainty necessary for the development of hydrogen networks.  

Some gas infrastructure operators argued that regulation at the EU level should allow both 
regulated and negotiated TPA for hydrogen infrastructure. The principles of unbundling, non-
discrimination, transparency and fair competition should always be met. A network operator 
proposed that initially a single operator or at least mutually controlled operators (at the national 
level) with uniform non-discriminatory access and transport conditions would be necessary, with 
later on uniform tariff setting and socialisation of costs among users of the different network 
clusters being an option – i.e. some conditions can be set from the start, but further measures 
such as regulated TPA and tariffs should be implemented at a later stage. In contrast, another 
natural gas network operator affirmed that regulated TPA should be the default approach to 
networks. 

A network operator indicated that the lack of regulated TPA for future hydrogen networks would 
make it impossible for grid operators to develop, as network growth would lead to increasing 
complexity of need for negotiating terms and tariffs with each new network user. Lack of regulated 
TPA would at least slow down network development below the speed required for the energy 
transition. 

One market actor indicated that, similar to closed natural gas distribution systems and direct lines, 
upstream (i.e. gas production-related) infrastructure and some new infrastructure (interconnectors, 
storage and LNG terminals) will require some flexibility for regulated TPA in specific cases. 
Although favouring the consideration of exemptions, two natural gas network operators indicated 
that the mere fact they already exist should not automatically lead to the provision of waivers to 
the current hydrogen system operators. Generally, gas TSOs indicate that, while requirements such 
as for unbundling and TPA may be waivered or exempted for direct pipelines, they should be 
enforced once additional consumers are connected to the network. 

173 Where network operators develop new capacity based on a market demand assessment (e.g. open season) 
and then firm commitments from market parties 
174 CEER (2018) Status Review of Renewable Support Schemes in Europe for 2016 and 2017 
EurObserv’ER (2017) Biogas Barometer 

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Sector integration – Regulatory framework for hydrogen 

Another stakeholder raised the option of requiring TPA only for specific groups of network users, 
such as hydrogen producers and industrial consumers, which would most likely be the early 
adopters of hydrogen. But the stakeholder added that this option would be discriminatory and thus 
easily be contested in court by other potential network user groups. A natural gas network operator 
supported the consideration of exemptions, but indicated that in the long-term, all hydrogen 
networks should be regulated. Another stakeholder was of the opinion that existing hydrogen 
networks are mainly used to supply feedstock for the chemical industry, and that market power 
issues should remain to be managed by the competition authorities and by guaranteeing that entry 
barriers are removed by offering non-discriminatory access. 

The opinions regarding the treatment of existing hydrogen networks are not consensual. A 
stakeholder commented that, while exemptions could be considered, existing customers should 
have the right to terminate their supply contract, after a transition period, and migrate to another 
energy network. One natural gas network operator indicated that minimum requirements on 
unbundling, TPA and transparency should also be imposed on existing private hydrogen networks, 
while market actors opposed in general the imposition of legal requirements on existing hydrogen 
infrastructure. A gas TSO supported the application of a sunset clause to exemptions to private 
network operators, noting that it would have various effects on both existing and new hydrogen 
network operators, which need to be better understood. Some energy exchange operators also 
supported a transition pathway for initial exemptions to existing private hydrogen network 
operators. Private hydrogen network operators, on the other hand, highlighted the need not to put 
existing long-term commercial contracts at risk and not to impair existing assets. 

3.3.1 Greenfield hydrogen regulation: Network access 

The options developed for the unbundling requirements for hydrogen networks consider two 
dimensions: 

 

 

The need for regulating third-party access to some extent; 

The type of third-party access regulation. 

Considering these dimensions, the following are the main options, as detailed in Table 3-5: 

  Option A: No harmonised TPA requirements at the EU level; 

  Option B: Choice for Member States between negotiated TPA (nTPA) and regulated TPA 

(rTPA); 

  Option C: Obligatory application of regulated TPA networks in all Member States. 

TPA requirements would only apply to regulated networks, while other operators could be 
exempted or subject to only nTPA. Other specific exemptions on TPA requirements could be 
granted and are detailed below. 

Table 3-5 TPA options for hydrogen / combined network operators 

Option A 

Option B 

Option C 

Options 

No harmonised TPA 
requirements 

Applies to  

- 

nTPA / rTPA choice 

Obligatory rTPA 

Hydrogen / combined network 
operators 

Hydrogen / combined network 
operators 

Advantages 

 Low regulatory cost related 
to EU legislation 
 Flexibility for national/local 
conditions 

 Increased transparency 
 Non-discrimination of users 
 Flexibility for national/local 
conditions 

Disadvantages / 
risks 

 Potential for discrimination 
and market power 
 Potential for cross-border 
distortions 

Mitigation 
measures 

 Competition law 
enforcement 

 Potential for cross-border 
distortions 

 Regulatory test for nTPA 
choice 
 Transparency requirements 
on terms & conditions and 
ex-post negotiated tariffs 
 Sunset clause (expiration 
date) for nTPA 

62 

 Increased transparency 
 Non-discrimination of users 
 No competition distortion 
between nTPA and rTPA 
networks 

 Increased regulatory cost 
 Potential impact on business 
case 

 Provide rTPA exemptions 

 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Box 3-6 Regulatory tests for nTPA/rTPA regimes 

As indicated in chapter 2, regulatory tests are broadly viewed as an appropriate way to decide 
whether and when regulation of hydrogen networks should be introduced. If Member States are 
allowed to choose between negotiated and regulated TPA for hydrogen networks as proposed in 
option B, harmonised principles should be set at the EU level for these regulatory tests. 

Similar principles can be applied to defining access to existing private hydrogen networks, to 
new networks as well as in eventual exemption procedures to the chosen access regime. 
Potentially, different access regimes (nTPA/rTPA) could be foreseen for existing and new 
hydrogen networks – and even different regimes for different categories of new networks (direct 
pipelines, closed distribution systems, etc). However, the choice of different regimes will need to 
be duly justified and the interaction and risk for unequal competition between the networks 
assessed. 

Different access regimes could in principle be imposed to the same network, with part of the 
transport capacity being offered under a regulated TPA regime. However, regimes should not 
discriminate between types of network users. 

Based on the analysis of this study as well as the criteria for decision on TPA regimes for gas 
storage,175 the following minimum regulatory test criteria are suggested for hydrogen pipelines: 
  Effective competition between networks and alternatives: are there other options 

for hydrogen transport (through networks or other modes – by rail, trucks, ships) or is 
competition by on-site hydrogen production feasible? 

  Effective network access: is/will a significant capacity of the network (be) booked 

with long-term contracts without non-discriminatory procedures? 

  Upstream or downstream concentration: is/will transport capacity be booked by a 

restricted number of network users? 

  Barriers to entry: are there economic or technical barriers to the development of new 
hydrogen networks, alternative transport modes or on-site hydrogen production? For 
example, a planning process which is discriminatory and does not consider alternatives 
to network development; 

  Relevance of repurposing of methane pipelines: does the potential repurposing of 
methane pipelines form barriers to investments in new pipelines, and if so, does the 
regulatory regime provide non-discriminatory rules for repurposing? Or are only 
incumbent methane TSOs allowed to repurpose their methane pipelines (i.e. they cannot 
be transferred to other parties)?  

Both regulated and negotiated TPA would require that network operators provide non-
discriminatory access to network users, based on transparent criteria and processes. Regulated 
third-party access would involve the definition or approval of network tariffs by the regulator. 
Negotiated TPA could be chosen by Member States based on a regulatory test, and would need to 
impose a number of requirements:176 

 

Publication of terms & conditions for access, such as ex-ante publication of standard 
contracts, as well as the available capacity; 
Transparency requirements for nTPA with the ex-post publication of the negotiated tariffs; 

 
  Market-based procedures for allocating capacity, such as open seasons or auctions; 
  Use-it-or-lose-it and other mechanisms to manage congestion (addressed in the CACM 

section); 

  At least legal unbundling from other energy infrastructure activities (addressed in section 

3.2). 

Moreover, a number of additional requirements to nTPA could be considered, if deemed necessary 
to guarantee non-discriminatory access to the network, such as to: 

Establish a cap on the capacity share allocated to dominant downstream users; 

 
  Sunset clause (expiration date) for nTPA or at least the test of market conditions to re-

confirm the nTPA regime. 

Refusal of connection to or use of the network (including curtailment) should be allowed only in 
case of proven lack of network capacity. Moreover, the regulatory framework could foresee 
mechanisms to expand network capacity to accommodate new network users, as long as this is 

175 European Commission (2010). Interpretative Note on Directive 2009/73/EC Concerning Common Rules for 
the Internal Market in Natural Gas 
176 Some of the suggestions are derived from: Trinomics, REKK & Enquidity (2020). Study on Gas market 
upgrading and modernisation – Regulatory framework for LNG terminals. 
Frontier Economics (2020). Modernisation of the regulatory framework for LNG terminals – A report for GATE 
terminal. 

63 

 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

technically and economically feasible. Member States could decide on whether connection costs 
should be recovered from the concerned users through specific connection fees and/or (partly) 
through the general network access tariffs. 

Regulated TPA would be suitable where a fast upscaling of the hydrogen system is expected to take 
place. In such cases, it is unlikely that, in the absence of regulated TPA, network operators would 
be able to negotiate and provide access to a significant number of new users in time. Access 
agreements with existing users would complicate the definition of available capacity and tariffs for 
new users, slowing down their connection. Network planning and investment would also be 
significantly more complex, especially in the absence of a network development plan based on 
policy objectives for hydrogen deployment.  

Box 3-7 The essential facilities doctrine and its application to hydrogen networks 

An essential facility is a “facility or infrastructure which is necessary for reaching customers 
and/or enabling competitors to carry on their business. A facility is essential if its duplication is 
impossible or extremely difficult due to physical, geographical, legal or economic constraints”.177  

The application of the essential facilities doctrine (EFD) is based on Article 102 (on abuse of 
dominant position) of the Treaty on the Functioning of the EU (TFEU) and on competition case 
law. In the EU, an operator of an essential facility may be obliged to enter into an agreement 
with competitors regarding access to the facility if “(i) refusing to do so could remove all 
competition from the market; (ii) the product, such as access to infrastructure, is necessary for 
the business in question; and (iii) in practice the product could not be replaced by another” as 
well as if (iv) there is no objective justification for refusing access. The EFD has been applied not 
only to electricity and natural gas infrastructure but also others such as railways and ports.178 

Electricity and natural gas infrastructure are traditional examples of essential facilities. The EFD 
could be employed to guarantee third-party access to dedicated hydrogen networks, if those 
were also deemed to be essential facilities. In Germany, existing hydrogen networks must 
already observe the Act against Restraints of Competition (Gesetz gegen 
Wettbewerbsbeschränkungen, GWB) antitrust regulations.179 Section 19(2) no.4 of the GWB 
classifies refusal by a dominant company to grant another company access to its own network as 
abusive behaviour, unless “the dominant company proves that the shared use is not possible or 
unreasonable for operational or other reasons”. 

Competition law in general and the EFD in particular can be important complements to sector-
specific regulation, as has been demonstrated in the EU electricity and natural gas as well as 
other sectors.180 However, the use of competition law to address eventual market failures in the 
hydrogen sector can demand significant resources from the competition regulator, face 
resistance from market participants which slows down sector inquiries, be complicated by 
information asymmetry, and last but not least may fail to provide the regulatory certainty 
necessary for investments, given the possibility for eventual market inquiries and ex-post 
regulation of the sector.181 

Exemptions and waivers to third-party access requirements 

In the case of options A-C, private hydrogen network operators existing at the time of entry into 
force of the new regulatory framework could be exempted (or not) from TPA. TPA requirement 
exemptions for pre-existing operators should be allowed only when it is demonstrated that the 
social benefits of TPA rules would not outweigh its social costs. This could be the case when for 
example the residual available transport capacity of a private pipeline is rather small and could not 
make a relevant contribution to the overall hydrogen system. A market test could be conducted to 
identify the interest of third-parties in accessing the pre-existing network, or absence of such 
interest. Considerations similar to for unbundling exemptions apply (see section 3.2), including that 
incentives could be given for pre-existing operators to provide third-party access. TPA 
requirements could also be phased in gradually, entering into force only once existing supply 
contracts expire. 

New direct pipelines between one producer and some individual hydrogen consumers could be 
exempted from TPA requirements, possibly for a defined period of time (i.e. with a sunset clause). 

177 DG COMP (2002) Glossary of terms used in EU competition policy – antitrust and control of concentrations 
178 Talus (2016) Introduction to Eu Energy Law 
179 https://www.gesetze-im-internet.de/gwb/BJNR252110998.html 
180 Talus (2016) Introduction to Eu Energy Law; Tapia et al. (2013). The Regulation/Competition Interaction. 
Handbook on European Competition Law-Substantive Aspects 
181 Ecorys and TNO (2018). Waterstoftransport – verkenning marktordeningsalternatieven; commissioned by 
Dutch Ministry for the Economy and Climate 

64 

 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

A similar regulatory test could be applied as for existing private hydrogen network operators. 
However, as indicated in section 3.2, direct line provisions and exemptions in the EU natural gas 
regulatory framework are considered to achieve an adequate balance between the rights of 
suppliers to develop direct lines and the broader interests of all system users. Exemptions to TPA 
rules should be applied sparingly and only after a regulatory test. 

Closed distribution systems could also be exempted from TPA. A similar definition for closed 
distribution systems as in the art. 28(1) of the Gas Directive could be employed, i.e. ‘for specific 
technical or safety reasons, the operations or the production process of the users of that system 
are integrated’ or the system ‘distributes gas primarily to the owner or operator of the system or to 
their related undertakings’. Closed distribution systems developed with significant public subsidies 
could be required to provide TPA, and only exempted after a regulatory test similar to new direct 
lines.  

Refurbished natural gas pipelines should in principle not be able to apply for an exemption from 
TPA, in order to ensure that the economic advantages of using existing assets benefit to the 
network users and facilitate the deployment of hydrogen.  

3.3.2 Natural gas as a basis for hydrogen network regulation: Network access 

The non-discriminatory third party access has in principle to be allowed in all gas networks, but 
exemptions might be granted under the conditions set out in the Article 30 of the Regulation on the 
Conditions of Access to Natural Gas Infrastructure (2009/715/EC) and Article 36 of the Gas Market 
Directive. The current regulatory framework thus offers a degree of freedom not to apply TPA rules 
on interconnectors, LNG and storage facilities (new, of increased capacity or modified) that: 
  Enable the connection of new sources of gas supply, or enhance gas competition and 

security of supply; and 

  Entail high level or risks that would otherwise prevent the realisation of such project; and 

 

The exemption does not negatively affect competition, the internal gas market or the gas 
system. 

The limitation of the possibility of exemptions only to new interconnectors, LNG and storage 
facilities means that “national” hydrogen transport pipelines would not be eligible for exemption 
from TPA requirements. Exemptions could be used however to interconnect these systems, if 
needed to improve the business case of the project. 

Table 3-6 Network access options for hydrogen based on natural gas regulatory 
frameworks 

Network 
access 

Option 

Option A 

Option B 

Network TPA requirements, exemptions 
and waivers apply to hydrogen systems 

Network TPA requirements apply to 
hydrogen systems, with exemption to 
existing networks 

  Guarantees effective TPA for future 

Advantages 

  Guarantees effective TPA for existing 

hydrogen networks 

and future hydrogen networks 

  Provides regulatory stability to existing 

hydrogen networks 

Disadvantages / 
risks 

  Exemptions limited to interconnectors, 

  TPA for some existing hydrogen 

storage, LNG/LH2 

networks may be socially optimal 

Mitigation 
measures 

  TPA requirements for pre-existing 

networks enter into force only once 
long-term supply contracts expire 

  Regulatory test for granting exemption 

or for imposing TPA to existing 
hydrogen network 

  Provide incentives for existing networks 

offering regulated TPA 

Due to the specific characteristics of energy networks highlighted in chapter 2, the revenue 
regulation of TSOs/DSOs is usually centred on the use of a regulated asset base (RAB). Hence, the 
revenue of network operators is determined through the building blocks of operational costs 
(related to O&M and required system services), depreciation of the RAB (allowing to recover the 
investments) and capital remuneration of the RAB (i.e. return on investments).182 Figure 3-3 

182 ECA (2018) Consultant report for ACER - Methodologies and parameters used to determine the allowed or 
target revenue of gas transmission system operators (TSOs) 

65 

 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

further details the determination of the allowed / target revenue based on these building blocks 
and associated parameters. 

The regulatory framework should incentivise network operators to take socially-optimal decisions 
regarding the planning, investment and operation of the system and physical assets,183 while 
guaranteeing the long-term economic security of the asset owners/operators. Regulators as well as 
policy makers have an important role in guaranteeing that these two objectives are met, as they 
are critical to providing long-term certainty for network operators to take decisions which are 
aligned to energy policy and decarbonisation strategies, thus facilitating the energy transition and 
reducing the risks of stranded investments.184 

As discussed in the network charging section, a number of principles guide the design of tariffs 
which serve to recover the allowed revenues of network operators, including that of cost 
reflectivity. Cost reflectivity implies that there should not be cross-subsidisation between network 
users, i.e. tariffs should reflect the actual network costs caused by each network user (reflecting 
also eventual system externalities). 

Figure 3-3 Regulation of the allowed / target revenues of network operators185 

Box 3-8 CEER’s note on stranded assets in distribution networks186 

In July 2020 CEER published a document on stranded assets in distribution networks. Noting 
that there is not a clear and harmonised definition of stranded assets in national regulatory 
frameworks, CEER indicates that “regulated gas or electricity assets can be considered to be 
stranded when it is expected that regulated companies, as owners of those assets, cannot 
recover their efficient investment costs under the conditions for allowed revenues given the 
changes between the current and expected environment. One of the main reasons for such a 
situation is underutilisation of assets, due to low demand, technical/environmental constraints, 
or policy decisions, among others”. 

Stranded assets could lead to an increase in tariffs, the need for subsidies, and ultimately to the 
decommissioning of assets. Responding to a CEER survey, most NRAs indicated that stranded 
assets are not a problem yet, with only a few cases identified and with varying causes. 

The NRAs identify a number of risk mitigation measures for stranded assets, namely: 

183 These functions may not be assigned to the same organisation, especially that of planning and/or of system 
operation (which may be assigned to an ISO), as discussed above. 
184 Trinomics, LBST and E3-M (2019) Impact of the use of the biomethane and hydrogen potential on trans-
European infrastructure 
185 Adapted from ACER (2018) Report on the methodologies and parameters used to determine the allowed or 
target revenue of gas transmission system operators 
186 Available at https://www.ceer.eu/documents/104400/-/-/cbe00257-ab09-c1b2-91bf-b6081032f322 

66 

O&MInvestmentsRAB / assets accounting valueForecasted cost of serviceAllowed or target revenuesCost of capitalDepreciationDepreciation periodWACCInflationEfficiency targetSystem servicesSystem costs recovered other  than through network tariffsResidual system costsNetwork tariffsNRA assessmentTransfers from/to electricity and natural gas infrastructureThird-party contributions(e.g. subsidies)Third-party contributions excluded from RAB 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

 

Incentives for efficient investments; 

  Alternative use for the grids; 

  Change in depreciation policies and adjustments to the cost of capital. 

At present, most NRAs are involved to some extent in the planning and development of 
distribution networks. They also examine and confirm the assessment of project demand 
volumes by the regulated network operators. 

Hence, NRAs play some role in the development of distribution network development plans 
including in the setting of projected demand volumes, and have a number of instruments to 
incentivise efficient investments by the DSOs. 

It must be noted that most instruments, except the re-purposing of networks, should be 
adequately applied regardless of the risks of stranded investments – i.e. incentives for efficient 
investments as well as adequate depreciation policies and remuneration of capital should be in 
place. 

Revenue regulation and dedicated hydrogen networks 

Regulating the revenues of network operators is a complex task which needs to consider holistically 
all the building blocks and parameters, so that decisions of network operators are socially optimal, 
while providing reasonable remuneration of their capital. Inefficient regulatory frameworks can lead 
to structural over-recovery (i.e. excessive profits) or under-recovery (i.e. revenue deficits) of the 
cost of service, through risks such as: 187 

 

Lack of robust planning scenarios; 

  Capex bias / gold-plating; 

 

Inadequate asset depreciation rules; 

  Misestimation of the WACC; 

 

 

 

 

Inadequate economic efficiency incentives (such as the x-factor); 

Inadequate re-evaluation of the RAB; 

Incorrect remuneration of working capital, assets under construction or leased assets; 

Inclusion of third-party contributions (e.g. EU grants) to the RAB. 

Therefore, revenue regulation is directly related to the transparent, non-discriminatory network 
planning and investments based on scenarios. In the case of hydrogen, scenarios reflecting energy 
policy targets (ideally approved by policy makers) will be particularly important to reduce risks to 
network operators of not being able to recover the incurred cost of service. 

In principle regulated hydrogen network operators should be able to source funds from the market 
(through equity, loans or bonds) at lower interest rates than non-regulated network operators, 
thanks to a lower risk premium. Hence, the regulation of hydrogen networks would lead to a lower 
tariff level to network users. However, although regulation would likely lead to a lower cost of 
capital, the important investments needed for the deployment of hydrogen networks could still lead 
to a higher cost of capital than for electricity and natural gas network operators, due to the 
perception of increased risk arising from the roll-out of infrastructure in a developing market 
and/or to higher leverage ratios of hydrogen network operators. 

Significant innovation will still be required in the technologies for the roll-out of hydrogen systems 
(not only regarding production infrastructure, but also transmission/distribution and end-use 
equipment and appliances). Hence, while efficiency considerations will still remain relevant for 
hydrogen TSOs/DSOs, the use of efficiency incentives such as an x-factor might be less relevant 
than the consideration of innovation incentives in the revenue regulatory framework. Otherwise, if 
network operators are not able to recover the costs of their R&I programs, the feasibility of 
developing hydrogen networks could be threatened, and lead to delayed implementation and/or 
higher costs in the long run. 

The revenue regulation of hydrogen network operators will also be influenced by the charging 
methods applied to network users concerning two specific aspects at least: the impact of tariff 
levels on the connection of new users to hydrogen networks (and the disconnection of users from 
methane networks), and cost-reflectivity to users in electricity, methane and hydrogen systems.  

187 Trinomics et al. (2020). Energy costs, taxes and the impact of government interventions on investments. 
Final report – network costs. 

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Sector integration – Regulatory framework for hydrogen 

First, high tariffs could disincentivise potential hydrogen users from connecting to the network. As 
indicated in the network charging section, high initial investments should not necessarily translate 
in high grid tariffs for first movers, as late-comers would also benefit from the investments. Also, 
new users should not be penalised for shifting to renewable or low-carbon hydrogen and hence 
contributing to energy and climate policy objectives. On the other hand, methane users might face 
increasing network tariffs as early adopters migrate to hydrogen and thus leave a smaller pool of 
remaining methane network users to bear the cost of service, which may still include a significant 
non-depreciated RAB (unless a large part of the non-depreciated RAB can be repurposed for 
hydrogen use). The potential decommissioning of non-depreciated methane infrastructure would 
exacerbate this issue, as network operators may claim a compensation for the residual asset value, 
possibly leading to a sharp increase in the tariff levels if the compensation is not borne by 
taxpayers. 

Second, due to the pursuit of cost-reflectivity in electricity and gas network tariffs and the 
avoidance of cross-subsidisation, there is generally no monetary transfer between the two sectors. 
However, as the roll-out of hydrogen networks will contribute to the flexibility of the electricity 
system and facilitate the decarbonisation of the gas system, intersectoral monetary transfers 
enabling hydrogen network operators to (partly) finance the required investments in networks, 
might in some cases be cost-reflective and thus not constitute (cross-)subsidisation.  

Such transfers would only be justified if the positive externalities resulting from hydrogen 
deployment are not properly internalised through other mechanisms, for example via carbon prices 
or taxes or prices paid for flexibility and security of electricity supply provided by conversion 
technologies such as electrolysers or hydrogen-based power generation. 

Due to some specific factors, the positive externalities of hydrogen deployment enabled by specific 
networks may not be fully internalised. First, investment in dedicated hydrogen networks will be 
lumpy, i.e. the network capacity will be discrete and over-dimensioned, in order to value the 
economies resulting from the sub-additive cost curves of pipelines and the repurposing of methane 
pipelines. Second, revenues of technologies coupling the hydrogen to the electricity and methane 
systems are mainly determined by the short-run marginal costs in the different electricity and 
methane systems, which may offer an adequate remuneration for flexibility but not for security of 
supply, as the benefits of hydrogen deployment resulting from reduced dependence of energy 
imports and enhanced diversification of sources and technologies are not reflected in the market 
prices. Finally, while electricity generation is part of the ETS, fossil fuels’ consumption by non ETS 
end-users is not subject to a similar carbon tax, which hinders the shift from fossil energy to 
renewable or low-carbon electricity and hydrogen.  

The value of non-internalised externalities such as increased system reliability and security of 
supply could be paid by electricity system users, while environmental positive externalities could be 
better borne by taxpayers (potentially recovered by a carbon tax on fossil fuel consumption by 
non-ETS end-users). One of the biggest challenges is correctly quantifying these non-internalised 
externalities and achieving a transparent re-allocation of costs with objective criteria. 

Stakeholders’ opinions 

Natural gas network operators and market parties in general support that NRAs should allow to 
include the efficiently-incurred costs to build dedicated hydrogen infrastructure (by new 
investments or conversion of methane infrastructure) into the network RAB. While natural gas 
network operators generally support the creation of combined gas network operators covering both 
methane and hydrogen, market parties do not have an established opinion on whether the RAB for 
hydrogen and methane assets should be separated, although specific actors do support the 
separation of accounts (but not necessarily ownership or legal/functional unbundling).  

One national regulator indicated that while a similar approach to revenue regulation as for natural 
gas could be used, aspects like the applicability of benchmarks and asset depreciation periods 
might not be the same. In the transition phase, a simplified approach could be desirable, without 
applying all elements of the natural gas regulatory framework. 

Two stakeholders specifically supported the possibility for hydrogen projects to apply for EU 
investment funding, such as through being eligible for PCI status and hence having access to CEF 
funding. 

Regulators highlighted that a regulated revenue model based on the RAB allows to depreciate 
investment costs over a long time period, leading to lower annual costs for network users. A 
network operator highlighted that the roll-out of hydrogen networks will be different across 
Member States, but that the general principle of favouring conversion of methane networks instead 
of decommissioning where efficient should be followed in order to reduce overall costs to network 

68 

 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

users. It noted also that incentives to end-users will be necessary to adapt or change equipment 
and appliances. 

Finally, a stakeholder indicated that it must be ensured that subsidies to the hydrogen sector do 
not undermine market signals for energy efficiency and electrification of end-uses. 

3.4.1 Greenfield hydrogen regulation: Revenue regulation 

Network cost re-allocation 

The options detailed in the table below addresses the issue of potential re-allocation of the cost of 
hydrogen, methane and electricity networks. Appropriate revenue regulation should aim to avoid 
investments by network operators which would lead to a lock-in in unsustainable pathways and/or 
to stranded assets. Thus, regulation that mandates an objective, transparent and non-
discriminatory planning process is critical to minimise these risks and thus the efficient cost of 
service. 

Assuming that the costs incurred by network operators are efficient, cost re-allocation may still be 
warranted to adequately phase-out or decarbonise natural gas systems, to reflect energy system 
positive externalities which are not internalised, and to incentivise potential hydrogen network 
users. 

Cost re-allocation may be explicit (through monetary transfers between network operators of 
different carriers or through government subsidies), or implicit (by joint accounts of combined gas 
operators). This is reflected in the options for cost allocation: 

  Option A: Neither cost re-allocation between networks nor subsidies by governments are 

allowed; 

  Option B: Cost re-allocation between hydrogen, methane and electricity network operators 

is allowed; 

  Option C: The use of combined accounts by combined gas network operators implicitly 

allows for cost re-allocation, if e.g. tariff revenues from methane network users are used to 
recover the allowed revenue of hydrogen network operators, especially the capital 
remuneration and depreciation components. 

It is assumed that for any of the options, subsidies (state aid) would be allowed for hydrogen 
networks, as part of energy infrastructures. Options for state aid to hydrogen networks are not 
analysed in this study, as they are part of the scope of the Guidelines on State aid for 
environmental protection and energy rather than related to network regulation. 

Table 3-7 Cost re-allocation options  

Re-allocation 
allowed 

Explicit/ 
implicit 
allocation 

Advantages 

Option A 

Option B 

Option C 

Cost re-allocation not allowed  Cross-sectoral cost allocation 

Combined gas network 
operators without accounts 
unbundling 

None 

Explicit 

Implicit 

 Low regulatory costs 
 Automatically cost reflective 
in case of no significant 
externalities 

 Reflects provision of non-
internalised system benefits 
 Beneficial for minority 
consumers (H2 at start, later 
NG) 
 Employs methane / 
electricity tariff revenue 

  Reduced administrative 

burden 

  Allows sharing of risks and 

costs 

 Beneficial for minority 
consumers (H2 at start, later 
NG) 

Disadvantages 
/ risks 

 Not cost reflective in case of 
significant externalities that 
are not internalised 

 Increases electricity / 
methane network tariffs 
 Complex integrated system 
assessment 

Mitigation 
measures 

 Subsidies to hydrogen 
networks 

 Require assessment of 
externalities 

  Cost allocation not 

transparent 

 May incentivise inefficient 
decisions if techno-economic 
parameters are 
fundamentally different 

 Use accounts unbundling 
 Use technology-specific 
techno-economic parameters 

69 

 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

The consideration of cost re-allocation either among ratepayers or to taxpayers should follow some 
guidelines: 

  Cross-sectoral cost allocation or subsidies should reflect externalities that are not 

internalised, and should be recovered from the beneficiaries of the positive externalities; 

  Energy network users should pay for the positive system externalities such as system 
reliability and security of energy supply which benefit them, while environmental 
externalities can be supported by taxpayers, and possibly recovered via a surcharge from 
the concerned end-users; 

  Cross-subsidisation between different categories of consumers should in principle not 
occur. For example, residential methane gas consumers should not cross-subsidise 
hydrogen networks serving mainly industrial consumers; 

  Assessment of the externalities should be a pre-condition to any cross-sectoral cost re-

allocation or subsidies. 

The non-internalised positive externalities of hydrogen networks could be estimated by: 

1.  Conducting a forward-looking resource adequacy assessment of the energy system; 
2.  Calculating the system-optimal level of hydrogen infrastructure deployment; 
3.  Comparing that to the expected level of deployment without cross-subsidisation; 
4.  Recovering the difference through subsidisation and/or charges to the methane and 

electricity sectors. 

Ideally, well-designed electricity and methane markets should adequately remunerate technologies 
at the interface with hydrogen systems. Hence, for example, electricity capacity remuneration 
mechanisms should also allow the participation of electrolysers and hydrogen-based power 
generation. Only if these technologies would not be adequately remunerated and grid tariffs would 
not allow to recover hydrogen network costs, subsidies and cost re-allocation can be considered to 
facilitate hydrogen network investments. Other mechanisms can be employed to recover the 
hydrogen networks investments in a cost-reflective manner. For instance, long depreciation periods 
could be used in order not to unduly burden initial hydrogen network users.  

To cover the costs arising from the eventual decommissioning of methane assets, the “Potentials of 
sector coupling for decarbonisation” study indicates that the options of cost reallocation to 
taxpayers and ratepayers of the electricity and hydrogen systems could be both feasible (with a 
preference for the reallocation to taxpayers). Front-loading the recovery of costs through 
accelerated depreciation, shorter depreciation periods or classifying a higher share of costs as 
OPEX is also proposed as a solution188. Recently, CEER also hinted at eventual cost sharing to be 
possible between energy sectors, although also stating that “potential negative impacts such as 
unjustified cross-subsidies” should be kept to a minimum.189 

Another study for Germany indicated that significant special depreciation costs for decommissioned 
methane assets would arise, in the order of 6 billion € for the 2033-2050 period.190 The study 
argued that the special depreciation costs could be avoided through investments in hydrogen 
networks (through the conversion of the to-be-decommissioned assets), leading to societal benefits 
and freeing up funds. This would complement available funds already arising from the reduced 
allowed revenue for methane network operators, which would result from the depreciation of 
assets and decreased investment levels. 

The biomethane and hydrogen study191 raised a number of potential policy and regulatory 
measures on network charging relevant for hydrogen networks. These include “joint tariffication of 
methane and hydrogen networks”, which would be compatible with option D above, and application 
of “super-shallow connection charges and tariff discounts for renewable and/or decarbonised gases 
when justified by system benefits or policy objectives”, which could be applied in any of the 
options.  

188 Frontier Economics et al. (2019) Potentials of sector coupling for decarbonisation – Assessing regulatory 
barriers in linking the gas and electricity sectors in the EU. 
189 CEER (2020) Paper on Whole System Approaches. C19-DS-58-03. 
190 bbh (2020) Principles of the regulation of German hydrogen networks in the context of an adaptation of the 
European legal framework and the financing of hydrogen networks by integration into the legal framework of 
gas network regulation.  
191 Trinomics, LBST and E3-M (2019) Impact of the use of the biomethane and hydrogen potential on trans-
European infrastructure 

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Sector integration – Regulatory framework for hydrogen 

Additional principles for network revenue regulation 

Next to the topic of the allowed network revenue recovery through taxpayers and/or ratepayers, a 
number of other principles should be followed by Member States when regulating the allowed 
revenue. EU legislation could set general guidelines to ensure that national regulatory frameworks 
respect the following principles:192 

  Require an objective, transparent and non-discriminatory network planning process with 

strong oversight; 
Encourage a balanced consideration of OPEX- and CAPEX-based solutions; 

 
  Assure stakeholder consultation on network development plans and on a project level (for 

large projects); 

  Require that capitalised costs financed with third-party contributions such as government 

subsidies or cross-sectoral transfers are not included in the RAB; 

  Avoid that the RABs are re-evaluated in case of (further) unbundling of network operators 
or upon conversion of methane infrastructure. The roll-out of hydrogen networks and 
changes to the regulatory framework should not constitute a reason for methane grid 
operators to review (increase) the residual accounting value of their repurposed assets; 

  Review the depreciation rules of methane infrastructure so that they better anticipate the 

expected evolutions of the gas system and properly reflect the economic lifetime of assets, 
considering current tariff levels and the ability of network users to absorb short-term hikes, 
especially vulnerable consumers and industrial users exposed to international 
competition;193 

  Maintain separated accounts between hydrogen and methane networks, to assure 

 

transparency, cost-reflectivity, and avoid information asymmetry between regulators and 
network operators; 
Ensure that the revenue methodology parameters for hydrogen and methane networks do 
not constitute a perverse incentive for incumbent methane network operators to repurpose 
methane pipelines where not socially beneficial. This could be the case if the capital 
remuneration level for hydrogen network RABs would be significantly higher than for 
methane networks while the effective capital costs would be similar. 

3.4.2 Natural gas as a basis for hydrogen network regulation: Revenue regulation 

The recovery of costs is regulated under the Article 13 of the Gas Regulation (Tariffs for access to 
networks), which states that network usage tariffs should be used to cover the actually incurred 
network costs, provided the service is run efficiently, and include appropriate return on investment. 
The revenue regulatory requirements are further elaborated in the Chapter IV of the Commission 
Regulation establishing Network Code on Harmonised Transmission Tariff Structures for Gas (TAR 
NC).194 

The following summary of revenue regulation building blocks is based on the study ‘Methodologies 
and parameters used to determine the allowed or target revenue of gas transmission system 
operators’, commissioned by ACER.195  

Most countries in the EU apply some kind of incentive-based approach to revenue regulation. In 
2018, 13 countries applied a revenue cap mechanism, 2 countries a price cap mechanism, and 9 
countries deployed a hybrid approach, usually applying a revenue cap on OPEX and a cost-plus 
approach for CAPEX. Only one country applied solely a cost-plus based approach. 19 out of 27 
regulators apply efficiency factors for OPEX, only those using a TOTEX approach apply efficiency 
factors to capital expenditures. 

The allowed revenues are in most EU countries established by assessing all cost components 
separately, e.g. using the building block approach. Only 3 countries apply a combined OPEX and 
CAPEX assessment (TOTEX) approach. Most of the regulators use a bottom-up approach for the 
CAPEX assessment, e.g. assessing individually all cost items claimed by network operators. For the 
OPEX assessment however, using a top-down cost approach is prevalent as well. The less prevalent 
method is benchmarking the costs to external factors. 

The regulatory periods range from 1 to 8 years in Europe, although a vast majority of countries 
opts for 4 to 5 years. 

192 Some principles proposed in Ecorys et al. (2019) Do current regulatory frameworks in the EU support 
innovation and security of supply in electricity and gas infrastructure? 
193 Trinomics, LBST and E3-M (2019) Impact of the use of the biomethane and hydrogen potential on trans-
European infrastructure 
194 EC (2017). Commission Regulation (EU) 2017/460 of 16 March 2017 establishing a network code on 
harmonised transmission tariff structures for gas 
195 ECA (2018). Consultant report for ACER - Methodologies and parameters used to determine the allowed or 
target revenue of gas transmission system operators (TSOs) 

71 

 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

The mostly used valuation method for determining the regulatory asset base is based on the 
historical costs (11 countries), followed by the actual economic value assessment (8 countries). In 
most cases, the asset value is not revaluated during the regulatory periods (except for deducting 
the depreciation), only two NRAs use the replacement cost as a basis for the periodic revaluation. 

While there is a wide consensus on using the linear depreciation method (as opposed to an 
accelerated depreciation), the regulated lifetime of assets substantially varies across the EU, as 
shown in Table 3-12 below. 

Table 3-8 Depreciation period (in years) of gas network assets 

Type of asset 

Pipelines 

Compressors 

Controllers & metering 

SCADA & telecom 

Min value 

Typical value 

Max value 

30 

12 

9 

4 

40-50 

20-30 

20-30 

5-10 

90 

65 

45 

45 

The allowed cost of capital also substantially differs among the EU countries, especially since 
there are different calculation methods, the most dominant method being the pre-tax calculation, 
either in nominal or in real values. The risk-free rate seems to significantly vary between Member 
States without a clearly established range, whereas the market risk premium seems to be more 
consistent, with most countries setting a value between 4,5% - 5,05%. There is however a wide-
scale consensus on setting the equity beta value below 1, suggesting that investments in regulated 
network assets bear less risk than in market assets in general. 

One national regulator specifically raised the question whether the same asset lives and fixed OPEX 
rates as used for natural gas could be applied to hydrogen, indicating that this issue requires 
further study. The question of OPEX rates was specifically investigated in the biomethane and 
hydrogen study196, where stakeholders from the gas sector indicated that the OPEX levels for 
hydrogen distribution networks could be similar to methane networks at around 1%/a of CAPEX, 
although the study acknowledged that further research is needed to validate these assumptions. 
The OPEX for natural gas transmission networks are significantly higher, at 1.7%/a to 2.4%/a of 
CAPEX, based on the 2018 TYNDP data. Similar or higher levels could thus be expected for 
hydrogen transmission networks. The European Hydrogen Backbone197 study assumes annual OPEX 
costs (excluding electricity costs for compression) of 0.8-1.7% of CAPEX of new investments, but 
scenarios lead to total OPEX costs (also including electricity costs for compression) of 5.4-6%, 
presumably due to CAPEX savings resulting from the repurposing of methane infrastructure. 

Options formulation 

In option A, there would be no revenue regulation for hydrogen networks. In option B, the 
regulatory approach for natural gas and hydrogen networks would be the same for all regulatory 
elements (e.g. WACC, depreciation period). The revenues from both networks would be cumulated 
and the resulting deviation from the allowed revenues would be globally assessed – any under-
/over-recovery in one network could be balanced out by the other network. In option C, some of 
the specific regulatory elements would be defined separately for natural gas and hydrogen 
networks, such as technology-specific lifetimes or specific WACC rules, reflecting different risk 
levels for investing in methane or hydrogen networks. The overall regulatory principles, i.e. 
incentive-based or cost+ approach, would remain the same and there would be no differentiation in 
the regulatory accounts between hydrogen and methane infrastructure. The last option D builds on 
option C, but both networks would be separated in the regulatory accounts, thus eliminating the 
possibility of balancing the accounts between networks. 

196 Trinomics, LBST and E3-M (2019) Impact of the use of the biomethane and hydrogen potential on trans-
European infrastructure 
197 Enagás et al. with support of Guidehouse (2020) European Hydrogen Backbone 

72 

 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Table 3-9 Revenue regulation options based on the natural gas regulatory framework  

Option A 

Option B 

Option C 

Option D 

Approach 
between 
methane and 
hydrogen 

No revenue 
regulation 

Unified approach 

Unified approach 
with technology-
specific adaptations 

Advantages 

  Reduced 

administrative 
burden 
  Increased 

flexibility for 
network operators 
adjusting tariffs 

Disadvantages 
/ risks 

  Cost allocation 
not transparent 

  Potential 

discrimination of 
price-insensitive 
network users 

   

  Reduced 

administrative 
burden 

  Allows sharing of 
risks and costs 

  Beneficial for 
minority of 
consumers (H2 at 
start, later NG) 

  Technology-

neutral 

  Cost allocation 
not transparent 
  May incentivise 

inefficient 
decisions if 
techno-economic 
parameters are 
fundamentally 
different 

  Cross-

subsidisation 
likely 

Separation of 
methane and 
hydrogen in 
regulatory accounts 

  Reflecting 

different value of 
assets; expected 
lifetime; level of 
risk 

  Reflecting 

different drivers 
of sector 
development (NG: 
efficient usage of 
existing assets; 
H2: development 
of new networks) 

  Reduced 

administrative 
burden 

  Allows sharing of 
risks and costs  

  Reflects main 
differences in 
techno-economic 
parameters 

  Increased 

complexity 
compared to 
option A 

  Cost allocation 
not transparent 

  Harder to 

distinguish which 
approach to apply 
e.g. for hydrogen 
admixture costs 

Mitigation 
measures 

  Regulatory 

  Separate sub-

approval of tariffs 

accounts 

  Ex-post control 
mechanisms by 
NRAs 

  WACC adders for 

high-risk 
investments 

  Separate sub-

accounts 

  Cost re-allocation 
between energy 
networks to 
reflect non-
internalised 
externalities 

The overall framework for network planning involves the definition of 1) the responsibility for 
network planning; 2) oversight of the planning process and approval of the plan, and 3) investment 
in and operation of the assets.198 Steps 1) and 3) may be conducted by the same or different 
operators, while generally step 2) is the responsibility of the competent authority or regulator. 
Hence, the following archetypal network planning models can be defined:199 

  Centralised network planning by an appointed organisation, and investment and operation 

of assets conducted by one or more separate companies; 

  Combined network planning, investment and operation by the same company; 

The regulator may be responsible for authorising expansion plans for any of the possible 
approaches above. The model of network users-driven expansion planning is rarely applied. 
Merchant investors may develop transmission projects which were not included in network 
expansion plans, also with prior authorisation (and provision of necessary exemptions of e.g. third-
party access) by regulators. 

Commonly used network planning criteria (security of supply, positive net socio-economic welfare, 
integrating renewable energy sources, minimising negative environmental impacts, and less often 
innovation) are also relevant for hydrogen networks. Traditionally, network development plans are 
demand-based, i.e. they must ensure system adequacy based on the forecasted demand, while 
also integrating the planned decentralised production of electricity, methane (biomethane) and 
hydrogen. 

198 Pérez-Arriaga (ed., 2013). Regulation of the power sector. 
199 Network users-driven expansion planning is also possible but rarely applied, where network users are 
responsible for proposing and voting candidate projects, and the network operator or a consortium of network 
users build the project(s). 

73 

 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Box 3-9 CEER’s paper on whole-system approaches200 

CEER’s paper released in June 2020 develops concepts for the whole-system approach for 
planning and operation of energy systems on three layers: the whole-network (i.e. TSO-DSO), 
the whole-chain (i.e. within one energy sector) and the cross-systems layer (e.g. between the 
electricity and gas sectors). It notes the cross-border layer could be added to the typology. 

The lack of a whole-system approach could lead to the planning and operation of an energy 
system which does not properly consider the interactions between the different vectors, with a 
(strong) potential to lead to sub-optimal results from a societal perspective. 

The paper notes 4 types of mechanisms to foster such a whole-system approach: 

  Regulatory incentives: within-network positive and negative incentives should be 

inserted in the regulatory framework setting the allowed revenue and tariff structure; 

  Regulatory requirements: such as requirements for coordination and cooperation 

between network operators and third-parties; 

  EU and national laws and regulation not impeding regulators and network operators 
to cooperating outside of their specific sector and pursuing common pathways, while 
minimising risks such as unjustified cross-subsidies; 

  Data transparency and interoperability, which act as an enabler for whole-systems 

approaches. 

Network planning and dedicated hydrogen networks 

Adequate planning procedures for hydrogen networks will serve to provide certainty for 
investments from regulated network operators as well as from network users. Network plans are a 
central instrument for guaranteeing that efficient investments proposed by network operators are 
authorised by regulators and hence may be included in their regulatory asset base and recovered 
via regulated tariffs. For (potential and existing) network users, hydrogen network plans will be 
useful to have updated information about the planned roll-out of hydrogen networks, when 
considering using the network versus alternatives such as on-site H2 production. 

The network planning will need to consider, to the extent where relevant, the entire energy 
system, at least the electricity and methane systems. Several studies about long-term 
decarbonisation scenarios have shown that an integrated planning approach is the lowest cost 
solution, in particular due to the fact that conversion of methane infrastructure is cheaper than 
investing in new hydrogen infrastructure. This is supported by the Energy System Integration 
Strategy of the European Commission.201 Moreover, as energy efficiency measures and direct 
electrification of end-uses are often the most cost-efficient solution, these will need to be 
considered before investments in methane and hydrogen infrastructure are made. Further 
interaction between the electricity, methane, hydrogen and heat sectors will take place through 
conversion technologies and hybrid equipment and appliances, such as hybrid turbines or boilers. 

This implies that the planning will also need to include the main potential solutions in each of the 
sectors for a secure and affordable energy supply that contributes to the energy and climate 
objectives. While the methane and hydrogen systems can provide important daily and seasonal 
storage as well as supply flexibility through LH2 terminals, these capacities may be constrained in 
size and location. Also, constraints in the electricity and hydrogen network capacity will play a role 
in determining the location of large-scale electrolysers. 

Policymakers will need to provide guidance regarding the planned roll-out of hydrogen networks 
and the eventual downscaling or decarbonisation of methane networks, so that the (dis)connection 
of methane network users is aligned with the energy and climate objectives. Policymakers will also 
need to consider under which conditions network operators can be obliged to connect new users to 
the hydrogen or methane network (and eventually revise existing obligations). 

When hydrogen systems will reach scale and will get integrated across borders, the planning of 
cross-border infrastructure will gain importance in specific regions. Planning at the EU level will 
then be necessary for major cross-border / cross-zonal infrastructure and also for addressing 
potential domestic structural congestion, also since transit flows may become important in some 
Member States that transport hydrogen from peripheral / coastal regions to central Europe. Hence, 
cross-border cooperation and consistency between the planning at the EU and national levels will 

200 Available at https://www.ceer.eu/documents/104400/-/-/c52735ff-54db-9d8b-146d-753d7edc141d 
201 European Commission (2020). Powering a climate-neutral economy: An EU Strategy for Energy System 
Integration. COM(2020) 299 final. 

74 

 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

be required depending on the scale of hydrogen deployment. This will also be necessary for the 
repurposing of cross-border methane interconnections, which will need to consider the cross-border 
transport capacity demand for hydrogen, which may, notwithstanding its lower energy density, be 
significantly lower than the capacity of the repurposed pipelines. However, compressors may be 
dimensioned to the actual forecasted demand, leading to CAPEX economies.202 

Integration between hydrogen transmission and distribution systems will also be necessary. 
Hydrogen systems may start being developed in either of the two levels, depending on the supply 
and demand characteristics, the eventual integration of hydrogen clusters as well as other factors. 
As the hydrogen infrastructure is expected to gradually develop, some new users may have the 
option to connect at the transmission or distribution level, which may create the risk for limited 
visibility of TSOs and DSOs on injection/demand forecasts at each level. Also, small-scale 
technologies such as electrolysers of up to tens of MWs can lead to significant production of 
hydrogen at the distribution level in certain clusters. 

Hence, hydrogen TSO-DSO cooperation will be necessary for systems where such two network 
levels will exist or would be deployed within the planning horizon. The decision on which level to 
connect new users should, preferentially, rest with the network operators rather than the users. 
This would avoid situations such as in Denmark, where biomethane producers could choose the 
grid connection level and bear the related costs, which meant that late-comers could only be 
connected to the (more expensive) transmission level, as the distribution network capacity was 
already taken. The model was changed to assign the planning responsibility to the network 
operators, which are supposed to realise the necessary efficient network investments allowing to 
connect biomethane users at the most adequate level.203 

Moreover, the roll-out of (cross-border) hydrogen networks will require the definition of 
interoperability guidelines and subsequent agreements, as well as European standards for gas 
quality and end-user equipment and appliances. For methane grids, similar requirements are 
necessary, also due to the planned blending of hydrogen in some methane networks. 

Box 3-10 The MosaHYc (Mosel Saar HYdrogen Conversion) project204 

In May 2020 the French natural gas TSO GRTgaz and the Luxembourger TSO Creos have signed 
a collaboration agreement for the MosaHYc (Mosel Saar HYdrogen Conversion) project. 

MosaHYc aims to converting existing natural gas pipelines to develop a 70-km hydrogen network 
across the France-Germany-Luxembourg border, aiming at supplying the transport sector. It 
could be further expanded to connect industrial clusters in the region. The gas TSOs will 
cooperate with the national regulators to develop the technical aspects of the project, but also 
the required regulatory framework to take a final investment decision in 2022. 

202 Enagás et al. with support of Guidehouse (2020) European Hydrogen Backbone 
203 See for example Energinet (2018) System Plan 2018 – Electricity and gas in Denmark 
204 Source: GRTgaz (2020) Hydrogen: signing of a collaboration agreement between GRTgaz SA and Creos 
Deutschland GmbH 
http://www.grtgaz.com/en/press/press-releases/news-details/article/hydrogene-lancement-du-projet-
mosahyc.html 

75 

 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Stakeholders’ opinions 

Stakeholders agree that network planning should be holistic and consider investment, operation 
and decommissioning costs as well as security of supply, climate and environmental impacts along 
the entire hydrogen, methane and electricity value chains.  

Multiple stakeholders, also including regulators, consider the network planning monopoly as a 
potential source of efficiency. One stakeholder highlighted the need for European guidelines on 
planning transparency and assessment of competing alternatives in the hydrogen, methane and 
electricity sectors.  

A stakeholder highlighted that the previous TYNDPs tended to analyse in detail network expansion 
options, while dedicating less attention to alternatives, leading to biased scenarios and the lack of 
acknowledgment for the alternatives. It stressed the need to define how conflicts of interest of 
network operators for the conversion of methane networks will be managed, and also whether 
current gas users could be forced to disconnect from the methane grid and/or switch to hydrogen. 

Generally, natural gas network operators do not see a need for the separation of network planning 
from the investment and operation of network assets, noting that there are synergies between 
them leading to investment and operational savings, especially in the case of significant conversion 
of methane pipelines. According to the network operators, the current transparent, non-
discriminatory planning processes for methane networks, which include oversight and consultation 
of stakeholders, would be an appropriate model for the planning of hydrogen networks. Regardless 
of which organisation has the responsibility for network planning, it is generally recognised that 
network and storage operators have an important role to play in the siting of assets such as for 
conversion, as transparency on available infrastructure capacity and constraints is key for efficient 
decisions. 

Gas TSOs support the immediate start of coordinated planning for a hydrogen backbone in Europe, 
to “diversify supply sources and prevent anti-competitive market structures”. They sustain that 
planning at the EU level would be carried out best within the existing TYNDP framework (updated 
as necessary). This would leverage existing and tested processes, and promote transparency. 

A market actor suggested that the TYNDP process should also evaluate the impact of 
decommissioning of energy infrastructure, in consultation with the users of the specific 
infrastructure. 

A natural gas network operator indicated that the discussion about separating the planning from 
the investment and operation of assets is similar to that taking place in the natural gas sector, and 
that the answer is not straightforward, as the proportionality of such a measure should be 
considered. Strict regulatory oversight in the concerned country should ensure that the benefits of 
network investments outweigh the costs. The transparency and non-discrimination of the planning 
process would involve multiple other questions such as information requirements, consultations 
and cooperation mechanisms, and existing measures could be improved.  

Stakeholders are unanimous regarding the need for increased coordination between TSOs and 
DSOs to plan the necessary infrastructure development, system operation and connection of 
network users. Interestingly, a stakeholder also highlighted the need for coordinating the R&I 
projects which will still be necessary in order to enable the deployment of a hydrogen system. 

A network operator indicated that the consideration of hydrogen infrastructure projects as being of 
public interest would facilitate the permitting procedures. 

3.5.1 Greenfield hydrogen regulation: Network planning 

The options developed for hydrogen network planning are organised in three main dimensions: 

  Network planning responsibility and oversight; 

  Cross-border network planning; 

  Cross-carrier network planning. 

Extensive stakeholder consultation should be part of the development of the scenarios, 
methodologies and network development plans for all options discussed below. The network 
operators should provide an analysis and justification of (non-)actions taken in response to 
stakeholder inputs.  

76 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Box 3-11 A proposal for an EU hydrogen TSO 

Some of the options for the regulatory elements considered in chapters 3 and 4 imply the 
creation of an EU hydrogen TSO. This EU H2 TSO could be responsible for a number of functions, 
in particular: 

  Network planning (section 3.5)- Development of EU-level determinative hydrogen 

network planning, including methodologies and scenarios (with ACER/EC approval). 

  CACM (section 3.7) - Management of capacity management and congestion platform 

employed for: 

o  DA/IDA implicit market coupling (in cooperation with market coupling operator, 

MCO, and TSOs); 

o  Countertrading and re-dispatching actions. 

  Network charging (section 3.6) - Management of inter-TSO compensation mechanism; 
  Balancing (section 4.2.3) - Management of balancing market coupling platform (with 

market area manager) – potentially same as CACM platform. 

DA/ID implicit market coupling, CACM and inter-TSO compensation would occur in the following 
manner: 

1.  Market participants trade  
2.  TSOs inform capacity availability data to the capacity management platform 
3.  Market participants submit supply/demand bids to nominated market operators 
4.  Capacity management platform and nominated market operators’ inform capacity and 

bid data to market coupling operator 

5.  Market coupling operator clears coupled market with information from capacity 

management and nominated market operators 

6.  EU H2 TSO manages intra-day and close to real-time congestion management actions 

(preferentially countertrading, otherwise redispatching) 

7.  Ex-post flows, other data are employed to define inter-TSO compensation for used 

interconnection capacity, congestion management measures 

The functioning of the ITC mechanism would be as follows: 

  Harmonised principles for XB and national tariffs would be set to address market 

distortion issues 

  NRAs or TSOs with NRA approval set regulated tariff levels 
 

Tariffs at IPs for clearing markets (ID, DA, BAL) would be set at 0 / limited value 
reflecting variable costs 
Ex-post flows, other data (e.g. network capacity) employed to define inter-TSO 
compensation for used/available interconnection capacity, congestion management 
measures 
TSOs pass through ITC costs/surpluses to network users cost-reflectively  

 

 

Ideally, the planning of cross-border and trans-European hydrogen, methane and electricity 
infrastructure should be conducted by a single organisation or with strong cooperation of the 
sector-specific EU-level (EN)TSOs employing common scenarios and a single energy systems 
model and CBA methodology. This single EU-level energy TSO entity could be set up by (or 
formed by the merger of) the electricity and methane ENTSOs with the new EU H2 TSO. 
However, in this scenario this single organisation could have different mandated activities for the 
hydrogen vs the electricity and methane sectors (e.g. regarding capacity allocation). Options to 
integrate network planning across energy carriers thus comprise: 

 

The new organisation could be responsible solely for planning, while other responsibilities 
could be assigned to a hydrogen-specific EU TSO; 

  Sector-specific EU-level (EN)TSOs would cooperate in planning while being mandated to 

jointly develop the scenarios, CBA methodology and energy systems model. If the 
mandates of ENTSO-E, ENTSOG and the EU H2 TSO are deemed compatible, they could 
be merged into a single organisation in order to facilitate sector coupling and reduce 
overhead costs. 

Another important aspect is whether the EU H2 TSO would be responsible for all above-
mentioned functions or whether some of them could better be assigned to regional 
organisations. Planning of hydrogen backbone infrastructure should take place at the EU-level, 
due to the importance of integrated planning across regions as well as the fact that planning of 
electricity and methane infrastructure (which would ideally be integrated with that of hydrogen 
infrastructure) is already conducted at the EU-level. Capacity allocation and congestion 
management, balancing and inter-TSO compensation could be managed by regional 
organisations reflecting interconnected hydrogen systems. However, as hydrogen systems would 

77 

 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

in the future have to be interconnected at a pan-European level, single EU platforms for such 
activities would be more efficient. 

Regarding the structure of the EU H2 TSO, two main options can be considered: 

1.  The EU H2 TSO is an independent organisation funded via fees from network operators 
and led by a management board with representatives from hydrogen TSOs and DSOs, 
regulators, hydrogen market participants, as well as with representatives from electricity 
and methane network operators and market participants. This representation would 
assure that the planning process conducted by the EU H2 TSO is unbiased. To simplify 
the process, existing EU-level organisations could represent all concerned stakeholders 
(i.e. with ACER, the EU H2 TSO, ENTSO-E, ENTSOG and EU-level representatives of 
market participants on the board); 

2.  Gas TSOs are shareholders of the EU H2 TSO, with an advisory board of (possibly EU-
level) stakeholders representing NRAs, hydrogen market participants, electricity / 
methane / combined gas network operators and market participants. 

The above-mentioned proposal for market coupling is related to but separate from the question 
of the definition of wholesale and balancing hydrogen market areas. A regulatory process for 
defining the most appropriate market areas should be established considering aspects such as 
hydrogen system interconnection levels, potential congestion and electricity and methane 
market areas’ configuration. Market coupling measures should then be established for major 
corridors, and ideally EU-wide in the long-term. 

Natural gas TSOs are of the general opinion that setting up a EU H2 TSO would be premature, as 
it would not be able to take into account the “different speeds of market development in the 
various regions and the different pipeline topographies”. 

Responsibility and oversight of hydrogen network planning 

The table below presents the main options for hydrogen network planning responsibility and 
oversight: 

  Option A: Joint hydrogen network planning, investment and operation, with ‘light’ 

oversight in the form of opinions from policy makers and/or regulators; 

  Option B: Joint hydrogen network planning, investment and operation, with strong 

oversight in the form of approval and amendments from policy makers and/or regulators; 

  Option C: Hydrogen network planning conducted by a separate independent body, with 
strong oversight in the form of approval and amendments from policy makers and/or 
regulators. 

Table 3-10 Network planning responsibility and oversight options  

Option A 

Option B 

Option C 

Oversight 

Opinions by authority 

Approval and amendment of 
methodology and outputs by 
authority 

Approval and amendment of 
methodology and outputs by 
authority 

Planning, 
investment and 
operation 

Planning by network operator  Planning by network operator 

Advantages 

 Low regulatory cost and 
shorter process 

 Non-discrimination of other 
resources 

Disadvantages / 
risks 

 Information asymmetry 
 Network operator not 
obliged to consider opinions 

 Longer regulatory process 
 Information asymmetry 
 Regulatory cost 

Mitigation 
measures 

 Transparency obligations 
 Dispute arbitration 
mechanism for third-parties 

 Transparency obligations 

Separate planning by 
independent body 

 Non-discrimination of other 
resources 
 Lower regulatory cost and 
information asymmetry than 
option B 

 Higher coordination 
necessary 
 Higher regulatory cost 
compared to option A 
 May require unbundling of 
existing network operators to 
separate activities 

 Allow legal/functional 
unbundling (instead of 
stricter OU) to separate 
planning 

The main elements of the network planning process where oversight should be exerted by the 
authority are the scenarios, the CBA methodology and the network development plans. Network 

78 

 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

planning is a critical regulatory element as it has a direct impact on the cost for achieving climate 
and energy objectives (including the roll-out of hydrogen networks), on the allowed revenue of 
network operators, and ultimately on tariffs to hydrogen network users. Moreover, neutral 
scenarios and an appropriate CBA methodology are necessary to ensure that all options are 
adequately considered, including storage, demand response, sector coupling as well as network 
OPEX-oriented solutions. 

Combined gas network operators could have a specific interest in favouring the conversion of 
methane network assets instead of other solutions. In the context of expected decreasing demand 
for methane gases, the risk for potential over-investment should be properly addressed. Moreover, 
there will certainly be cases where decommissioning methane infrastructure is  from a societal 
perspective a better solution than repurposing it.  

In addition to the moral hazard that network operators may over-invest in hydrogen networks, 
there is the converse risk of potential under-investment in hydrogen infrastructure. Such 
mismatches could arise from the uncertainty on the transition pathways, and the fact that 
regulated network operators may take investment decisions based on policy and regulatory signals 
rather than on market needs. Network development plans based on realistic and validated 
scenarios aligned to firm policy goals are hence an important element to avoid over- or under-
investments and to ensure that the development of energy networks adequately supports the 
energy and climate objectives, including the decarbonisation of the energy system at least overall 
cost. 

Hence, non-discriminatory and transparent planning based on policy-aligned scenarios is essential. 
A scenario with significant investments for development of hydrogen networks across Member 
States would require strong oversight of the planning process (options B and C) in order to ensure 
alignment to policy objectives and approval of efficient network investments only, based on an 
analysis from a cross-border and cross-energy carrier perspective (discussed below).  

Separating the planning of hydrogen networks from the asset investment and operation (option C) 
would guarantee that the planning process is non-discriminatory and transparent, and lead to a 
lower regulatory cost and less information asymmetry between the network operator and regulator 
compared to option B. It would furthermore allow to tender the construction of new network 
sections and/or O&M of network assets to individual companies. However, separate planning would 
require increased coordination between the planning organisation and network operators. Separate 
planning would also be more interesting if it could be implemented not only for hydrogen but also 
for methane and electricity networks: i.e. if an independent organisation could be tasked with the 
network planning for all energy carriers.  

Finally, transparency would benefit from the use of an open model and data (input and output) by 
the network operators or planning organisation. Any regulated organisation should be required to 
publish the models and data employed, which would furthermore increase public trust in the 
network development plans, thus facilitating their implementation. 

Cross-energy carrier network planning 

An increasing degree of integration of cross-carrier network planning can take place as reflected by 
the options in the table below: 

  Option A: No harmonisation at EU level, i.e. network operators for each energy carrier are 
not obliged to cooperate with each other, and Member States are free to decide on the 
issue at the national level; 

  Option B: Network operators in hydrogen, methane and electricity (and possibly heat) are 

by EU law obliged to employ common scenarios, as well as considering significant 
interlinkages between the energy systems. However, the use of an integrated energy 
systems modelling is not required, leading to the development of separate network 
development plans for each energy system; 

  Option C: Network operators in hydrogen, methane and electricity are by EU law required 
to employ common scenarios and an integrated energy systems models linking all energy 
systems. This leads to an integrated NDP, or at least to separate NDPs based on common 
modelling outputs. 

79 

 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Table 3-11 Cross-energy carrier network planning options  

Option A 

Option B 

Option C 

Options 

No harmonisation at EU level 

Advantages 

 Low coordination required 

Disadvantages / 
risks 

 Risk of uncoordinated / 
biased scenarios 

Mitigation 
measures 

 Foresee minimum 
information exchange 
requirements between 
network operators 

Common scenarios and 
consideration of main 
interactions 

Common scenarios, integrated 
energy systems model and 
NDP 

 Considers main interactions 
 Common scenarios enhance 
neutrality and consistency 

 Medium complexity 
 Medium coordination 
required 

 Phase in when hydrogen 
system reaches scale 
 Require only when 
significant interactions with 
methane/electricity sectors 
exist 

 Considers detailed 
interactions 
 Common scenarios enhance 
neutrality and consistency 

 High complexity 
 High coordination required 

 Phase in when hydrogen 
system reaches scale 
 Ensure consistency of CBA 
methodologies and models 
prior to option introduction 

The adequacy of the options will depend on the expected level of deployment of hydrogen networks 
and the level of sector integration. Hence, in countries with little or no hydrogen deployment, 
option A would be most suitable as limited interaction would occur between the hydrogen and other 
energy systems. Nonetheless, to ensure a minimum level of coordination, option A could foresee 
minimum information exchange requirements between network operators. 

The use of common scenarios and consideration of main interactions suggested in option B is 
similar to the current interlinked model of the ENTSOs. Common scenarios would enhance the 
neutrality and consistency of the network development plans, by obliging network operators with 
different interests and expertise to agree on common scenarios. A methodology would need to be 
developed for the identification and consideration of main interactions, such as those related to 
large-scale electrolysers (hundreds of MWs), possibly through exchanging supply and demand 
curves and checking the compatibility of the plans regarding those large interactions (e.g. to 
ensure that no structural network constraints would arise at either side of the conversion 
technology). This option would be coherent with the process for the definition of Projects of 
Common Interest in the TEN-E regulation, which will be revised to also include hydrogen corridors. 

Option C would best consider the system integration through the use of an integrated energy 
systems model, at the cost of higher complexity and need for coordination between network 
operators. Hence, such approach could be applied once the hydrogen system will reach a 
significant scale, and a high level of interactions. Criteria would need to be defined to establish this 
threshold, and work conducted proactively to develop the planning model. 

Moreover, it is difficult to migrate to an integrated energy systems model once network operators 
are employing their own mature models and separate CBA methodologies. Hence, measures could 
be taken to facilitate the transition to an integrated energy systems model, as it would require not 
only hydrogen but also methane and electricity (and in some Member States also heat) network 
operators to adapt their approach. Measures could ensure the consistency of the CBA 
methodologies and models as much as possible. Soft linking of the models of the network 
operators would also allow to represent the relevant features of each energy system while limiting 
the integrated model complexity. 

For all options, unregulated or exempted hydrogen network operators should be obliged to timely 
provide information on their network development plans and demand and supply forecasts for the 
organisation responsible for the planning of hydrogen networks to consider in their own planning. 

At the national level, there generally exists a framework  for notifying and coordinating 
decommissioning of assets. The Council Regulation (EU,  Euratom) No 617/2010205 establishes 
notification obligations to the Commission of investment projects in energy infrastructure within the 
EU, including gas transmission pipelines.206 A new provision obliging network operators to assess 
the economic and technical impacts of plans for decommissioning large methane network assets 

205 Council Regulation (EU, Euratom) No 617/2010 of 24 June 2010 concerning the notification to the 
Commission of investment projects in energy infrastructure within the European Union and repealing Regulation 
(EC) No 736/96 
206 DNV GL for CEER (2018) Study on the Future Role of Gas from a Regulatory Perspective 

80 

 
 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

could be included in EU legislation. Divestment plans related to networks with cross-border impact 
should also be included in the network development plans, and the concerned  neighbouring 
Member States should be consulted.207 If combined with appropriate cross-energy carrier network 
planning, this would minimise the risks that methane pipelines were decommissioned that could 
better be repurposed for hydrogen transport.  

Cross-border network planning 

The options for cross-border network planning obligations reflect an increasing level of obligation 
on hydrogen network operators to cooperate at supra-national level, from no cross-border planning 
required (option A) to developing network development plans at the regional (option B) or even EU 
level (option C). 

Table 3-12 Cross-border network planning  

Option A 

Option B 

Option C 

Options 

No cross-border planning 
obligations 

Regional planning 

EU-level planning 

Advantages 

 Low planning costs 

 Increased integration 

 Increased integration 

Disadvantages / 
risks 

 Lack of coordination for 
cross-border planning 

Mitigation 
measures 

 Incentivise regional 
cooperation 

 Risk of uncoordinated 
regional plans 
 Unnecessary for smaller 
system scales 
 Medium planning costs 

 Migrate to regional planning 
when national systems are 
forecasted to be 
interconnected 

 High planning costs 
 Unnecessary for smaller 
system scales 

 Migrate to EU-level planning 
when regional systems are 
forecasted to be 
interconnected 
 Combine and check 
consistency of regional plans 

Cross-border network planning should take place at the foreseen level of network development 
during the planning horizon. Hence, as regional hydrogen systems are forecasted to be developed 
in the following e.g. 10 years, the relevant network operators should cooperate in developing 
regional network development plans. When regional networks are forecasted to be interconnected, 
plans should be developed at the EU level. These plans could initially be developed by combining 
and checking the consistency of the regional network development plans. 

Cross-border network planning of hydrogen networks will require the definition of the responsibility 
for and oversight of planning as well as consideration of cross-energy system interactions also at 
the regional or EU level. The planning process would benefit from maintaining, as far as possible, a 
similar approach for these aspects between the EU/Member States, especially for oversight and 
cross-energy system interactions. Ideally, at both the EU and national level, policy makers and 
regulators should exercise strong oversight for all regulated energy systems, and ensure that 
common scenarios and consistent CBA methodologies are used, as well as integrated or at least 
compatible energy systems models. Some countries could have a separate organisation conducting 
the overall planning, while in others planning could be done by network operators. 

3.5.2 Natural gas as a basis for hydrogen network regulation: Network planning 

Under the current EU regulatory framework, there is no obligation to develop a single gas NDP in 
countries where more than one TSO operate. However, current practices in countries with several 
gas TSOs indicate that national regulatory frameworks require in general the development of 
consolidated national NDPs. The view that consolidated NDPs are beneficial for consistent gas 
network development is also supported by ACER208. 

There is also a difference across the Member States in the level of involvement of NRAs in network 
planning. “In about 40% of the instances, NRAs are formally empowered, albeit in differing ways, 
to approve, reject or validate the NDP proposals of the TSOs, and in some cases the NRAs also 
carry out a consultation process on the draft NDP”209. 

207 ACER and CEER (2019) The Bridge Beyond 2025 Conclusions Paper 
208 ACER (2016). ACER opinion on gas network developments: Review of national network development plans to 
assess their consistency with the EU TYNDP. Available at: 
https://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Opinions/Opinions/ACER%20Opinion%20
14-2016.pdf 
209 ACER (2018). ACER opinion on the review of national network development plans to assess their consistency 
with the EU TYNP. Available at: 

81 

 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Apart from the process of network planning, there are different elements that can be considered 
when developing the NDPs: 

  As noted by ACER210, the current NDPs often lack coordination on cross-border projects, for 

example on their planned capacity and timing of their construction. This problem could be 
avoided by enhancing the involvement of neighbouring Member States in the consultation 
process; 

 

 

There is a difference between Member States in the consideration of innovative solutions in 
the planning process. One issue is the potential bias towards CAPEX-based solutions, 
versus efficiency-oriented OPEX-based solutions. CAPEX-based solutions might be favoured 
by TSOs as they increase their RAB value and hence their remuneration. The risks 
associated with innovative projects might in some national frameworks not be properly 
valued and TSOs might be deterred by penalties for not meeting deadlines. The regulatory 
frameworks also often lack incentives for applying efficiency measures211; 

The NDPs can differ in their approach relative to other infrastructure, in particular 
electricity networks. The options include: 1) separate development of scenarios for each 
sector 2) developing common future scenarios 3) developing interlinked development plans 
(based on common scenarios) 4) developing common NDPs for all sectors. Currently, the 
second option is applied on the EU level and work on applying interlinked TYNDPs is in 
progress. The EU-wide approach however focuses mainly on cross-border capacities, not on 
network development within Member States. Given the increasing need for coordination of 
electricity and gas network development and possibly conflicting TSO interests, at least 
common scenarios aligned to the National Energy and Climate Plans (NECPs)212 should be 
required.  

Furthermore, there is currently no planning obligation for DSOs in the EU legislation. DSO-related 
planning aspects are discussed in section 3.8. 

Option development 

Option A involves having no oversight of network planning (however, authorities still approve 
investment projects, which are included in RAB), or oversight limited to a consultation role (e.g. 
NRAs and/or policy makers providing an opinion or organising a consultation process). Option B 
empowers the authorities to approve the NDP. In option C, next to the approval of the NDP by the 
authorities, they also have an oversight role regarding the scenario building. In option D, the TSOs 
would be required to develop scenarios that follow policy goals (for example NECP scenarios). In 
this option, the authorities would be empowered to approve the scenarios and NDPs, and also 
mandate changes in the scenarios to ensure coherence with the policy goals. 

Next to the sectoral network development, there are also several possibilities for cross-sectoral 
planning. The NDPs form a basis for creating an EU-wide TYNDP, which is developed by ENTSOs 
and based on their own development scenarios. As the decision has been taken to agree on 
common scenarios for future electricity and gas TYNDPs, the implementation of common 
electricity-methane-hydrogen scenario formulation on EU level is feasible. The regulators are also 
calling for better alignment of these scenarios with policy goals.  

Because of the additional European-level layer of planning, even the options with less oversight (A 
and B) will be partially based on cross-sectoral impact considerations. In the options C and D, the 
authorities have the power to approve/amend the scenarios, so they might decide to require cross-
sectoral planning if necessary (weighing the potential cost and benefits of such exercise). In the 
option D, the scenarios should ideally be based on policy scenarios, which would consider to some 
extent cross-sectoral interactions.  

https://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Opinions/Opinions/ACER%20Opinion%20
11-2018%20on%20the%20review%20of%20national%20NDPs%20consistency%20with%20EU%20TYNDP.pdf 
210 Ibid 
211 EC (2019). Do current regulatory frameworks in the EU support innovation and security of supply in 
electricity and gas infrastructure?. Available at: https://op.europa.eu/en/publication-detail/-
/publication/6700ba89-713f-11e9-9f05-01aa75ed71a1 
212 ACER (2019). The Bridge beyond 2025 conclusions paper. Available at: 
https://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/SD_The%20Bridge%20beyond%202025/
The%20Bridge%20Beyond%202025_Conclusion%20Paper.pdf 

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Sector integration – Regulatory framework for hydrogen 

Table 3-13 Network planning options based on natural gas regulatory frameworks  

Network 
planning 

Option A 

Option B 

Option C 

Option D 

Option 

Network planning a 
TSO responsibility 

Approval of NDPs 

Approval of 
scenarios and NDPs 

Advantages 

  Enables more 
flexibility in 
development of 
the network plan 

  Oversight of 
efficient 
investment still 
possible but 
enables initiative 
of industry 

Disadvantag
es / risks 

  Scenarios 

developed to 
reflect TSO’s 
interest, lack of 
transparency 

  Permitting 

process may be 
more difficult 
  Supply of NG to 

consumers might 
be stopped if TSO 
decides to switch 
to H2 

  Lack of 

transparency in 
scenario 
development 

  May enable 
oversight of 
conversion from 
NG to H2 
infrastructure – 
ensuring supply 
to limited groups 
of consumers 
  Possible to align 

network planning 
with policy goals 

  Resources 

invested in the 
process might 
outweigh 
potential benefits 
(especially when 
considering 
cross-sectoral 
impacts) 

Mitigation 
measures 

  Checking the 

  Checking the 

results against 
the EU TYNDP 

results against 
the EU TYNDP 

   

Network planning 
follows policy goals. 
Approval of 
scenarios and NDPs. 

  Scenarios reflect 

policy goals 

  Network planning 

aligned with 
policy goals 
  Decreases risks 

of 
overinvestment/s
tranded assets as 
future needs are 
defined 
independently 

  Scenarios 

possibly less 
ambitious than 
network 
operators’ 
expectations 

  Resources 

invested in the 
process might 
outweigh 
potential benefits 
(especially when 
considering 
cross-sectoral 
impacts) 

  Proper 

consultation 
process when 
developing 
scenarios 

Network charges can be separated in connection and access charges, the latter being called use of 
system charges. Balancing of energy systems and recovery of balancing costs are discussed in 
more detail in chapter 4. It is not straightforward to determine an adequate network connection 
and access charging structure, as it must satisfy conflicting tariffication principles, especially cost 
reflectivity, cost recovery, non-discrimination, transparency, predictability and simplicity.213 

The challenge lies not only in properly balancing these principles, but also in satisfying them 
individually. For example, perfectly assuring cost reflectivity is impossible as not all network costs 
can be directly assigned to a specific network user (group) and thus should partly be socialised. For 
instance, while a new connection may require the reinforcement or extension of the network, other 
existing or future network users may also benefit from these investments. 

Also, shallow connection cost allocation approaches may be used by policy makers and regulators 
to reward specific network technologies which provide environmental or system benefits, such as 
renewable energy or storage projects. Network charges (also for access) should be cost-reflective, 
and preferentially not used to promote specific policy objectives (which can better be implemented 
through other instruments). Hence, any network tariff design is not perfectly cost-reflective, both 
due to the inability to fully define cost causality, and to conflicting tariffication principles such as 
the need for stability and transparency of the tariffs. 

The setting of network access charges is directly linked to the approach on network access, as so-
called regulated vs negotiated third-party access will imply a different level of regulatory oversight. 
Nonetheless, regulated network tariffs should be cost-reflective, transparent and non-
discriminatory. 

213 Trinomics et al. (2020). Energy costs, taxes and the impact of government interventions on investments. 
Final report – network costs. 

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Sector integration – Regulatory framework for hydrogen 

Cost-reflective network charges also serve to provide appropriate incentives to network users to 
take investment and operation decisions which minimise total system costs. To this end, charges 
may contain locational and time-related components aiming at providing such incentives. Further 
measures can be applied to gas network charges, such as specific discounts to certain network user 
groups, such as storage and users with specific utilisation profiles, e.g. power plants or industry. 

Regulated network access charging in gas systems can employ an entry-exit or point-to-point 
approach. In an entry-exit system, “network users book capacity at entry points and exit points 
independently. Gas can be injected at entry point and made available for off take at exit points on 
a fully independent basis. The gas does not follow a predefined contractual path. The entry-exit 
system has a virtual trading point where gas can change ownership within the system.”214 
Alternatively, point-to-point access charging defines tariffs according to the contractual path of the 
gas. Entry-exit systems with transparent tariffs facilitate gas trade by providing flexible and non-
discriminatory access to network users within a system, as well as across multiple systems using 
entry-exit tariffs. Both approaches, if well designed, could be suitable for the hydrogen market, and 
allow market operators to conclude long-term supply and capacity contracts. Risks for potential 
contractual congestion should be mitigated by adequate regulation (UIOLI) and physical 
bottlenecks should timely be eliminated by network investments. 

Network charging and dedicated hydrogen networks 

As network charges serve to recover not only O&M but also depreciation costs, and to remunerate 
capital, they are directly related to investment levels, especially in a context of strong network 
development, which is expected to be the case in some countries and regions with large-scale 
deployment of dedicated hydrogen infrastructure.  

The biomethane and hydrogen study215 estimated a tariff of around 1.6 €/MWh for hydrogen 
transmission in 2050 in the hydrogen scenario, which is quite similar to the current natural gas 
transmission tariff. However, the results are dependent especially on the chosen OPEX levels and 
cost of capital, and will differ for specific Member States. Tariffs for the recovery of hydrogen 
network investments and related OPEX could be partly compensated by lower costs for methane 
networks, if the former are developed mainly by repurposing methane networks.  

Network tariffs should be cost-reflective, which requires considering the long-term costs of 
hydrogen systems as well as the flexibility benefits that electrolysers and hydrogen storage can 
provide. Early users of dedicated hydrogen systems should not be penalised for following national 
strategies and contributing to decarbonisation. These early users will furthermore enable the 
system build-up (and consequently technical and regulatory learning leading to cost reductions) 
from which later users will also benefit. It will be also important that hydrogen network access 
charges are stable and predictable. Distribution aspects related to the potentially different user 
groups of methane and hydrogen networks need also to be considered, and are further analysed in 
section 3.4 above.  

Network tariffs should be cost-reflective, which requires considering the long-term costs of 
hydrogen systems as well as the flexibility benefits that electrolysers and hydrogen storage can 
provide. Early users of dedicated hydrogen systems should not be penalised for following national 
strategies and contributing to decarbonisation. These early users will furthermore enable the 
system build-up (and consequently technical and regulatory learning leading to cost reductions) 
from which later users will also benefit. It will be also important that hydrogen network access 
charges are stable and predictable in order to allow the necessary investments by market actors.  

In case of strong electrification facilitated by hydrogen deployment and shift of natural gas users to 
dedicated hydrogen systems, the remaining natural gas users could face an important increase of 
the grid tariff, as transported volumes and the number of connected users would substantially 
decrease. The effective impact will depend on the rate of methane network defection compared to 
the rate of depreciation and capital remuneration costs, as well as the fixed O&M. To reduce this 
risk, any new investment in natural gas infrastructure should be thoroughly assessed. Possible cost 
reallocation between the electricity, methane and hydrogen sectors as well as issues concerning 
tariff levels for early adopters and followers are further discussed in section 3.4. 

Stakeholders’ opinions 

Stakeholders have provided limited comments regarding network charging practices. Generally, 
stakeholders are in favour of the regulation of tariffs for new hydrogen networks, while many 

214 KEMA et al. (2013) Study on Entry-Exit Regimes in Gas. Part A: Implementation of Entry-Exit Systems 
215 Trinomics, LBST and E3-M (2019) Impact of the use of the biomethane and hydrogen potential on trans-
European infrastructure 

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Sector integration – Regulatory framework for hydrogen 

recognise exemptions from regulated access and tariffs could be granted to existing private 
hydrogen system operators. Some support the provision of these exemptions on a case by case 
basis, while others indicate that existing private operators should not be legally obliged to e.g. 
unbundle and offer third-party access. 

A stakeholder highlighted a commonly supported view that tariff setting for hydrogen infrastructure 
should not be seen in isolation, but should also consider the natural gas systems, for example to 
properly take into account the cost-effectiveness of converting natural gas infrastructure to 
hydrogen, and the need to address the eventual residual value of decommissioned natural gas 
infrastructure. 

According to this stakeholder, the decisions on incentives are a responsibility of policy makers, but 
such incentives should foster competitive markets and provide adequate investment signals rather 
than distort markets, including by avoiding cross-subsidisation between energy systems. A network 
operator is however of the opinion that subsidies to hydrogen network investments would keep 
tariffs for early hydrogen adopters at moderate levels, and could be justified by the environmental 
benefits of dedicated hydrogen systems. 

Another stakeholder indicated that it will be necessary to ensure that consumers with limited choice 
(e.g. who cannot put the upfront capital for efficiency measures and heat pump investments) can 
still have access to several options.  

Some energy exchange operators highlighted the importance of introducing virtual trading points 
(VTP); the experience in the natural gas market shows that this instrument has a positive impact 
on market liquidity. They moreover support the definition of a market area manager to manage 
balancing and the trading notifications from the market operators. 

3.6.1 Greenfield hydrogen regulation: Network charging 

The main relevant aspect regarding hydrogen network charges is whether such charges will be 
based on the point of entry and exit, or on the contractual path (and whether this will be defined at 
the EU level or not). This is reflected in the three options for network charging below. The choice 
between regulated and negotiated tariffs is discussed in section 3.3. 

Table 3-14 Network charging model options  

Options 

No harmonisation 

Option A 

Option B 

Entry-exit 

Option C 

Path-based 

Advantages 

 Flexibility for Member States 

 Lower transaction costs 
 Provides locational signals 
for entry and exit congestion 
of domestic and 
interconnection points 

 Provides locational signals 
for path congestion 
 Possible with highly 
decentralised network 
operation 

Disadvantages 
/ risks 

 Lack of harmonisation 
hampering cross-border trade 

 Tariff pancaking 
 Higher congestion 
management required 

Mitigation 
measures 

 Harmonisation once cross-
border integration develops 

 Appropriate entry-exit area 
design and review 
 Monitor tariff levels 

 Higher transaction costs, 
increasing with system 
complexity 
 Ex-post costs in case of 
migration to an entry-exit 
system 
 Not harmonised with current 
natural gas entry-exit model 

 Develop capacity allocation 
platforms 
 Use NC-like process to 
migrate to entry-exit 
according to market maturity 

While an entry-exit model facilitates trade via large networks, it may increase the need and cost of 
congestion management and require coordination with multiple network operators in case of 
decentralised networks. In contrast, a path-based model can better reflect physical network 
constraints in trading and thus reduce congestion, including in a highly decentralised network, at 
the cost of higher transaction costs for market participants, which would increase with system 
complexity. However, in the case of significant repurposing of methane networks, there might be 
some overcapacity (despite the lower energy content of hydrogen), reducing congestion concerns 
and the need for congestion management. This will depend on the capacity of the compressors, 
which would most probably be dimensioned based on the foreseen transport demand (with some 
margin), and thus significant over-dimensioning of hydrogen networks is unlikely. 

85 

 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Path-based charges are currently applied in the US methane sector with adequate contractual and 
coordination measures in place to facilitate trade, leading to a highly liquid market.216 Also, while 
entry-exit areas can facilitate the development of liquid markets, their benefits would be less 
important if a significant share of hydrogen supply was committed in bilateral long-term contracts, 
for which the transaction costs to assure transport capacity in a path-based approach would be less 
significant. Furthermore, as the major share of the EU hydrogen production would be domestic, 
hydrogen cross-border transit would be less important compared to natural gas, which could also 
justify the use of path-based charges. 

Hence, the most adequate model will depend on the scale of hydrogen networks and markets, their 
interconnection level, the advantages of having a harmonised approach between hydrogen and 
methane networks as well as the acceptability of higher congestion costs and their eventual 
socialisation among network users.217 The experience with the harmonisation across the EU of the 
entry-exit model with the third energy package suggests that, when the hydrogen system grows 
and becomes more interconnected, it would still be possible to migrate to a harmonised solution, 
albeit with significant costs. 

If either the entry-exit or the path-based system were defined by EU legislation, harmonised tariff 
principles could be defined. In the case of an entry-exit system, these principles could be set for 
interconnection and/or domestic points. The latter could be justified to avoid cross-subsidisation 
between intra- and cross-system flows, or at least a cross-subsidisation test could be required, 
such as in the TAR network code. Cross- and intra-system flows in each market area may differ 
significantly, according to the area hydrogen demand, production, imports and exports. 

Whatever the system used, it will be important to ensure that market parties are incentivised to 
balance their portfolios as much as possible, by using bilateral transactions and with TSOs 
employing market-based mechanisms for providing linepacking services to market participants and 
managing congestions.  

Principles in network charging 

Access tariff structures for hydrogen network users should, as for other energy infrastructure, 
reflect the drivers of the cost of service. Hence, if hydrogen networks exhibit similar economic 
characteristics as natural gas networks, such as high fixed costs, the use of mainly fixed and 
capacity related tariff components would be sensible. The most appropriate tariff structures could, 
however, be significantly different for individual Member States, depending on aspects such as the 
share of domestic vs imported hydrogen, the level of coupling with the electricity and methane 
systems, and the use of domestic infrastructure for hydrogen transit. 

In a context of strong network development and connection of new network users, the use of 
appropriate signals to consumers to reflect system constraints could improve investment and 
operational decisions and thus facilitate the roll-out of hydrogen networks. However, while 
significant experience has been gained in the electricity and natural gas sectors in employing 
locational and time-related signals in tariffs, the strength of eventual incentives to network users 
needs to be weighed against the final impact on their decisions (considering also the relative 
importance of the energy and taxation component in final hydrogen prices) and the added 
complexity that such signals would bring. 

Generally, the principle of not using network charges in order to support policy objectives should 
be followed also for hydrogen networks. Economic support to hydrogen deployment would best be 
implemented by support mechanisms to producers and consumers, rather than by reduced network 
tariffs, as the latter would reduce cost-reflectivity. Eventual re-allocation or subsidisation of the 
cost of service of hydrogen network operators could nonetheless be envisaged to reflect the 
positive externalities as indicated above, and serve to (partially) recover investments proportionally 
to the benefits derived from hydrogen networks.  

3.6.2 Natural gas as a basis for hydrogen network regulation: Network charging 

The 2009 Gas Directive established entry-exit tariffs as the standard model across the EU. The 
network charging based on Articles 13 and 14 of the Gas Regulation was further developed in the 
TAR network code. The Gas Regulation states i. a. that the tariffs shall be transparent, reflect the 

216 Hallack et al. (2013) European Union regulation of gas transmission services: Challenges in the 
allocation of network resources through entry/exit schemes 
217 Hallack et al. (2013) European Union regulation of gas transmission services: Challenges in the 
allocation of network resources through entry/exit schemes 

86 

 
 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

actual cost incurred and be non-discriminatory. The TAR NC sets the requirements (based on the 
Gas Regulation) for setting the reference tariff methodologies. The methodologies should: 

 

Take into account the actual costs; 

  Ensure non-discrimination and prevent undue cross-subsidisation; 

  Ensure that significant volume risk is not shifted from cross-system to intra-system use; 

  Ensure that reference prices do not distort cross-border trade. 

The only entry or exit points that are allowed to benefit of a grid tariff discount are storage and 
LNG facilities. 

In 2018, 20 (out of 22 analysed) Member States had a majority capacity component in 
transmission access tariffs, 6 of them having only capacity components in their access charges. 
Since the NC TAR entered into force, new tariff regulation is being put in place in Member States. 
The trend is only highlighting the shift to a greater share of capacity-based charges, with 9 
countries applying no commodity charges in the new regulatory periods. Most of the Member 
States currently apply an entry/exit cost allocation split that relies more on withdrawal charges 
(e.g. over 50% of costs recovered from withdrawal charges)218. 

Most of the Member States apply shallow network connection charges (both on transmission and 
distribution level), and some use super-shallow connection charging. Only 5 Member States apply 
deep connection charges.219 

Option formulation 

Application of the natural gas regulatory framework for hydrogen would imply the use of entry-exit 
charges for hydrogen network tariffs. The advantages and disadvantages of an entry-exit model 
compared to one based on the contractual path are discussed above. 

The application of the TAR NC to hydrogen would further restrain hydrogen transmission tariff 
methodologies to providing discounts only to storage and LH2 facilities and to be capacity-based, 
among others.  

Similar to the options for revenue regulation, the options for network charging can be distinguished 
by determining whether the charging methodologies for both networks would be the same or could 
be different. A single regulatory account for methane and hydrogen networks would imply that the 
same charging methodology is employed (although methane and hydrogen network users could be 
treated as separate user groups in the methodology). If separate regulatory accounts for methane 
and hydrogen networks are employed, the same charging methodology could still be employed. 

Having a single charging methodology might be counter-productive in countries that have different 
patterns of production/consumption for natural gas and hydrogen. For example, Southern 
European countries are at present pure importers of natural gas, but could become important 
hydrogen producers and even exporters. Similarly, some countries that have an important transit 
role for natural gas might not be in the same position for hydrogen (e.g. countries on important 
transit routes from Russia). For such countries, having different entry/exit or transit/domestic split 
might be important to cover accurately the incurred costs and avoid cross-subsidisation. 

Given the similar technical and economic characteristics of natural gas and hydrogen networks, 
employing similar principles for the charging methodologies of both networks could be sensible, 
such as the use of mainly capacity-based tariffs (electricity costs for compression can represent a 
significant share of total OPEX costs, this could be counterbalanced by the over-dimensioning of 
pipelines and the fixed depreciation and capital remuneration costs). However, the use of the same 
charging methodology for both carriers seems too restrictive and would not allow for tariff 
structures to reflect important differences in patterns of supply, transport, storage and 
consumption. 

218 Trinomics et al. (2020). Energy costs, taxes and the impact of government interventions on investments. 
Final report – network costs. 
219 Trinomics et al. (2020). Energy costs, taxes and the impact of government interventions on investments. 
Final report – network costs. 

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Sector integration – Regulatory framework for hydrogen 

Table 3-15 Network charging options based on natural gas regulatory frameworks  

Network charging 

Option A 

Option B 

Tariff methodologies 

Single tariff methodology 

Advantages 

Disadvantages / risks 

Mitigation measures 

  Reduced administrative burden 
  Allows sharing of risks and costs 
  Beneficial for minority of consumers 

(H2 at start, later NG) 

  Technology-neutral 

  Cross-subsidisation likely 
  Cannot account for different patterns 
of natural gas and hydrogen supply, 
transport, storage and consumption 

  Allow differences for certain tariff 

design parameters 

Separate tariff methodologies (with 
mirroring of principles allowed) 

  Tailored charging approaches for NG 

and H2, reflecting different role in MS 

  Transparent tariff methodology, 

reduces risk of cross-subsidisation 

  Divergence between methane and 
hydrogen tariff methodologies  

  Mirror methodology principles 

Capacity allocation concerns the procedures for allocating the transport capacity of the network. 
Specifically, this refers to the transport capacity at interconnection points between different areas 
in the case of an entry-exit system, while point-to-point (path-based) systems require the 
allocation of capacity along the contractual path.  

Capacity allocation may make use of capacity products standardised by duration (from yearly to 
quarterly, monthly or less), interruptibility and unit (e.g. MW), traded (or not) via centralised 
platforms employing e.g. capacity auctions. Capacity may be allocated, however, for longer 
periods, with long-term contracts established for multiple years ahead. Capacity allocation may 
also comprise bundled products, where transport capacity at both sides of an interconnection point 
is jointly offered (i.e. the right to withdraw gas on one side and inject it on the other).  

Capacity allocation procedures may foresee mechanisms for incrementing transport capacity, e.g. 
realising investments in new / upgrading of pipelines or in cross-border reverse flow capacities. 
Such mechanisms involve calls for interest from market participants for additional capacity, who 
eventually commit to contracting future incremental capacity arising from investments by the 
network operator(s). 

Congestion management refers to the rules for addressing eventual contractual or physical 
congestion in the network due to insufficient network capacity. Congestion management 
procedures may use mechanisms such as long- or short-term use-it-or-loose-it conditions, or the 
obligation for market actors to return unused capacity to be reallocated to other actors, as 
currently foreseen in the gas capacity allocation mechanisms network code. These mechanisms 
should ensure that transport capacities are efficiently employed, allowing shippers to trade capacity 
rights and re-nominate them. 

CACM and dedicated hydrogen networks 

Capacity allocation and congestion management rules should aim to improve non-discriminatory 
access to the network, maximise the efficiency of network utilisation, and reduce contractual and 
physical congestion while minimising the cost of necessary congestion management measures such 
as re-dispatching. 

CACM rules design will also depend on whether an entry-exit or point-to-point model is employed 
for each specific system. Nonetheless, regardless of the model, rules will be necessary for both 
cross-border and domestic congestion management, and allocation rules at least for cross-border 
capacity.  

Long-term capacity bookings may lead to the foreclosing of access to other network users, if they 
represent a relevant share of total network capacity, and in the absence of measures to ensure 
actual utilisation of the capacity, such as use-it-or-lose-it (UIOLI) rules. However, as long-term 
hydrogen supply agreements should play an important role in fostering new hydrogen production 
capacity, market actors will want to have sufficient secure transport capacity. Hence, CACM rules 
will need to consider the need to provide non-discriminatory access to the network, optimise its 
utilisation, enable liquid hydrogen markets as well as provide certainty for long-term investments 
in hydrogen supply. Ideally, capacity allocation using market-based instruments would be 
employed facilitating cross-border trade with the use of e.g. bundled products, with a liquid 
secondary market for market actors to trade capacity. 

88 

 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Coupling of market areas could further facilitate trade, while congestion management could be kept 
manageable if constraints at interconnection points were adequately represented when clearing the 
market. Also, initially hydrogen clusters would potentially not be interconnected, although a clear 
Hydrogen Target Model could provide guidance to Member States regarding the development of 
regulation once their hydrogen clusters become interconnected (addressed in section 3.9).  

Stakeholders’ opinions 

Network operators and market actors highlighted that, based on the experience from the natural 
gas sector, there are benefits of cross-border harmonisation of CACM rules and considered that the 
approach of the relevant gas network codes would be applicable and appropriate for hydrogen 
networks. One stakeholder noted that uncoordinated actions by Member States and voluntary EU 
guidelines in the past were not able to efficiently contribute to harmonisation. Stakeholders also 
highlighted that interoperability agreements for different areas are necessary to foster cross-border 
trade. One stakeholder noted that while some specific rules cannot be applied to hydrogen yet as 
there is no existing market, they should be timely foreseen as the development and amendment of 
network codes is a lengthy process. 

3.7.1 Greenfield hydrogen regulation: Capacity allocation and congestion management 

The main question regarding capacity allocation and congestion management is whether CACM 
rules for hydrogen interconnection and/or domestic points should be harmonised at EU level, and 
whether a hydrogen market coupling mechanism should be employed. The applicable CACM rules 
will be dependent of the charging system chosen: entry-exit or path-based (discussed in section 
3.6). 

Thus, the main options considered below comprise: 

  Option A: No CACM harmonisation at EU level 
  Option B: Harmonised rules for cross-area CACM 
  Option C: Harmonised rules for cross-area CACM and for domestic congestion 

management 

  Option D: Market coupling (for an entry-exit system) 

Table 3-16 CACM options in the EU hydrogen regulatory framework 

CACM 

Option A 

Option B 

Option C 

Option D 

Harmonisation of 
rules and market 
coupling 

No harmonisation of 
CACM at EU level 

Rules for cross-area 
CACM 

Advantages 

  Flexibility for MSs 

  Improved market 

integration 

  Harmonised CACM 
for different IPs 

Rules for cross-are 
CACM and domestic 
congestion 
management 

  Improved market 

integration 

  Harmonised CACM 
for different IPs 
  No discrimination 

of domestic/foreign 
users 

Disadvantages / 
risks 

  Divergence of CACM 

for different IPs 

  Higher complexity    Higher complexity 

Mitigation measures 

  Development of 

CACM NC/GL later on 

  Provide a menu of 

  Provide a menu of 

options for TSOs to 
address 
contractual 
congestion 

options for TSOs to 
address 
contractual 
congestion 

Market coupling 

  Lower transaction 
costs for trading 
  Incentivises cross-
border trade by 
eliminating tariff 
pancaking 

  May lead to higher 

congestion 
management costs 

  Administrative 

costs for market 
coupling 

  Monitor tariff levels 
  Initially couple 

market areas with 
significant IP 
capacity 

While options A-C are mutually exclusive, market coupling considered in option D would necessarily 
require the harmonisation of CACM rules proposed in options B and C. The market coupling process 
is further detailed in Box 3-11 above. Harmonisation of domestic congestion management rules 
could be justified if there was a relevant risk or demonstration that hydrogen network operators 
were discriminating cross-area flows to relieve internal congestion.  

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Sector integration – Regulatory framework for hydrogen 

3.7.2 Natural gas as a basis for hydrogen network regulation: Capacity allocation and 

congestion management 

If the EU natural gas regulatory framework would be employed as a basis for hydrogen regulation, 
the main design questions concerning CACM would be whether to employ the same CAM network 
code and CMP guideline, and also the same CACM mechanisms (auction platforms, capacity 
products, congestion mechanisms (UIOLI, etc). The following CACM options can be thus be 
derived: 

  Option A: Employing the same CAM NC and CMP GL, as well as the same CACM 

mechanisms foreseen in these; 

  Option B: Employ the same CAM NC and CMP GL, but with separate mechanisms for 
CACM, allowing for some flexibility to account for the hydrogen sector specificities; 

  Option C: Develop separate CACM network codes/guidelines for hydrogen, while 
employing a similar development and amendment process as for natural gas. 

Table 3-17 CACM options based on natural gas regulatory frameworks  

CACM 

Option A 

Option B 

Option C 

Network codes 

Same CAM NC and CMP GL 

Same CAM NC and CMP GL 

Same development and 
amendment process, 
different NCs/GLs 

Separation of auction 
platforms, capacity 
products, congestion 
mechanisms (UIOLI, 
etc) 

Same as for methane  

Separate for hydrogen and 
methane  

Separate for hydrogen and 
methane 

Advantages 

  Lower administrative costs  
  Tested & proved CAM NC 

and CMP GL 

  Medium flexibility in 
products/platforms/ 
mechanisms for different 
stages of network 
development and 
integration 

  Full flexibility for stages 
of hydrogen network 
development 

  Tested & proved NC/GL 

development & 
amendment process 

Disadvantages / 
risks 

  Lack of flexibility for 

  Menu of 

different stages of network 
development and integration 

products/platforms/ 
mechanisms is the same 

Mitigation measures 

  Add new optional capacity 

  Add new optional capacity 

products/congestion 
mechanisms 

products/congestion 
mechanisms 

  Regulatory cost for NC/GL 

development 

  Potential diseconomies of 

scale 

  Coordination in CH4/H2 
NC/GL development 

  Use of same CACM 

platforms for economies 
of scale 

While Option A would allow to employ established regulation and mechanisms for CACM of 
hydrogen systems and potentially could provide economies of scale in managing the necessary 
CACM mechanisms, there is a significant risk that the mechanisms would not be sufficiently tailored 
to the specific characteristics of the hydrogen system (such as different supply and demand 
profiles, interlinkages with the electricity system, share and length of long-term capacity contracts, 
market liquidity). Option B could allow e.g. certain congestion management mechanisms to be 
applied separately for the methane gases and hydrogen systems, or for capacity products to be 
tailored to the hydrogen system. Finally, option C would employ the tested network code/guideline 
process to elaborate and amend hydrogen CACM rules. Hence, capacity products, congestion 
mechanisms and even the platforms for allocating capacity and managing congestion could be 
tailored to the hydrogen system. While the benefits arising from the design flexibility could be 
significant, employing the same CACM platforms could be beneficial as it would lead to economies 
of scale due to sharing of fixed costs, and could thus be considered. 

This section discusses specific adaptation and mitigation measures to the regulatory elements 
analysed above, that should be considered for hydrogen distribution networks. Plans exist for a 
relatively fast development of a European hydrogen transmission backbone and it is likely that 
many of the first future hydrogen networks will mainly serve to supply large industrial consumers. 
Nonetheless, the future EU regulatory framework for hydrogen should consider the regulation of 
hydrogen distribution networks as well, given that projects already exist to convert methane gases 
distribution networks to hydrogen, and that hydrogen distribution networks may exhibit significant 
differences to their present methane counterparts, given e.g. the fact that PtG may lead to 
significant hydrogen injection at distribution level. The table below indicates the aspects regarding 
the regulatory elements analysed above, and the possible mitigation measures and adaptions to 

90 

 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

the regulatory options which could be adopted. Balancing is also included in this table, but is more 
extensively addressed in the next chapter. 

Table 3-18 Common/different aspects for hydrogen distribution networks 

Regulatory 
element 

Main differences to transmission / 
other energy sectors 

Possible mitigation measures / 
adaptations 

Overarching 

Unbundling 

  Transmission and distribution roll-out 

will differ per MS 

  Competition with alternative hydrogen 

transport modes differ 

  Conversion of distribution pipelines 

may be easier for many MSs  

  Adapt potential exemptions/waivers to 
distribution, with/without regulatory 
test: emergent/isolated markets, 
closed distribution systems, direct 
lines, major hydrogen distribution 
infrastructure 

  Gas Directive allows exemption/waiver 

to DSOs serving less than 100 000 
customers 

  Gas Directive exemption to closed 

distribution systems 

  Eliminate or lower the customer 
threshold for hydrogen DSOs 

  Require account unbundling for all 

hydrogen network operators 

  Enforce unbundling from hydrogen 

production for all network operators  

Network access 

  Gas Directive exemption for closed 

distribution systems 

  See overarching category 

  No TYNDP or national planning 

obligations 

  Mandate coordination between DSOs 

and TSOs for planning of infrastructure 
needs and decision for connection of 
users 

Network planning 

  No hydrogen EU DSO entity as in 

  Mandate obligation for DSO planning 

electricity 

Revenue regulation 

Network charging 

  Differences by MSs between TSOs and 

DSOs in approaches / various 
regulatory parameters 

  No TAR NC 
  Path-based and entry-exit systems not 

applicable 

mirroring new electricity market design 

  Create hydrogen EU DSO entity / 

inclusion of hydrogen in mandate of 
electricity EU DSO entity 

  Promote best practices / benchmarking 

between NRAs 

  Harmonise minimum charging 

principles 

CACM 

Balancing 

  Flexibility resources may be necessary 

  Establish principles for DSOs 

to deal with congestion 

contracting flexibility resources 

  DSO-connected balancing resources 

may be significant 

  Integrated DSO-connected balancing 

resources in balancing markets 
through TSO-DSO cooperation 

The hydrogen sector will develop with different speeds in the EU Member States, each country or 
region following one of the pathways developed in chapter 1. Nonetheless, hydrogen networks are 
incipient in all Member States, despite private networks existing in North-Western Europe. Hence, 
the hydrogen network and market regulation discussed in this study will need to be gradually 
implemented, while simultaneously providing guidance to market and regulated actors, and 
assuring regulatory stability. Additionally, significant technological and business model innovation 
still needs to occur in the hydrogen (and generally the energy) sector. 

To address these needs, the hydrogen sector regulation at the EU and Member State levels need to 
incorporate two design principles: 

 

Transitional measures, to pace regulatory requirements to the stages of market 
development, while at the same time providing clear guidance to all stakeholders on future 
regulation; 

  Regulatory experimentation, to promote regulatory learning and sharing of the most 

adequate practices, and address cases requiring particular treatment (see Box 3-12 for a 
typology of regulatory experimentation mechanisms). 

At the EU level, a number of main measures could be considered in this regard to introduce 
stepwise the regulation, promote regulatory learning and accelerate the stages of market 
development: 

  Define a Hydrogen Target Model guiding the development of EU network codes and 
guidelines applicable for Member States with interconnected hydrogen systems, and 
enabling Member States to develop national regulation which is compatible with the model; 

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Sector integration – Regulatory framework for hydrogen 

  Derogate Member States from specific regulatory requirements until their hydrogen 

systems become interconnected across borders. This approach is similar to the provisions 
in Article 49 of the Gas Directive on emergent and isolated markets (mostly derogations 
from regulation of concessions for infrastructure developers, from unbundling, market 
opening and from regulation of direct lines).These derogations would apply to relevant 
hydrogen cross-border aspects, while provisions necessary to avoid distortions to the 
internal energy market should still be applied even for isolated hydrogen systems, given 
the coupling of local hydrogen clusters with the electricity and methane systems. 
Regulatory elements that are eligible for derogation could comprise unbundling, planning, 
and CACM requirements, while network third party access requirements should be required 
even for isolated clusters / systems. This mechanism should furthermore be designed in 
order to stimulate Member States to consider developing cross-border interconnections,220 
and to prepare the necessary national regulatory framework adaptations in anticipation of 
interconnection, according to the network development plans; 

  Define requirements for waivers and exemption procedures of hydrogen network 

operators, covering potentially pre-existing operators, direct pipelines and closed 
distribution systems; 

  Establish an EU regulatory sandbox model, which could then be employed by NRAs for 

regulatory learning in specific initiatives. 

The hydrogen regulatory framework needs to provide exemption procedures for isolated 
hydrogen systems in interconnected markets 

An important specific case should be addressed by the transitional measures listed above: that of 
isolated hydrogen systems in Member States which are not considered as isolated hydrogen 
markets. As Belgium, the Netherlands and France have already cross-border private hydrogen 
pipelines, these countries could in principle not qualify anymore as isolated hydrogen markets 
(unless the criteria would only consider networks with third party access). 

Initiatives to develop isolated hydrogen networks could arise in these countries (e.g. by converting 
certain distribution networks). These hydrogen networks would not qualify for the derogation of the 
regulatory requirements granted to isolated markets. They would also not qualify for exemption 
procedures, if these exemptions were reserved to pre-existing networks, direct pipelines and closed 
distribution systems. 

However, for isolated hydrogen networks to fully comply with the Hydrogen Target Model could be 
very costly, e.g. if networks users were responsible for their imbalances in the absence of a liquid 
hydrogen market. Other requirements would simply not apply, e.g. related to cross-area CACM. 

Hence, regulatory requirements should be phased in not only according to the hydrogen networks 
stage of development of each Member State, but also of each individual network. To address this 
issue, in addition to exemption procedures for pre-existing operators, direct lines and closed 
distribution systems, the EU regulatory framework could allow NRAs to exempt such isolated 
networks from certain regulatory requirements, according to defined criteria. 

Principles for an EU hydrogen regulatory sandbox model 

Regulatory sandboxes are not defined in EU energy sector regulation. ACER and CEER (2019) 
support the definition of a regulatory sandbox model at the EU level.221 For the financial services 
industry, the Commission has supported the development of innovation hubs and regulatory 
sandboxes in its 2018 FinTech Action plan, which was followed by a report on best practices by EU 
financial services authorities.222 

The EU hydrogen regulatory framework should address known cases deserving special treatment 
(such as potentially pre-existing or isolated clusters / systems) through waivers and exemption 
procedures. The EU regulatory sandbox model would rather serve to promote regulatory learning 
regarding aspects which are unclear at this moment and thus cannot be adequately addressed yet 
by specific legislative provisions. Once one or more sandboxes provide sufficient learning, they 

220 A concrete example of such deterrents to cross-border expansion does exist. The Electric Reliability Council 
of Texas (ERCOT) system is not synchronously connected to the rest of the US power system and its utilities do 
not sell to interstate customers, and thus ERCOT is not subject to the jurisdiction of the Federal Energy 
Regulatory Commission (FERC). See Fleisher (2008). ERCOT's Jurisdictional Status: A Legal History and 
Contemporary Appraisal; Slate (2003). Why Texas Has Its Own Power Grid. 
221 ACER and CEER (2019) The Bridge Beyond 2025 Conclusions Paper 
222 EC (2018) FinTech Action plan: For a more competitive and innovative European financial sector. 
ESMA, EBA and EIOPA (2019) FinTech: Regulatory sandboxes and innovation hubs. 

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Sector integration – Regulatory framework for hydrogen 

should end and the necessary regulatory changes (if any) made at the EU and/or Member State 
level. 

ACER and CEER propose the following characteristics for such a sandbox model: 

To specifically produce useful information of public interest on regulation; 

  Having limited duration; 
 
  As long as there is no significant risk of harm to the market; and 
  With knowledge sharing between NRAs to reduce the need for replication and accelerate 

the regulatory process. 

Regulatory sandboxes should address specific regulatory barriers hampering technological or 
business model innovation, such as new forms of investments in hydrogen infrastructure or 
efficient operation of the hydrogen system. The EU sandbox model should clearly delimit the scope 
of application (e.g. specific legislative articles from which the experiment could be exempted) and 
define requirements for the transparent, non-discriminatory design, monitoring and evaluation of 
the sandbox. 

Box 3-12 Regulatory experimentation: waivers, exemption procedures and regulatory 
sandboxes223 

Regulation can act as an enabler or a barrier to the energy transition, responding and 
anticipating developments such as strong technological innovation, the need to decarbonise our 
economies, market and system integration and the appearance of new market actors and 
applications.  

Therefore, regulatory experimentation has been drawing increased attention as a way to allow 
regulatory innovation and the required process of transparent, dynamic and inclusive trial and 
error. This without being burdened by the inertia of the regulatory process, nor making far-
reaching yet untested regulatory changes in a sector with significant importance to the energy 
and climate objectives as well as to the economy. 

FSR and CSEI (2020) identify three types of regulatory experimentation approaches: waivers, 
exemption procedures, and regulatory sandboxes. These would be characterised by the targeted 
activity or actor, the scope of exemption and the granting of exemption, as detailed below. 

Targeted activity 
or actor 

Scope 
exemption 

Waiver  

Strictly defined 

Exemption procedure 

Strictly defined 

Regulatory sandbox 

More open 

Narrow 

Narrow 

Broader 

Granting of 
exemption 

More general 

Case-by-case 

Case-by-case 

While these instruments have been employed already by NRAs in various European countries, 
the authors further note that EU directives give a larger room for bottom-up experimentation by 
Member States than regulations.  

Regulatory experiments for the development of hydrogen infrastructure are also in place or 
being planned. For example, in its hydrogen strategy,224 the German government indicates that 
it is exploring “new business and cooperation models for operators of electrolysers and for grid 
and gas network operators in line with the principle of regulatory unbundling”. The results should 
be available in 2020 and include the identification of the necessary regulatory changes enabling 
one or two model projects to “ease the burden on the grids at an affordable price without 
distorting the hydrogen market”. 

Waivers and exemption procedures are already in place in the electricity and gas regulatory 
frameworks, and their use in an hydrogen regulatory framework could build on the experience in 
these sectors.  

223 Based on FSR and CSEI (2020) Regulatory Experimentation: Waivers, Exemption Procedures and Regulatory 
Sandboxes. 
224 Federal Ministry for Economic Affairs and Energy (2020) The National Hydrogen Strategy 

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Sector integration – Regulatory framework for hydrogen 

4  HYDROGEN MARKET DESIGN AND DEVELOPMENT 

The aim of this chapter is to develop regulatory options at the EU level for the design of hydrogen 
markets. Well-functioning and liquid hydrogen markets will be key for increasing the production 
and use of renewable and low-carbon hydrogen in the EU. The development of properly functioning 
hydrogen commodity markets should allow producers, shippers and suppliers to optimally value 
their products, and for all market participants to manage their price and volume risks. Appropriate 
market functioning will depend on different aspects, such as: 

 
 
 

 

 

The size of hydrogen supply and demand 
The level of market concentration 
The availability of appropriate transport infrastructure to physically trade and supply 
hydrogen 
The existence of adequate price benchmarks and of market products from the long- to the 
short-term (forwards, futures or derivatives, spot and balancing products); 
The balancing rules and the availability of storage and other flexibility tools (e.g. virtual or 
physical conversion to and from methane-based gases and electricity) to balance supply 
and demand. 

The analysis considers the following inter-related objectives of the market design framework: 

  Stimulate hydrogen market liquidity by avoiding market fragmentation & foster renewable 

 

and low-carbon hydrogen deployment; 
Facilitate hydrogen trading through adequate market instruments, advanced market 
coupling and effective competition; 

  Reduce regulatory uncertainty, avoiding useless complexity and administrative burden. 

This chapter identifies and assesses potential measures to develop market liquidity. It is structured 
into two main sections: 

  Section 4.1 summarises the EU legal framework regarding gas markets and its relevance 
for the design of hydrogen markets, analyses the existing gas market structure and 
characteristics and identifies and assesses the relevant market design elements for 
hydrogen markets; 

  Section 4.2 develops the market design elements, assesses the potential barriers to the 

development of hydrogen markets, and proposes regulatory options to enable efficient 
hydrogen markets. 

This chapter focuses on dedicated hydrogen markets; hydrogen blended with natural gas, 
transported and sold via the natural gas infrastructure and market, is hence not addressed in this 
chapter. However, blending hydrogen with natural gas into existing methane networks is 
considered, next to the development of a dedicated hydrogen market and infrastructure, as an 
enabler to accelerate hydrogen deployment. Blending can in a transitional period represent an 
adequate solution to commercialise the output of hydrogen production facilities situated in areas 
where dedicated transport infrastructure is not (yet) available.  

4.1.1 Existing EU legal framework for gas markets and its relevance for hydrogen markets 

This section summarises the main legal provisions in the Gas Directive (2009/73/EC) and Gas 
Regulation (715/2009) related to the functioning of the gas market that may be relevant for 
elaborating an EU regulatory framework for hydrogen markets. 

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Sector integration – Regulatory framework for hydrogen 

Table 4-1 Legal provisions of the Gas Directive relevant for hydrogen markets 

Main elements 

Gas Directive 

Relevance for hydrogen  

Customer protection 

Art 3 

Authorisation 
procedure 

Art 4 – ease granting authorisations 

Closed distribution 
system 
and direct lines 

Art 28 – CDS distribute gas within a 
geographically confined industrial, 
commercial or shared services site and 
does not supply households 
Art 34 – direct lines 

Access to storage 

Art 33 – rules for access to storage (and 
obligation to make rules public) 

Record keeping 

Retail market 

Art 44 – relevant data relating to all 
transactions in gas supply contracts and 
gas derivatives with wholesale 
customers and transmission system 
operators as well as storage and LNG 
operators 

Art 45 – shall ensure that the roles and 
responsibilities of transmission system 
operators, distribution system 
operators, supply undertakings and 
customers and if necessary other 
market parties are defined with respect 
to contractual arrangements, 
commitment to customers, data 
exchange and settlement rules, data 
ownership and metering responsibility. 

Limited relevance as these provisions 
are focusing on end-users in residential 
buildings, while hydrogen is expected to 
mainly be deployed in the industrial and 
transport sectors.  

Can be relevant for hydrogen market 
participants, to avoid administrative 
burden.  

Current hydrogen transport 
infrastructure could be considered as 
CDS (industrial clusters) or direct 
pipelines. In the future, such 
infrastructure could co-exist in parallel 
with interconnected networks. 

Hydrogen market operators should have 
regulated or negotiated access to 
storage, and/or be allowed to 
own/operate storage facilities. 
The current gas storage regime could 
potentially be mirrored for hydrogen 
storage 

Similar provisions could be implemented 
for hydrogen transactions; the scope 
should be defined, including the 
potential applicability to existing supply 
contracts 

Similar provisions could be implemented 
for hydrogen retail markets 

Table 4-2 Legal provisions of the Gas Regulation potentially relevant for hydrogen 
markets 

Main elements 

Gas regulation 

Relevance for hydrogen 

Access to storage 

Capacity allocation and 
congestion 
management 

Transparency 

Art 15 – Third-party access services 
concerning storage and LNG facilities 

Setting non-discriminatory and market-
based rules for access to storage assets 

Art 16 – Capacity allocation, congestion 
management (Art 17 for storage) 

Setting non-discriminatory and market-
based rules for connection to and use 
of network capacity 

Art 18 – Transparency requirements 
(Art 19 for storage) 

Fair access to information for all market 
participants 

Balancing 

Art 21 - Balancing rules and imbalance 
charges 

Setting the framework for H2 networks 
balancing, by defining the responsibility 
of market participants and of system 
operators 

Capacity rights trading 

Art 22 - Trading of capacity rights 

Setting rules for capacity rights trading 

4.1.2 Structure and characteristics of electricity, gas and hydrogen markets  

The regulatory framework for a dedicated hydrogen market should be designed taking into account 
the specific characteristics of hydrogen. This section compares the characteristics of the hydrogen 
market with those of the electricity and natural gas markets, including their liquidity. 

The following table illustrates major differences in market size and characteristics. The current 
hydrogen market is still very limited and concentrated, compared to the electricity and gas 
markets. Also, in 2030-2050, the overall estimated market volume would be lower than current 
natural gas market volumes, while the market concentration would depend on the scenarios, and 

95 

 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

might be different between EU regions. When assessing the options for a hydrogen market 
regulation, it is essential to consider the existing and expected situation, as well as the similarities 
and differences with the electricity and gas markets. 

Table 4-3 Key markets’ characteristics 

Characteristics 

EU traded volumes  

Total EU-28 import 
(2018)228 

EU consumption expected in 
2030 LTS 

Natural gas 

Electricity 

Hydrogen 

2018: >48 457 TWh225 

2019: 12 470 TWh226 

2015: 325 TWh227 

4 296 TWh  

393 TWh 

NA 

Baseline: 1802 TWh 

Baseline: 4059 TWh 

481 - 665 TWh229 
43 – 183 TWh of ren. H2

230 

EU consumption expected in 
2050 LTS 

H2 scenario: 640 TWh 
ELEC scenario: 837 TWh 

H2 scenario: 3966 TWh 
ELEC scenario: 4826 TWh 

H2 scenario: 1547 TWh 
ELEC scenario: 116 TWh  

Number and type231 of 
producers in EU 
- in 1990 
- in 2020 
- in 2030-2050 

Number of traders/suppliers 
in EU 
- in 1990 
- in 2020 
- in 2030-2050 

Number and type of 
consumers in EU 
- in 1990 
- in 2020 
- in 2030-2050  

Wholesale price 
convergence and market 
coupling 
- in 1990 
- in 2020 
- in 2030-2050 

- limited number of large 
mainly non-EU producers  
- idem 
- increasing number of local 
biogas/biomethane 
producers in EU 

- high market concentration 
(mainly OTC transactions) 
- high nr of traders & 
suppliers, high/increasing 
market liquidity 
- idem 

- mainly centralised large 
scale producers  
- increasing number of 
decentralised producers 
- high number of 
decentralised producers 

- high market concentration 
(mainly OTC transactions) 
- higher nr of traders & 
suppliers, high liquidity in 
wholesale markets 
- idem 

- high nr of residential and 
tertiary/industrial 
consumers 
- increased nr of consumers 
- decreasing nr of 
consumers 

- high nr of residential and 
tertiary/industrial 
consumers 
- high nr of consumers, 
increased nr of prosumers 
- idem 

- very limited number of 
producers 
- idem 
- increasing nr of 
decentralised producers 

- high market concentration 
(only OTC transactions) 
- idem 
- larger nr of suppliers and 
traders 

- very limited nr of industrial 
consumers 
- idem 
- increasing nr of 
consumers, mainly in 
industrial and transport 
sectors 

- inexistent 
- high price convergence at 
regional level 
- idem 

- inexistent 
- high price convergence at 
regional level 
- idem 

- inexistent  
- idem 
- depends on market 
development and regulation 

The definition of the hydrogen market rules and products should properly account for the 
differences between the natural gas and hydrogen value chain characteristics, as illustrated in 
Table 4-4 which highlights some important characteristics to be considered when assessing 
whether the natural gas market rules and instruments would also be suitable for trading and 
supplying hydrogen.  

Table 4-4 Value chain characteristics 

Natural gas value chain  

Hydrogen value chain  

Production 

Natural gas is mainly extracted in 
non-EU countries (and to a limited 
extent domestically produced) and 
transported to the EU by vessels or 
pipelines, mostly over long distances. 
Production can fluctuate or be 
constant over time and delivery has 
to adapt to demand. 

Hydrogen will mainly be produced within 
the EU and to a more limited extent also 
be imported and will enter the market 
via several routes: produced locally near 
to or at users’ sites; produced remotely 
and transported to users either by 
vessels, trucks or pipelines. 
There will be an increasing share of 
electricity supply-driven hydrogen 
production, through electrolysers located 
close to or distant from (renewable) 
electricity generation plants. 

225 ACER (2019) Traded volumes and CAGR at EU hubs via market platforms – 2012 to 2018. Comprises trades 
via transparent market platforms with a price reference and some product standardisation.  
226 Yearly (2016 figures) traded volume of electricity on the most liquid European Markets (BE, NL, CEE, ES, IT, 
UK, FR, Nordic, DE) is approximately 14 130 TWh, from figure 11 on the Monthly traded volume of electricity 
(incl. exchange executed and OTC) on the most liquid European markets, 
https://ec.europa.eu/energy/sites/ener/files/documents/quarterly_report_on_european_electricity_markets_q2
_2017.pdf 
227 FCH JU Hydrogen Roadmap Europe 
228 Eurostat. Simplified energy balances [nrg_bal_s] 
229 FCH JU Hydrogen Roadmap Europe 
230 Trinomics and LBST (2020) Opportunities from the inclusion of hydrogen in NECPs 
231 Type = centralised or decentralised  

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Sector integration – Regulatory framework for hydrogen 

Buffer & Flexibility 

Demand profile 

Natural gas value chain  

Hydrogen value chain  

Variable injection in transport 
pipelines from production facilities 
and LNG terminals acts as buffer to 
adapt supply to demand. 
Furthermore, flexibility is provided by 
storage, including operational storage 
at LNG terminals, linepacking, and to 
a limited extent demand side 
response. 

The large volumes of gas 
consumption and the knowledge of 
consumption patterns provide to 
network operators and market 
participants a good basis to 
anticipate demand levels and 
variations in function of some 
parameters (e.g. degree days, 
seasonal, weekly and daily profiles, 
…). 

At the present, supply volumes are 
adapted to demand on a bilateral basis.  
In the future, storage (tanks, UGS, 
linepacking) will provide system 
flexibility, in combination with flexible 
production & conversion (renewable and 
fossil-based hydrogen, methanation) and 
possibly demand response. 

In the first development phase demand 
profiles will mainly be determined by 
industrial users and heavy duty 
transport, with a more stable demand 
profile. The seasonality will hence be 
much more limited than for natural gas. 
In the second development phase, other 
end-uses (transport, power/heat 
generation) with more varying demand 
profiles may develop. Especially in the 
initial phase, the demand profile for 
individual clusters will be highly 
dependent on its specific network users 
and will hence be difficult to forecast. 

4.1.3 Potential market failures or barriers related to the development of a hydrogen 

commodity market 

To ensure a properly functioning and competitive market, the market rules and instruments should 
be adequately designed in order to avoid or mitigate market failures or barriers. These are 
presented in Table 4-5; the different measures to address them are discussed in the subsequent 
sections.  

The market design elements discussed in section 4.2 address multiple market failures and barriers 
simultaneously, to a different extent. Therefore, to facilitate the reading, the most relevant 
potential failures and barriers are presented in this overview table. The market design elements 
addressed in this chapter comprise the following: 

  Development of liquid hydrogen exchanges and OTC platforms; 

  Appropriate hydrogen product types with cross-border standardisation; 

  Efficient balancing mechanisms for hydrogen systems; 

  Access for market parties to short and long-term hydrogen storage; 

 

Licensing of hydrogen traders and suppliers. 

In addition to these market elements, other factors not discussed in this chapter are required for 
the development of a liquid, transparent hydrogen market at the EU level. These include: 

  Stable and predictable policy signals; 

 

 

Further R&I in hydrogen technologies to enhance their maturity and competitiveness with 
conventional technologies; 

Public support for non-mature promising hydrogen technologies with significant cost-
reduction potential, in particular to compensate non-internalised positive externalities; 

  Objective, transparent and non-discriminatory planning, investment and operation of 

hydrogen transport and storage infrastructure; 

  Efficient energy systems’ integration; 

  Development of cross-border hydrogen transport infrastructure; 

  Adequate carbon price and taxation signals for all energy products and uses; 

  Adequate oversight of energy markets to detect and address potential abuse of market 

power. 

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Sector integration – Regulatory framework for hydrogen 

Table 4-5 Potential market failures or barriers 

Market failures or barriers 

Market concentration / vertical integration of production/import and supply, leading to potential abuse of 
market power and constituting a barrier to new entrants 

Fragmented market structure (e.g. size of market areas) hampering cross-border transactions and therefore 
not allowing effective trade and competition 

Unstandardised and/or inadequate market rules, products and contract types (including short-term 
standardised products), limiting market liquidity, cross-border participation and/or access for smaller 
participants 

Lack of transparency regarding information (quality, price, type and origin) of hydrogen traded on platforms 

Lack of network availability data, especially cross-border, and on system operation, limited harmonisation on 
transparency requirements 

Difficulties to conclude long-term hydrogen supply contracts to finance production, partially as a result of the 
inexistence of a liquid hydrogen market  

Competition between market hubs and concentration of trade in highly liquid hubs impeding the 
development of regional hubs 

Limited sector coupling hampering efficient competition between hydrogen, methane, electricity, and heat, 
due to e.g. incomplete integrated planning or implicit coupling in operation of each energy system 

Inadequate disclosure measures resulting in market participants being unable to value the specific benefits of 
renewable or low-carbon hydrogen compared to grey hydrogen 

Non-harmonised guarantees of origin/certificates for renewable and low-carbon gas, hindering trade across 
national borders, market deployment, GO liquidity and information provision to consumers 

GOs/certificates granted only for renewable hydrogen, reducing interest to invest in low-carbon hydrogen 
production; also hindering full disclosure of energy supply mix 

Strictness of national licensing requirements for suppliers/traders in some markets hampering market entry 
and hence competition 

Lack of mutual recognition of licenses for traders and suppliers hampering market entry and hence efficient 
competition 

Distortive effect of RES support mechanisms 

This section develops the five regulatory elements (see Figure 4-1) that are deemed relevant for 
the design of hydrogen markets. 

For each market design element, a first section introduces the main theoretical and operational 
underpinnings used for the analysis of the hydrogen market design. A second section assesses the 
potential barriers to the development of hydrogen markets. A third section proposes regulatory 
measures to stimulate market liquidity and enable hydrogen deployment. The overall set-up and 
relationship between these market design elements ultimately determine the effectiveness of a 
possible regulatory intervention and different market regulation alternatives to facilitate market 
development.  

Figure 4-1 Hydrogen market design elements 

Trade 
platforms & 
exchanges

Definition of 
market 
product types

Hydrogen 
system 
balancing

Access to 
large-scale 
storage

Licensing for 
suppliers and 
traders 

4.2.1 Hydrogen trade via OTC platforms and exchanges 

Wholesale energy markets 

Gas and electricity producers, shippers and traders operate in a liberalised market environment. 
They compete in the wholesale energy markets to sell to traders, large industrial consumers and 
retailers. Energy commodities are traded on different types of wholesale markets, as summarised 
in Table 4-6. This table also assesses whether these types of wholesale energy markets would be 
suitable for hydrogen trade. 

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Sector integration – Regulatory framework for hydrogen 

Table 4-6 Types of wholesale energy markets 

Gas & electricity (*) 

Hydrogen  

Exchange or 
multilateral 
trading platform 
(e.g. EEX) 

Market participants submit supply and 
demand bids. The market is cleared per 
predefined time period and a single 
market price (price as cleared) is 
determined. The clearing prices are 
published and can serve as a reference for 
other market participants. 

Bilateral over-the-
counter (OTC) 
trading  

Market parties agree bilaterally on a trade 
or supply contract by directly interacting 
with each other. The prices at which OTC 
contracts are concluded are not disclosed 
to other market participants.  

Organised over-
the-counter (OTC) 
trading  

Market participants submit supply and 
demand bids via a market platform which 
is continuously registering new bids; any 
market player can bilaterally accept the 
bid of another market player, resulting in 
different prices for each trade. 
Prices can be published by a number of 
services, as is currently done for OTC 
natural gas trade in the TTF hub.233 

Currently not used for hydrogen trade or 
supply. 
The use of exchanges requires 
participation of several market operators, 
both at the supply and demand side, in 
order to have sufficient liquidity allowing 
markets to clear at a representative price. 
Furthermore, the offered volumes per 
relevant market area and time period 
should reach a minimum level. 

The current trade and supply of hydrogen 
is based on bilateral OTC contracts. There 
is limited transparency regarding offered 
volumes or negotiated prices, with the 
first hydrogen price index published only 
in 2020232.  

Currently not used for hydrogen trade or 
supply. 
The use of such platforms could be 
considered even with a limited number of 
market participants and limited volumes, 
in order to enhance transparency about 
actual market volumes and prices. This 
option could possibly be used before the 
market is sufficiently mature to use 
exchanges. 

(*) The design of gas and electricity markets is adapted to properly account for their specificities, 
especially  regarding  the  definition  of  market  products,  timeframe,  and  balancing  requirements 
(instantaneous basis for electricity versus daily or hourly basis for gas). 

Box 4-1 illustrates the current situation in the wholesale gas markets. Investments in cross-border 
transport infrastructure and implementation of regulation (capacity allocation, market rules), have 
led to highly integrated gas markets and prices that are at regional level converging to a large 
extent.  

Box 4-1 Wholesale gas markets 

Gas trading on energy exchanges plays a key role in fostering liquid gas markets. Exchanges and 
trading  platforms  are  important  sources  of  price  signals  and  enable  trading  of  standardised 
products with minimised counterparty risk, aiming to create a viable and strong gas market that 
can satisfy the demand of traders, retailers and consumers in the short and long run. 

According to the ACER Market Monitoring Report 2018234, most EU gas wholesale markets have 
become very liquid and dynamic; market participants conclude future, forward and spot 
commodity contracts using long-term and short-term capacity products according to their 
business requirements and the economic fundamentals. Network Codes are contributing to these 
market improvements and their implementation increases liquidity, competition and price 
convergence. The concentration of capacity bookings is significantly higher for the longer-term 
capacity than short-term, due to historical contracts and the fact that naturally more market 
participants seek to optimise their portfolio in the short-term.235 

Figure 4-2 illustrates that the large majority of the transaction volumes in the wholesale gas 
market are still OTC based; the liquidity has however substantially increased at most gas hubs 
thanks to increased traded volumes and a higher number of market participants. The gas trading 
platforms have substantially contributed to more effective competition and more representative 
price formation. 

232 https://www.spglobal.com/platts/en/our-methodology/methodology-specifications/electric-power/hydrogen-
methodology 
233 ICIS - Daily prices, analysis and news for the Dutch gas markets and TTF hub. See 
https://www.icis.com/explore/energy/dutch-ttf/ 
234 ACER/CEER, Annual Report on the Results of Monitoring the Internal Electricity and Natural Gas Markets in 
2017 Gas Wholesale Markets Volume, September 2018 
235 ACER MMR 2018 – Gas wholesale market volumes 

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Sector integration – Regulatory framework for hydrogen 

Figure 4-2 Gas wholesale market volumes 

Source: ACER (2019) Market Monitoring Report 2018 – Gas Wholesale Market Volume 

To have liquid and properly functioning hydrogen wholesale markets, larger supply volumes and a 
higher number of market participants (both at the supply and demand side) are preliminary 
conditions. Once a minimum threshold in terms of market volumes and participants will have been 
reached, appropriate instruments will be needed such as OTC platforms and centralised exchanges 
(covered under section 4.2.1), and adequately designed market products.  

Electricity and gas exchanges and OTC platforms236 

Natural gas and electricity are traded on transparent market platforms ensuring liquidity and 
efficient market competition. Box 4-2 provides some background regarding the establishment of 
energy exchanges. CEER indicates that in most cases, the prevalent initial trigger for the 
establishment of energy exchanges in the EU was commercial interest. In addition, a few European 
exchanges have been developed with the involvement of their respective energy regulator. 237 

Box 4-2 Involvement of energy regulators in the establishment of exchanges238 

According to CEER “the Spanish electricity exchange OMEL, the Portuguese exchange OMIP and 
the Romanian exchange OPCOM were established due to legal enforcement by the 
government).” The Norwegian energy regulator was involved and granted a license for the 
foundation of the Statnett Marked electricity spot exchange in 1993 (the predecessor of Nord 
Pool). CEER also indicates that ”the Portuguese regulator was involved through discussions in 
the MIBEL Council of Regulators, and Romania’s energy regulator has granted the license for the 
power exchange, gradually issued and approved the market rules and established the market 
monitoring system. The Netherlands Competition Authority (NMa) advised the Ministry on the 
regulation of APX. Most other NRAs were not involved in the development of energy exchanges.” 

Most of the energy exchanges are licensed either by the national government or competent 
Ministry (e.g. Germany, Austria), the competent national financial (e.g. derivatives exchanges in 
Austria, France) or energy regulatory authority, and are supervised by an exchange supervisory 
authority, which is often the same authority as the one granting the license. 

Hydrogen trading via specific hydrogen platforms or via existing OTC platforms or 
exchanges for natural gas or electricity 

Specific trading platforms could be set up for hydrogen, but using existing platforms for natural gas 
or electricity to also trade hydrogen could be considered as an efficient alternative. Using existing 

236 An energy exchange is a multilateral system for the trading of wholesale electricity and/or natural gas spot 
and/or derivatives products operated and/or managed by a market operator, which brings together or facilitates 
the bringing together of multiple third party buying and selling interests in wholesale natural gas and/or 
electricity spot and/or derivatives products in a way that results in a contract, in respect of the wholesale 
energy product admitted to trading under its rules or systems. 
237 CEER (2011) Final advice on the regulatory oversight of energy exchanges.  
238 CEER (2011) Final advice on the regulatory oversight of energy exchanges.  

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Sector integration – Regulatory framework for hydrogen 

trading platforms would save development time and cost, reduce operational costs, underpin price 
formation (as arbitrage between natural gas, electricity and hydrogen will, to a certain extent, be 
relevant) and allow to have representative price formation and price level information per relevant 
EU market. 

The issue whether natural gas and hydrogen could be traded using the same market rules, 
products and instruments, is influenced by a number of factors: 

 

 

 

 

 

The differences in market structure regarding supply and demand, number of market 
participants and concentration; 

The differences in operators’ expectations (including contracts’ duration to secure new 
assets); 

The differences in product characteristics and end-use (for energy and/or feedstock); 

The possibility to separate for both gas types the carbon footprint and the physical product; 

The expected hydrogen market volume that would justify the use of trading platforms. 

At the present, publicly available information about hydrogen prices is still very limited; Platts has 
in April 2020 started to report daily hydrogen prices in the US and Europe (the Netherlands).239 But 
this is, up to now, rather limited in scope and product information. The European Commission has 
indicated in its hydrogen strategy document that it will develop a benchmark for euro-denominated 
transactions in hydrogen.240 Such a hydrogen price benchmark is considered key to developing 
trading in all market horizons. 

Rather than being traded via organised platforms, hydrogen is expected to continue to be traded 
via long-term OTC contracts allowing to underpin investments and hedge risks, at least in a 
transitional period until a liquid hydrogen market develops and in the absence of further policies for 
the development of organised markets. OTC contracts for short-term trade and balancing purposes 
will probably develop progressively – preferably via platforms to enhance transparency - to 
complement long-term OTC contracts. Electricity supply and electrolysers’ costs will play an 
important role in developing hydrogen markets, as hydrogen producers will take advantage of the 
variability in short-term electricity prices to improve the competitiveness of (renewable) electrolytic 
hydrogen. In a later stage, centralised exchanges might develop naturally once the number of 
market participants and the hydrogen production and import have reached a minimum level. On 
the basis of the current information, liquid exchanges might at the earliest develop in a few EU 
regions around 2030; national documents such as the Dutch and German hydrogen strategies do 
not explicitly provide a more ambitious timeline.  

Rules and conditions should favour participation of multiple operators in the trading platforms in 
order to stimulate liquidity. Services such as price reporting, market making, market broker 
platforms and exchanges would emerge alongside. Liquidity will be very low in the initial phase, 
and could be enhanced by incentivising or obliging existing market parties to trade (part of their) 
supply volumes via an open platform or oblige dominant parties to release part of their long-term 
commodity contracts. It would be useful to further analyse whether and under which conditions 
such a legal obligation could be imposed on existing and new market parties.  

Could a single commodity market be used for both methane and hydrogen? 

Theoretically, a single gas commodity market could be set up for hydrogen and methane gases, in 
order to have high market liquidity and to avoid fragmentation of the gas market. Trading could be 
based, separately, on the energy content on the one hand and on the ‘sustainable value’ of the 
concerned gases on the other hand. The physical systems could be taken into account by implicitly 
coupling the markets for the two gas types, with the consideration of the conversion constraints. 

Such a single market would require more dynamic metering and exchange of data, given the 
differences in product characteristics (energy content, volumetric density, production and demand 
profiles, different hydrogen and methane types and required purity, …). A market area manager 
would need to clear the market taking into consideration available capacity informed by conversion 
asset as well as by network operators.  

However, the creation of such a single commodity market for natural gas and hydrogen may face 
several difficulties, like physical conversion constraints (limited capacity, limited conversion 
technology maturity, high conversion costs), clearing of the single market with implicit 

239 https://www.spglobal.com/platts/en/our-methodology/methodology-specifications/electric-power/hydrogen-
methodology 
240 European Commission (2020). A hydrogen strategy for a climate-neutral Europe 

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Sector integration – Regulatory framework for hydrogen 

consideration of the constraints, and balancing of the methane and hydrogen systems. If markets 
could be coupled, the limited (and asymmetric) conversion capacity would lead to frequent 
decoupling of markets and thus to different commodity prices. 

A single market does de facto assume that the existing platforms, contract types and products are 
also suitable for hydrogen (see section 4.2.2 on product types). The single price and market 
products would not allow to reflect the different daily to seasonal production and load profiles, 
subjecting hydrogen consumers to price determinants which do not concern them, and conversely 
methane gases consumers. This while hydrogen supply would be much more strongly coupled to 
electricity markets development, as electricity prices would directly affect electrolytic hydrogen 
production. Moreover, clearing at a single commodity price for methane and hydrogen would not 
allow to reflect their different market value. And an important number of hydrogen consumers, 
such as the chemical and steel-making industries that use hydrogen as feedstock would not be able 
to switch consumption to methane gases anyway, regardless of their market value. 

Additionally, a single commodity market could lead to a situation where TSOs of natural gas and 
hydrogen grids would have a dominant role if the operation of conversion assets would be assigned 
to them. If, in contrast, market participants were to operate conversion assets, they would have to 
inform the available conversion capacity and prices to the market area manager. Reflecting the 
climate footprint of the different gases would also be more complex, although trade in guarantees 
of origin could be separated from trade in the gases themselves. 

Taken into account the complexity and potential negative impacts of a single commodity market, it 
might be preferable to have separate commodity markets for methane and hydrogen, also to 
properly value the specificities of each gas type. If technical progress reduces the cost and 
increases the capacity of conversion assets and when hydrogen markets will develop, the markets 
could eventually be implicitly coupled, but maintaining separate prices for methane gases and 
hydrogen would still be desirable. 

Stakeholders’ opinions 

The following table summarises the feedback received from stakeholders regarding hydrogen 
trading platforms and exchanges. 

Generally, the current natural gas market framework is considered as a good basis for a future 
hydrogen market design, but changes might be required to account for the specificities of hydrogen 
versus natural gas. Stakeholders are divided on the adequacy of a single commodity market for 
hydrogen and methane gases. 

Table 4-7 Stakeholders’ opinions on OTC platforms and exchanges topics 

Topic 

Arguments in favour 

Arguments against 

One single 
market for 
methane and 
hydrogen 

  Some TSOs suggest to set up a single commodity 

market for methane and hydrogen, to avoid market 
fragmentation. 

  The integration of H2 and NG markets could be done 

by trading the energy content of the commodity 
separately from other features such as the carbon 
footprint - certificates or GOs could be used to value 
the different footprints on the basis of a “book & 
claim” system. If two commodity markets (methane 
and hydrogen) co-exist, the liquidity of the hydrogen 
market will be very limited. 

  While acknowledging that a common market is 

unlikely in the short- to medium-term, they consider 
it as feasible option in the long-term. 

  Market operators consider that 

a single energy market for 
natural gas and hydrogen (via 
e.g.TTF) would be very 
difficult to implement. 

Using natural 
gas market 
platforms 
(using similar 
contract types 
and 
conditions) 

  The large majority of stakeholders (network 

operators, gas traders/suppliers, hydrogen industry) 
consider that natural gas market platforms can be 
used to trade hydrogen. 

  As the gas sector in NL and UK has a very keen 

interest in H2 development, it is expected that the 
TTF and NBP will be the first platforms to develop 
products for hydrogen. 

  Operators of gas exchanges indicate they can support 
the development of a hydrogen market already now, 
highlighting the importance of price benchmarks.  

  For some gas infrastructure 
operators, it is too early to 
start trading hydrogen on gas 
platforms. Once more 
hydrogen production capacity 
is available to increase 
liquidity, it would be feasible 
to include hydrogen in the NG 
platforms so that 
shippers/traders can leverage 
the available tools. 

102 

 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Options for a single gas market vs two separate commodity (hydrogen and 
methane) markets  

Hydrogen could be traded via one single gas market for both methane and hydrogen, as a separate 
commodity while using the same trading platforms and exchanges, or through separate platforms 
and exchanges. In the second case using separate platforms and exchanges, the current regulation 
for natural gas could also apply to hydrogen, or specific regulation could be considered.  

The first option (option A) is thus to have one single commodity market for methane and hydrogen, 
allowing to trade both gases in the same portfolio, similar to how H-gas, L-gas or biomethane are 
jointly traded based on their energy content.  

The second option (option B) is using the existing gas platforms and applying the same regulation, 
but the products’ definition and contract types could be specific for hydrogen, and the markets 
would de facto be organised separately. The trade of gases across networks would imply the need 
to prove that there is sufficient transport and conversion capacity. 

The third option (option C) is to leave the hydrogen market unregulated, at least for the time 
being, to leave time to the market to develop. 

Options formulation 

The three options are 

  A: One single gas market; 

  B: Two separate markets, with common platforms; 

  C: Two separate markets, with no regulation for the hydrogen market; 

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Sector integration – Regulatory framework for hydrogen 

Table 4-8 Regulatory intervention in the establishment of hydrogen markets 

Option A 

Option B 

Option C 

Single or 
separate 
gas markets 

One single commodity 
market for methane and 
hydrogen 

Separate hydrogen and 
methane markets, with 
common platforms 

Not regulated 

Advantages 

 Increases liquidity for 
hydrogen trade 
 Addresses natural gas 
consumption decrease and 
its impact on market 
liquidity 
 Maximises use of 
conversion capacity across 
markets 

 Potentially high 
implementation and 
operational costs 
 Limited conversion 
capacity may require 
frequent decoupling of 
markets 
 Conversion capacity may 
be asymmetric between 
markets 
 Does not reflect different 
product characteristics and 
uses and market values 
 Less flexibility for hydrogen 
market participants and 
possible exchange operators 

Disadvantag
es / risks 

Mitigation 
measures 

 Coherence with electricity 
and methane regulatory 
framework regarding 
freedom of exchange 
operation 
 Separate hydrogen and 
methane trade based on 
product characteristics and 
uses 
 Facilitates market coupling 
while allowing for separate 
prices 
 Monitoring can be set up 
according to risks and 
market dynamics 
 Adapted to the progressive 
market uptake (OTC only in 
a first phase) 

 Requires a new regulatory 
framework dedicated to 
hydrogen 
 Potentially lower welfare 
due to more limited coupling 
compared to option A 

 Monitoring existing 
exchanges regarding their 
expansion to hydrogen and 
adapt licensing accordingly 

 Low administrative costs 
 Flexibility for product 
innovation 
 Separate hydrogen and 
methane trade based on 
product characteristics and 
uses 
 Adapted to the progressive 
market uptake (OTC only in 
a first phase) 

  Lack of standardisation 
can become an important 
barrier (to cross-border 
trade) 
 Potentially lower welfare 
due to limited market 
coupling 
 Higher monitoring costs 
and eventually need to react 
(and regulate) when needed 
 Low security to 
investments due to slower 
market development 

 Monitoring existing 
exchanges regarding their 
expansion to hydrogen and 
adapt licensing accordingly 
 Incentivise harmonisation 
and exchange of best 
practices 
 Incentivise exchange 
mergers/expansion once 
liquid markets develop 

Options regarding the setting up of organised platforms or exchanges for 
hydrogen  

This section deals with the options for setting up (or not) organised market platforms or exchanges 
for hydrogen. The central question concerns the regulatory intervention in the establishment of 
hydrogen exchanges, obliging their use by market participants or leaving it open to new and 
existing market platform operators to develop profitable business cases. 

The establishment and use of organised energy trading platforms and exchanges is not regulated 
at EU level, and is addressed differently by Member States. However, in most Member States, 
energy exchanges were established without any legal obligations and set up on a voluntary and 
commercial basis by market operators, albeit with oversight from energy and/or financial 
authorities and regulators.  

Oversight of the trading platforms and exchanges would be conducted by the energy and/or 
financial authorities and regulators in all options presented below, which differ on the role of the 
policy makers and regulators in their establishment. 

The three options are therefore: 

104 

 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

  Option A: No mandatory rules for the establishment of hydrogen trading platforms and 

exchanges; 

  Option B: Mandatory rules for the establishment of hydrogen trading platforms and 

exchanges; 

  Option C: Involvement of energy regulator in establishing hydrogen trading platforms and 

exchanges; 

The first option (option A) is to follow the general rule and leave it open to market participants to 
progressively offer hydrogen trading options via organised platforms or exchanges once the 
hydrogen market reaches maturity (in terms of market volume and number of participants) to 
justify a profitable business case.  

The second option (option B) is to impose the establishment of organised platforms or exchanges 
for hydrogen through legal enforcement by national governments.  

A third option (option C) is to ensure the involvement of the energy regulator (which would be 
responsible also for the regulatory oversight of the hydrogen sector), e.g. by granting licenses for 
hydrogen trading platforms or exchanges, by establishing a market monitoring system, and by 
issuing specific market rules or by advising other involved authorities on market related issues.  

Table 4-9 Options for the establishment of hydrogen trading platforms and exchanges 

Option A 

Option B 

Option C 

Options 

No mandatory rules for the 
establishment of organised 
platforms and exchanges  

Mandatory rules for the 
establishment of organised 
platforms and exchanges  

Regulator involvement in 
organised platforms and 
exchanges establishment 

Advantages 

 Leave freedom to use 
existing organised platforms 
or exchanges or to develop 
new ones 
 Market driven, stimulating 
innovative developments & 
based on profitability 
 Let time to develop the 
market (volume and number 
of participants) 

Disadvantag
es / risks 

 Incumbent market 
platform operators have 
possible competitive 
advantage 

Mitigation 
measures 

 Monitor existing trading 
platforms and exchanges 
and, if required, adapt 
licensing, or foresee setting 
up a legal framework 

 May possibly accelerate 
the accessibility of trading 
platforms and exchanges to 
all market participants 
 Ensure coherence with 
other energy regulatory 
framework regarding trading 
platforms & exchanges 
operation 
 Mainstream monitoring 
needs 

 Difficult to reflect the real 
costs as it would not be 
market driven 
 Not flexible to adapt 
market products 
 May not be cost-efficient 

 Extract lessons from gas 
trading platforms and 
exchanges costs to adapt 
and apply to hydrogen 
 Remain legal framework 
flexible and open to changes 

 Ensure coherence with 
other energy regulatory 
framework regarding trading 
platforms & exchanges 
operation 
 Monitoring can be set up 
according to risks and 
market dynamics 
 More flexible than 
mandatory rules for the 
establishment 

 Non-harmonised 
establishment of rules and 
regulatory intervention 
across Member States 

 Monitoring trading 
platforms and exchanges 
and ensure NRAs 
coordination 

4.2.2 Definition of market product types for hydrogen 

Different product types are used in the gas market to maximise market value and hedge 
risks 
The liberalisation of the gas sector has introduced competitive access to markets, implying new 
risks for market participants. To reduce these risks, ad-hoc instruments have been implemented to 
manage and hedge portfolios of assets and customers, to protect market values or to take benefit 
from trade opportunities. Energy trading covers more than just proprietary commodity trading. The 
use of complex structured products in energy markets is related to the intrinsic complexity of the 
business, which requires the trader to virtually replicate assets and their portfolio constraints. 

Such structured products could also be developed and used by hydrogen market participants. 
Similar to the natural gas market, their development should be left to the initiative of market 
operators, and should in principle not require regulatory intervention. For the purpose of this 
assessment, the focus will be on market product types directly interacting with market operations. 
Table 4-10 gives an overview of the main products traded at the gas wholesale market and 
assesses whether similar products would be suitable for hydrogen trade.  

105 

 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

As the properties of hydrogen are more similar to those of natural gas than of electricity, especially 
regarding the timeframe and balancing requirements, the current gas market structure and 
products are considered as the most relevant basis for hydrogen. Balancing products are addressed 
in the next section. 

Table 4-10 Gas market product types and their suitability for hydrogen trade 

Gas market 

Suitability for hydrogen 
trade 

Need for adaptation 

Futures are standardised 
contracts that can be further 
traded on energy exchanges 

Futures 

Forwards 

A forward contract is a 
customised contract between 
two parties to buy and sell 
energy at a specified price to 
be delivered in a future time 
period (e.g. year n +1). It 
provides higher price certainty 
to the involved parties 
compared to short-term 
transactions  

Day-
ahead 
market 

In DA markets, gas trade are 
concluded one day before 
actual delivery241 via OTC or 
platforms. 
At the end of the day-ahead 
market, each BRP submits a 
balanced portfolio to the TSO 

Intraday 
and 
balancing 
markets 
(ID)242 

After clearing of the day-
ahead market, BRPs can 
intraday still trade and submit 
revised nominations to TSOs. 
Portfolio imbalances are dealt 
with via the balancing market 

 Could progressively 
complement Forwards 
 Futures can underpin both 
domestic and cross-border 
trade. Development of cross-
border trade will depend on 
availability of interconnected 
corridors throughout Europe 
  Standardisation at EU level 
may be appropriate 
 Futures are useful to 
ensure long term investment 
security (on demand and 
supply sides) 

 This type of contracts is 
currently used in the 
hydrogen market 

 DA markets (or equivalent) 
allow participants to adjust 
their long-term position or 
act as the central platform 
for supply and trade  
 Can provide additional 
revenues to flexible 
technologies (storage, 
hydrogen production, 
demand response) 
  

 Current functioning of ID 
and balancing markets for 
natural gas seems suitable 
for hydrogen 
 Would allow to provide 
additional revenues for 
flexibility offered by 
hydrogen production, storage 
and demand  

 Market uptake (minimum 
market volume and number 
of participants) will be 
needed before platforms will 
develop hydrogen futures  
 Market integrity and 
transparency monitoring and 
surveillance rules (REMIT) 
could be extended to the 
hydrogen sector 

 Forward contracts for 
hydrogen should in the future 
progressively comply with 
the “energy” related market 
rules (they now seem to be 
based on industry and 
feedstock-related rules) 
 Market integrity, 
transparency monitoring and 
surveillance rules 
(REMIT)could be extended to 
the hydrogen sector 

 Need for rules regarding 
settlement, balancing and 
nomination (similar to the 
gas market rules or specific) 
 Market integrity and 
transparency monitoring and 
surveillance rules (REMIT) 
could be extended to the 
hydrogen sector 

Id. 

Long term contracts are needed to secure investors in hydrogen infrastructure and 
production capacity 

In the gas sector, long-term capacity contracts are traditionally needed to ensure financing for 
new, large-scale infrastructure investments and to ensure long-term capacity bookings for TSOs 
and LNG terminal operators. In addition, LTC holders require them to mitigate the risk of lack of 

241 The day-ahead market is of major importance to balance individual portfolios and the market zone 
242 The intra-day market enables market participants to still adapt their positions, also in view of minimising 
their residual imbalance cost 

106 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

capacity and high costs of transmission or other services.243 Next to long-term capacity contracts, 
20/30 years long-term gas supply contracts have played a key role in supporting the development 
of the gas infrastructure and supply. 

In the hydrogen sector, it is likely that capacity and supply agreements will also be concluded on a 
long-term basis, to underpin the development of the required hydrogen supply assets. However, 
this practice may compromise hydrogen market liquidity. Moreover, electrolytic hydrogen 
producers may want some flexibility through e.g. interruptible transport capacity contracts that 
allow to take benefit from the volatility of electricity prices. Hence, adequate market platforms and 
instruments (e.g. forward and future contracts and adequate price benchmarks) need to be 
developed in order to attract market participants to use these platforms to hedge their risks while 
providing long-term security of investments and flexible market products. 

Considered options on the hydrogen market product types  

The central question will be to identify whether the existing gas market products are suitable for 
hydrogen trade, to contribute to hydrogen market deployment and market liquidity. While 
development of hydrogen market products should be left to the initiative of market operators, and 
hence would in principle not require regulatory intervention, policy makers and regulators could 
play a role in incentivising the harmonisation of product types across the EU and sharing of best 
practices. 

Furthermore, setting minimum product characteristics could be necessary in order to ensure that 
there are no entry barriers for new or smaller market actors, such as small-scale electrolytic 
hydrogen producers. As hydrogen markets will develop and ultimately would have a large number 
of participants (as illustrated in Table 4-3), minimum product obligations could be warranted. This 
would approximate the approach of the new electricity market design, where minimum bid sizes of 
500 kW and a settlement period of 15 min (with derogations) are required by 2021 for day-ahead 
and intraday markets.244 

The first option (option A) is to establish the same minimum product requirements for hydrogen 
and methane markets, assuming that there are strong similarities between them regarding the 
required timeframe of delivery, the product definition and the adequate contractual arrangements. 
The second option (option B) is not to regulate hydrogen markets, at least for the first 
development phase (e.g. until 2030). The third option (option C) is to mirror minimum product 
requirements for hydrogen and methane markets, with some adaptations to better fit with the 
hydrogen system characteristics. 

As illustrated in Table 4-4, the three most important differences between gas and hydrogen , which 
are directly influencing market features, are 

 

 

 

The more domestic and dispatchable character of hydrogen production compared to natural 
gas production; 

The expected lower coverage and interconnection of hydrogen networks compared to the 
natural gas networks; 

The interaction of hydrogen deployment with the electricity and methane systems. 

Options formulation 

The three options are 

  Option A: Mirror all gas market products; 

  Option B: Mirror gas market products but adapt some product requirements to properly 

account for specific features of hydrogen. 

  Option C: No mandated standardisation; 

243 EY & REKK (2018) - Quo Vadis EU gas market regulatory framework – Study on a Gas Market Design for 
Europe 
244 Regulation 2019/943 on the internal market for electricity. 

107 

 
 
 
 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Table 4-11 Wholesale hydrogen market product types standardisation 

Option A 

Option B 

Option C 

Options 

Advantages 

Mirror all gas market 
products minimum 
requirements 

 Lower administrative costs 
compared to option B 
 Fits to all market 
participants needs as long 
as characteristics are 
similar / minimum 
requirements are of 
sufficient resolution  

Disadvantages 
/ risks 

 May not properly reflect 
the specific characteristics 
of hydrogen supply and 
demand 

Mitigation 
measures 

 Set minimum product 
requirements to maximum 
common denominator (i.e. 
most strict requirements) 
 Monitor the success and 
adapt when required 
 Incentivise development 
of regional exchanges and 
initiatives 

Mirror and adapt some 
product requirements 

No standardisation 

 Fits to all market 
participants needs as long 
as minimum requirements / 
adaptations are of sufficient 
resolution  

 Accounts for differences 
between methane and 
hydrogen systems 

 Higher administrative 
costs 

 May compromise 
hydrogen and methane 
market integration (into 
one single market), unless 
adaptations are harmonised 

 Extract lessons from gas 
and electricity exchanges’ 
products harmonisation  

 Incentivise development 
of regional exchanges and 
initiatives 

 Low administrative costs 
 Adapted to the current 
situation with industrial 
market participants only 
 Allows for innovation in 
products 

 Lack of standardisation 
can become important 
market barrier, e.g. to 
cross-border trade  

 Extract lessons from gas 
and electricity exchanges’ 
products harmonisation 
 Set ex-ante target product 
requirements (initially no 
standardisation and 
gradually increase 
requirements according to 
an established roadmap) 
 Incentivise development 
of regional exchanges and 
initiatives 

4.2.3 Balancing rules and tools to balance hydrogen portfolios 

Balancing rules and tools used in the gas system245 

The experience in the natural gas sector regarding portfolio and system balancing, provides 
relevant input to determine the possible balancing approach for the future hydrogen system. To 
ensure that a gas system operates safely and efficiently, balancing injection in and withdrawal from 
the system is required, taken into account the flexibility offered by linepack. Previously, natural gas 
TSOs were responsible for balancing supply and demand within their network, holding options for 
injection or withdrawal of gas via long-term contracts (e.g. using large storages). The Balancing 
Network Code was introduced to stimulate liquidity in the short-term market and to enable and 
incentivise network users (NU) to balance their own portfolios, through adapting their injection 
(from production, import or storage) and/or offtake (for consumption or storage). This resulted in 
the development of the Balancing Target Model. 

Natural Gas Balancing Target Model (BTM) features and tools 

The balancing position of a network user is the difference between its inputs (e.g. local gas 
production or gas shipped into the balancing zone from adjacent balancing zones, LNG terminal or 
storage, or bought on the market) and its off-takes (e. g. gas consumed by its end-customers or 
sold on the market). The actual differences at the end of the Gas Day are cleared between the TSO 
and the network users at the marginal price.  

Network-related rules on information provision, imbalance charges, settlement processes 
associated with daily imbalance charges and provisions on operational balancing underpin the 
operation of balancing markets. To meet the aims of the Balancing Network Code (BAL NC), the 
following tools or features are relevant: 

1.  Trading Platform and Short Term Standardised Products 

TSOs should trade gas for residual balancing purposes on the same trading platforms as 
network users using Short Term Standardised Products (STSPs) with the aim of increasing 
competition and liquidity of the short-term wholesale gas market. 

245 This section is based on ENTSOG (2018) Balancing Network Code – an Overview. Available at 
https://entsog.eu/sites/default/files/2019-11/BAL%20leaflet.pdf 

108 

 
 
 
 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

The STSPs have to be traded for delivery on a within day (ID) or day ahead (DAM) basis seven 
days a week, in accordance with the applicable rules. The STSPs are defined in the BAL NC as 
represented in the next figure. 

Figure 4-3 Short Term Standardised Products definition246 

The ultimate aim is that TSOs will use only Within-Day title products. 

For the procurement of STSPs, TSOs use a trading platform that meets all of the following 
criteria: 

 

 

 

 

 

 

provides sufficient support to both NUs and TSOs to undertake balancing actions using 
relevant STSPs; 

provides transparent and non-discriminatory access; 

provides services on an equal treatment basis; 

ensures anonymous trading at least until a transaction is concluded; 

provides a detailed overview of the current bids and offers to all trading participants; 

ensures that all trades are duly notified to the TSO. 

2.  Virtual Trading Point & Trade Notifications 

It allows for the tracking of the market party that is financial responsible for gas supplies 
within the entry/exit system. The Balancing NC describes the underlying features of trading 
at the VTP, such as the lead time and the information to be provided in the trade 
notification process. 

3.  Operational Balancing (merit order) 

When deciding upon the appropriate balancing actions, the TSO shall prioritise the use of 
title products where and to the extent appropriate over any other available short term 
standardised products or balancing services. 

4.  Nominations 

The NU provides nomination information to the TSO. This section of the code harmonises 
the information the NU has to provide to the TSO to have or to change the gas flow (i.e. 
nomination or re-nomination) at Interconnection Points (IPs). It also sets common rules 
about this process: re-nomination should be possible every hour of the Gas Day, with the 
general rule that the lead time for re-nomination is two hours ahead. 

5.  Daily Imbalance Charges 

NUs have to be bound to pay or be entitled to receive (as appropriate) daily imbalance 
charges in relation to their daily imbalance quantity. These charges shall be cost reflective. 

6.  Within Day Obligations 

In a daily balancing regime, NUs must be balanced at the end of the day. WDOs are 
additional within day constraints. The Code provides for three types of WDOs: System-wide 
WDOs247; Balancing portfolio WDOs248; Entry-exit WDOs249. 

246 ENTSOG (2018) Balancing Network Code – an Overview. Available at 
https://entsog.eu/sites/default/files/2019-11/BAL%20leaflet.pdf 
247 Designed to provide incentives for NUs to keep the transmission system within its operational limits 
248 Designed to incentivise NUs to keep their individual position during the Gas Day within a pre-defined range 
249 Designed to provide incentives for NUs to limit the gas flow or the gas flow variation under specific 
conditions at specific entry-exit points 

109 

 
 
 
 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

7.  Neutrality arrangements 

A balancing neutrality mechanism will be used to enable the TSO to recover and 
appropriately apportion charges and revenues related to its balancing activities. 

8.  Information Provision 

To allow shippers to balance their portfolios, information is provided to them regarding 
their inputs and off-takes from the TSO. The information provided to NU by the TSO should 
refer to the overall status of the transmission network, the TSO balancing actions and the 
network user’s inputs and off-takes for the Gas Day. 

9.  Line-pack Flexibility Service (LFS) 

The LFS service is an additional tool to allow NU to be balanced at the end of the day. A 
TSO may offer the provision of LFS to NU after the approval of the related terms and 
conditions by the NRA. 

10. Interim Measures 

In the absence of sufficient liquidity of the short-term wholesale gas market, suitable 
interim measures shall be implemented by the TSO. Balancing actions undertaken by the 
TSO in case of interim measures have to foster the liquidity of the short-term wholesale 
gas market to the extent possible. 

Options to balance hydrogen portfolios and the overall hydrogen system  

To balance hydrogen portfolios and the system, market and network operators can use various 
tools such as: 

  Hydrogen storage (underground storage, tanks, …); 

  Demand side flexibility via interruptible contracts and injection of hydrogen into the gas 

system (blending); 

  Supply side flexibility: next to flexible import, domestic hydrogen production via 

electrolysers will offer opportunities for balancing the hydrogen system by taking benefits 
from the price variability in the electricity market.  

Hydrogen prices on the intra-day and balancing markets will hence to a large extent be determined 
by the short-term electricity prices. Having a liquid market for short-term hydrogen market 
products, will hence be key to balance both the electricity and hydrogen system while optimally 
value the price differences and variations on both markets via arbitrage. As long as there is no 
liquid short-term market for hydrogen, TSOs could be held responsible to cover residual imbalances 
by concluding direct contracts with storage operators and other flexibility providers (local 
producers, industrial users) and possibly by own conversion activities (blending, separation,…).  

Hydrogen producers, traders, storage operators and suppliers should be stimulated to participate in 
the short-term/balancing market. In order to enhance the system flexibility and reduce the overall 
balancing costs, it would be appropriate to opt for large balancing areas, which would require a 
high interconnection level of the future hydrogen networks. Connecting the existing and possibly 
new ‘closed’ pipelines (exempted from TPA) also to the future ‘open’ hydrogen networks, would 
allow to enhance short-term market liquidity and reduce balancing costs. Potential contractual or 
physical congestion should be addressed by adequate rules (e.g. UIOLI) or investments. Large 
balancing zones would be enabled by properly interconnecting the future hydrogen backbones in 
the different EU Member States. 

Stakeholders’ opinions 

Table 4-12 summarises the feedback received from stakeholders regarding rules and tools to 
balance hydrogen portfolios and the system. 

110 

 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Table 4-12 Stakeholders’ opinions on balancing rules and options 

Topic 

Comments provided by stakeholders  

Homogenous 
EU approach to 
regulating 
balancing 

Arrangements 
for hydrogen 
balancing could 
be similar to 
gas balancing 
in zones 
comprising 
both H-gas and 
L-gas 

Need for 
additional tools 
in early phase 

Balancing tools 

Clusters  

A homogenous EU approach to regulating balancing has been proved to be more effective 
and suitable than a fragmented approach. A gas exchange operator supports EU harmonised 
requirements for balancing agreements and balancing periods. 

For several stakeholders (TSOs and other gas infrastructure operators, gas suppliers and 
traders, hydrogen industry), coupling between natural gas and hydrogen balancing would 
avoid fragmentation and could take place in the following way:  

-  TSO determines imbalance of the hydrogen network and balancing position of each 

network user 

-  TSO provides conversion capacity from and to the methane network 
-  Balancing markets allow to trade standardised short-term balancing products (according 

to one stakeholder complemented with locational and capacity-based longer-term 
products) 

A trading association suggests that, in the early phases, some additional tools may be 
necessary to enable TSOs to ensure the system remains safe. 

All possible sources should be eligible to provide balancing services: flexible hydrogen 
production and import; underground and other storage, line-pack of TSOs and DSOs; 
conversion services and sufficient physical means for conversion in both directions should be 
in place. 

Local or regional clusters might need to respect strict balancing requirements considering 
their lower flexibility potential (e.g. 1 or more storage tanks), whereas larger interconnected 
hydrogen systems can leverage more flexibility as they will be directly or indirectly 
connected to several facilities, that can provide balancing services. 

Considered options on balancing rules and tools 

Stakeholders globally agreed that the Balancing Target Model currently used in the gas sector could 
be applied for the hydrogen market as well. Table 4-13 analyses some features and tools of the 
BTM, and assesses their suitability for the hydrogen market. Taking into account the limited market 
maturity, some approaches may not be feasible in the initial phase, but could become relevant 
when the market reaches maturity and liquidity. 

Options formulation for the hydrogen balancing design  

The first option (option A) is, at least for the time being, not to regulate balancing at the EU level, 
meaning that each Member State is free to decide on the regulation of balancing its hydrogen 
systems. 

The second option (option B) for a hydrogen balancing design is to fully mirror the existing NG 
Balancing Target Model and BAL NC. In this option, the neutrality arrangements should be very 
clear, and in the case of a methane TSO also endorsing the role of hydrogen TSO, there should be 
a clear separated balancing of methane and hydrogen systems. Virtual and physical conversion for 
balancing purposes would be contracted by the TSO from market parties. 

The third option (option C) is to mirror the existing NG Balancing Target Model as in option B, but 
to lighten some features that may not be essential, at least in a first phase (e.g. shorten the 
nomination requirements, and adopt interim measures more widely such as balancing instead of 
trading platforms). 

111 

 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Table 4-13 Features and tools of the BTM for gas and suitability for hydrogen balancing  

Gas market 

Hydrogen market 

NUs are financially responsible for daily 
imbalance charges (which should be cost 
reflective) to stimulate liquidity 

Mirror the natural gas approach, to 
incentivise shippers or NUs to reduce 
imbalances. 

TSOs or balancing operator providing 
physical daily / intra-daily correction 

Similar principle seems feasible and 
appropriate. 

TSOs should trade gas for residual balancing 
purposes on the same trading platforms as 
NU using STSPs. 
All participants are eligible as balancing 
service provider (storage, demand response, 
production, import, conversion) 

Most appropriate option seems to mirror 
natural gas approach; as the market will 
be rather illiquid in the initial phase, the 
role of the TSO will be crucial.  
All market participants should be allowed 
to provide balancing services 

Main 
balancing 
responsibility 

Residual 
balancing 
responsibility 

Trading 
platform and 
Short-Term 
Standardised 
Products 

Virtual 
Trading Point 

Use of VTP for each balancing area. 

Operational 
Balancing 
(merit order) 

Deciding upon the appropriate balancing 
actions, the TSO shall prioritise the use of 
title products 

Nominations 

NU provides nomination to the TSO. 
Information is harmonised, incl. changes to 
gas flow at IPs. It also sets some common 
rules about this process: re-nomination 
should be possible every hour of the Gas 
Day, with the general rule that the lead time 
of the re-nomination is two hours ahead. 

Within-Day 
Obligations 

WDOs address additional within day 
constraints 

Depends on choice of entry-exit model 
(discussed in chapter 3). 

Use of title products should be prioritised. 
For small clusters, locational and/or 
temporal products may be more 
frequently necessary. 

Appropriate rules are key to facilitate 
balancing and to incentivise participants to 
address own imbalances. Frequent re-
nomination (i.e. in intra-hourly intervals) 
may be necessary to optimise use of 
dispatchable production/conversion 
technologies (e.g. electrolysers).  

WDOs could be important given 
intermittency of renewable hydrogen 
production. 

Neutrality 
arrangements 

A balancing neutrality mechanism will be 
used to enable the TSO to recover and 
appropriately apportion charges and 
revenues related to its balancing activities 

Combined methane-hydrogen TSOs 
without separation of balancing systems 
could lead to cross-subsidisation of 
balancing costs across systems. 

Information 
Provision 

Information is provided to shippers, to 
balance their portfolios (overall status of the 
transmission network, the TSO balancing 
actions and the NU’s inputs and off-takes for 
the Gas Day) 

Linepack 
Flexibility 
Service (LFS) 

The LFS service is an additional tool to allow 
NU to be balanced at the end of the Gas Day 

Information provision to all market 
participants is critical for all market 
stages, including balancing. 

LFS could play important role in all 
hydrogen system sizes. Provision of LFS 
should be regulated given the need to 
provide non-discriminatory and 
transparent access to network users, and 
the inverse relationship of network 
transport and LFS capacity arising from 
different network pressures. 

Interim 
Measures 

In the absence of sufficient liquidity of the 
short-term wholesale gas market, suitable 
interim measures shall be implemented by 
the TSO 

Will be relevant as long as the hydrogen 
balancing markets are not liquid and TSOs 
are responsible for a large share or all of 
the network balancing. 

The fourth option D is for the TSO to be fully responsible for balancing the injection and withdrawal 
within their network, holding options for significant amounts of flexible hydrogen via long-term 
contracts (e. g. with operators of hydrogen storage or production facilities) and contracting further 
necessary balancing services in the short-term (e.g. via interruptible offtake contracts). 

The four options are thus: 

  Option A: Full mirroring; 

  Option B: Third party to endorse residual balancing responsibility; 

  Option C: Charging balancing costs through tariffs; 

  Option D: Mirroring and lightening some features  

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Table 4-14 Balancing rules and tools for the hydrogen system 

Option A 

Option B 

Option C 

Option D 

Options 

No regulation 

Mirror approach for 
hydrogen and methane 
networks 

Mirror approach for 
hydrogen and methane 
networks, with adaptations 

No individual balancing 
responsibility 

Main balancing 
responsibility 

Residual 
balancing 
responsibility 

Defined by MS / cluster 

Network users 

Initially TSO, ultimately 
network users 

TSO 

Defined by MS / cluster 

TSO 

TSO 

Not applicable. 

Advantages 

 Low initial regulatory 
costs 
 Flexibility to develop 
balancing solutions 
according to market 
maturity and later 
harmonisation 

Disadvantages 
/ risks 

Mitigation 
measures 

 May hamper market 
integration at a later 
stage 
 Specific solutions 
may not incentivise 
network users to 
reduce imbalances, 
increased balancing 
costs 

 Providing guidelines 
for contractual 
arrangements and for 
“public interest” 
investment in storage 
and conversion assets 
(guide to set up a 
viable business case 
for all market parties) 

 Straightforward to 
implement given 
developed natural gas 
balancing regulation 
 Would fit well if H2 
balancing 
requirements and user 
profiles are similar to 
NG 
 Increases balancing 
cost-reflectivity  

 Straightforward to 
implement given 
developed natural gas 
balancing regulation 
 Can simplify balancing 
rules for new market 
participants 
 More adapted for an 
infancy phase 
 Allows to adapt 
balancing rules to 
hydrogen clusters 
characteristics 
 Increases balancing cost-
reflectivity in the long-
term 

 May be too heavy in 
developing hydrogen 
markets 
 May miss the 
opportunity to adapt 
for sector coupling 
specific aspects (*) 

 Higher administrative 
costs 
 Increased balancing 
costs initially 
 Does not stimulate NU to 
reduce imbalances initially 

 Simpler to implement as 
TSOs have experience in 
balancing 
 Can simplify balancing 
rules for new market 
participants 
 Allows to share balancing 
costs with gas NU in the 
case of common charging 
 Possibly more space for 
flexibility and innovation 
 Allows to adapt 
balancing rules to 
hydrogen clusters 
characteristics 

 Increased balancing 
costs 
 Higher regulatory costs 
 Does not stimulate NU to 
reduce imbalances 
 May incentivise market 
operators active in 
electricity and methane 
markets to offload 
balancing responsibility to 
hydrogen TSO 

 When mirroring, 
screen with sector 
coupling criteria (move 
to option D-like) 
 Exempt/waiver 
isolated hydrogen 
systems from BTM 
requirements 

 Condition interim 
measures phase-out to 
market development 
 Exempt/waiver isolated 
hydrogen systems from 
BTM requirements 

 Regulator should follow 
up very closely and strictly 
 Cost-reflective allocation 
of balancing costs in 
charges per user group 

(*) This concern is shared by the 4 options 

Each option would allocate balancing costs to network users differently. If the main balancing 
responsibility were allocated to network users (i.e. they would be balancing responsible parties), a 
significant share of the balancing costs could be allocated to users causing the imbalances (except 
for eventual balancing reserve costs, if those were due to non-availability of sufficient gas volumes 
in the short-term market). In contrast, if the TSO was responsible for the main imbalances, 
balancing costs would be recovered through network tariffs, thus reducing the balancing cost-
reflectivity. 

Many of the features of the gas Balancing Target Model seem appropriate for balancing hydrogen 
systems, as indicated in Table 4-13, for example on the main balancing responsibility. Generally, 
as a minimum, Member States should not be impeded of allocating the main balancing 
responsibility to network users, as this incentivises them to reduce their imbalances and thus the 
overall system balancing costs. Suppliers should take on the responsibility for balancing the 
aggregate imbalances of their customers. Ideally, hydrogen network users would have the main 
balancing responsibility across the EU. 

However, especially smaller network users might have a difficulty in managing their imbalances, 
particularly in case there is not a liquid spot market. Balancing costs for isolated hydrogen clusters 
will be higher, relying specially on smaller-scale underground storage (if suitable geological 
locations exist), power-to-gas and potentially pressurised containers, given the limited linepacking 

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Sector integration – Regulatory framework for hydrogen 

capacity of hydrogen systems (as hydrogen has a lower specific energy content compared to 
natural gas) and that using large-scale underground storages for daily balancing is not economical 
(due to higher energy needs for compression).250 

Therefore, a number of adaptations to the gas Balancing Target Model as well as transitional 
measures would be appropriate. The first measure consists of foreseeing an increased role for 
network operators contracting directly balancing capacity and energy (through market-based, non-
discriminatory and transparent mechanisms) until a liquid market is developed and isolated 
hydrogen clusters are interconnected. Also, given the strong coupling of the electricity and 
hydrogen sectors through power-to-gas and hydrogen-based power generation, tailored market 
products (with e.g. a higher temporal resolution) might be appropriate. 

In case an entry-exit system for hydrogen is adopted, this would enable virtual trading points 
which could facilitate the development of spot hydrogen markets employed also for balancing. 
Another aspect for consideration is the unbundling of combined (methane and hydrogen) network 
operators. Here, at least accounts unbundling of hydrogen and methane systems balancing costs 
would be beneficial to increase transparency and avoid cross-subsidisation between the two 
sectors. 

The survey of potential barriers and measures adopted in the EU regulation and market design for 
the electricity and natural gas sectors in section 3.1 highlights the importance of sufficiently large 
balancing zones, transparency, a liquid market, appropriate balancing rules and cross-border 
harmonisation. It furthermore suggests regional initiatives as a channel to promote the integration 
of balancing markets and share best practices. 

Given these considerations, the option C seems the most appropriate. The definition of a hydrogen 
Balancing Target Model reflecting the methane one, but with a stronger initial role for TSOs and 
mechanisms for the integration of front-running hydrogen regions would provide sufficient 
flexibility but also guidance for the eventual development of EU-wide balancing markets. 
Eventually, managing residual imbalances could be assigned to the EU hydrogen TSO (described in 
Box 3-11) or another EU-level organisation focusing on balancing. 

Moreover, the EU hydrogen TSO (see Box 3-11) or another organisation could be responsible for 
managing the residual balancing of network users across the EU or groups of hydrogen market 
areas in the long-term. This could further reduce the hydrogen balancing costs, but would require a 
high-level of integration of the involved market areas. 

4.2.4 Access for market parties to large-scale hydrogen storage 

Regulation of energy storage and its role in the energy market 

Electricity storage is according to the EU legislation a competitive activity; electricity storage assets 
can only be owned and operated by grid operators for well-defined purposes. Third-party access to 
electricity storage is not foreseen by legislation, but can be negotiated on a commercial basis.  

For natural gas underground storage, legal provisions apply to ensure transparent and non-
discriminatory tariffs for third party access. Those regulated tariffs are applicable to all users on a 
non-discriminatory basis. Where a storage facility operates in a sufficiently competitive market (no 
natural monopoly), access can be allowed on the basis of negotiated tariffs, following a decision 
taken by the Member State. 

Natural gas underground storage facilities are a major flexibility resource in the gas sector, in 
particular to cover peak demand in winter periods. Even with factors such as the cold spell of the 
2018 winter, the closure of the Rough gas storage site in the UK and the imposed cap on the Dutch 
Groningen field production, a situation of overcapacity in natural gas underground storage can be 
observed across the EU.251 This situation, coupled with stabilising or even decreasing demand 
peaks (due to energy efficiency measures and global temperature rise) and increasing gas 
interconnectivity of Member States, has led to lower market demand and prices for storage 
capacity, and to changes of the access regime from nTPA to rTPA of some storage assets (e.g. in 
France) to maintain the capacity available to the market and avoid closure due to limited 
profitability. Therefore, converting some of the existing natural gas storage capacities (e.g. salt 
cavern sites) to hydrogen storage could be an adequate option from a societal perspective to 
minimise the overall energy system costs and also the risk of stranded gas storage assets. 

250 See for example Northern Gas Networks et al. (2016) H21 Leeds City Gate. 
251 ACER MMR 2018 – Gas wholesale market volumes 

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Sector integration – Regulatory framework for hydrogen 

In some national markets, gas suppliers are legally obliged to book underground gas storage 
capacity in order to secure their supply to retail end-users. This obligation, combined with possible 
restrictions to its utilisation, has an impact on the competition in the concerned Member States and 
on the gas wholesale and retail prices. For example, “the legal provisions established by the 
government in Poland, obliging any supplier importing gas to keep 30 days of the yearly volumes in 
the country’s storage facilities starting from 2017, has worsened the price convergence of the 
Polish market with the NWE region.”252 

Implementing such a legal obligation on hydrogen suppliers would not be an appropriate option, 
not even if there would be accessible hydrogen storage capacity available. Such obligations are 
mainly introduced to limit the risks related to the import dependence from non-EU countries and to 
cope with the high winter demand levels related to the use of natural gas for heating. As the future 
hydrogen demand in the EU would to a large extent be covered by production within the EU, and is 
expected to be much less seasonal than the current natural gas demand, the drivers for hydrogen 
storage would be different. Hydrogen storage is indeed expected to improve the business case of 
hydrogen production facilities and will to be certain extent also compete with them by also 
providing daily and seasonal flexibility to other market operators.  

Mulder et al. (2019) note, however, that the types of underground gas storage for hydrogen may 
play a role in determining the need to regulate (or not) storage, as, if hydrogen could be stored in 
depleted gas fields instead of salt caverns, the number of storage facilities needed in the 
Netherlands would decrease from 50 to 3. Hence, the different capacities of the reservoir types 
could lead to a concentration in the Dutch storage market which could warrant regulation of 
storage.253 

Next to underground storage facilities, mainly used for seasonal flexibility, LNG terminal operators 
provide third-party access to operational storage capacity (tanks), mainly used for short-term 
flexibility purposes. Access to these facilities is in general provided on the basis of regulated terms 
and tariffs, while some Member States have authorised or determined terminal operators to apply 
negotiated tariffs.  

Similar to natural gas, hydrogen storage is expected to play an important role in providing 
flexibility to the energy market, both by using storage tanks and underground facilities for short-
term or operational flexibility, and by using underground sites for seasonal flexibility. This role 
could be amplified with the expected development of production of hydrogen using (variable 
renewable) electricity, thereby increasing the need for hydrogen storage and other flexibility tools. 

The following table summarises the storage technology options per market type. 

Table 4-15 Storage technology options per market type 

Storage type / 
characteristic 

Gas market 

Electricity market 

Hydrogen market 

Short term – balancing 
and ID/DA market  

Long – term (seasonal) 
– all markets 

Tank 

LNG 

UGS 

UGS  

Pumped hydro 

Tank 

Batteries 

Flywheels 

/ 

LH2 terminals254 

UGS  

UGS 

The interaction between the electricity, gas and hydrogen systems and markets will be important, 
as methane and hydrogen storage assets can be used to also provide flexibility to the electricity 
system, and some natural gas storage facilities can be converted for the purpose of storing 
hydrogen (tanks, LNG terminals, UGS, …). 

Stakeholders’ opinions 
Stakeholders (TSOs and other infrastructure operators, gas suppliers, hydrogen industry, gas 
traders) agreed that the current regulatory regime for natural gas storage could be applied to 

252 ACER MMR 2018 – Gas wholesale market volumes 
253 Mulder et al. (2019) Outlook for a Dutch hydrogen market - Economic conditions and scenarios 
254 LNG import terminals can be combined with entry points for (liquid) hydrogen produced in other regions of 
the world where wind and solar energy are available at larger scale and lower cost than in Europe. Existing gas 
pipelines connected to LNG terminals could be used to distribute hydrogen locally. RWE is exploring such 
possibility, with the Brunsbüttel terminal in Germany. RWE (2020) German LNG Terminal and RWE to explore 
Hydrogen opportunities via Brunsbüttel. 

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Sector integration – Regulatory framework for hydrogen 

hydrogen storage as well, and that flexibility should be offered to Member States to regulate or not 
this activity. 

One stakeholder highlighted the important role of hydrogen storage in facilitating integration of 
surplus renewable electricity from electricity markets; to facilitate this, regulated third party access 
would be necessary to allow proper competition and market functioning. 

Considered options 

The central question is whether large-scale underground hydrogen storage should be a regulated 
activity, depending on the situation of the Member States and acknowledging that small-scale 
hydrogen storage in tanks should anyhow be a commercial activity, without any legal obligation for 
TPA. 

The first option (option A) is to impose regulated TPA access to hydrogen underground storage, 
assuming that the available capacity will be limited in most Member States and will hence in 
general be characterised by a natural monopoly. 

The second option (option B) is the mirroring of the 3rd Energy Package, with a more flexible 
regime, allowing Member States to decide whether access to storage is regulated or negotiated. 
This would assume that adequate regulation and rules for TPA would be necessary to avoid that the 
concerned owners/operators would abuse their natural monopoly position. This should consider the 
geographical distribution of potential hydrogen storage sites across Europe and the need to create 
a well-balanced storage infrastructure, with capacity mainly coming from the conversion of natural 
gas underground storage. 

The third option (option C) consists of not to implement regulated access to storage. 

Options A & B are mainly justified by the similar economic and technical characteristics of natural 
gas and hydrogen storage. Adequate regulation should facilitate the conversion of underground 
methane storage to hydrogen use.  

Options formulation 
The considered options are 
  A: Regulated TPA; 

  B: Regulated or negotiated regime, mirroring the current natural gas regime; 

  C: No regulation. 

Table 4-16 Options for access to underground hydrogen storage 

Option A 

Option B 

Option C 

Options 

Regulated TPA  

Regulated / negotiated TPA 
choice 

No regulation  

Advantages 

 May lower cost of capital 
 Consistent with the 
conversion of NG storage 
assets 
 EU harmonisation and 
possibly coordination 
 Addresses potential abuse 
of storage market power 

 May lower cost of capital 
 Allows differentiation 
depending on market 
situation and technical 
potential 
 Allows to match regulatory 
approach to methane storage 
 Allows to spur innovation 

 Low regulatory 
implementation costs 
 Open to all market 
participants 
 Market driven 
 No discrimination between 
storage in underground 
facilities and tanks 

Disadvantages 
/ risks 

 Could limit national action 
effectiveness 
 Methane storage operators 
under nTPA could not be 
interested in repurposing 
facilities under an rTPA 
regime 

 Risk of non-harmonised 
approaches between MS & 
non-coordinated use of 
underground storage 
capacities 
 Potential distortions 
between rTPA and nTPA 
assets 

 Potential discrimination of 
storage users 

Mitigation 
measures 

 Strong oversight by NRAs 

 Strong oversight by NRAs 

 Investment support 
mechanisms, such as 
guarantees 

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4.2.5 Licensing of hydrogen traders and suppliers 

Current practices in the natural gas markets 

Article 3(5) of the gas Directive 2009/73/EC stipulates that “Member States shall ensure that all 
customers are entitled to have their gas provided by a supplier, subject to the supplier’s 
agreement, regardless of the Member State in which the supplier is registered, as long as the 
supplier follows the applicable trading and balancing rules. In this regard, Member States shall take 
all measures necessary to ensure that administrative procedures do not discriminate against supply 
undertakings already registered in another Member State.” 

In the definition of the Gas Directive, ‘supply’ means the sale, including resale, of natural gas, 
including LNG, to customers. 

Usually, gas traders/suppliers must obtain a licence from their NRA or, less commonly, another 
national authority or the TSO, 255 when carrying out the following gas related activities: 

  Supply gas by pipes to any premises, industrial or household; 

  Operate as a gas shipper. 

Currently, integrated licenses for trade and supply can be obtained in France, Poland and Romania 
at least. Licensing requirements for traders are very diverse in the EU and can be rather strict, 
acting as a barrier to entry. Moreover, market operators that are active in different national 
markets have to dispose of licenses for each considered market and even establish a local 
presence, which can also act as a barrier.256 

Considered options for licensing of hydrogen suppliers and traders 

Licensing requirements for suppliers are usually based on national retail market regulation and 
characteristics and aim to protect retail market consumers, in particular (vulnerable) households. 
As a large scale use of hydrogen in the household market segment is not expected to develop in 
the short or medium term, it seems premature to assess within the framework of this study further 
concrete options for a regulation at EU level regarding licensing of hydrogen suppliers. The current 
provision in the Gas Directive seems a sufficient basis, and could also be implemented for hydrogen 
supply to consumers.  

As hydrogen trade is expected to become a supranational activity, it would be appropriate to define 
at EU level harmonised minimum requirements for trading licenses as well as a mechanism of 
mutual recognition. The licensing conditions should not be too strict in order not to create a barrier 
to market entry, while however being sufficiently strict to ensure trust in market operators. 
Introducing a system of mutual recognition for wholesale market authorisations/licences for trading 
activities across the EU would be an appropriate option to enhance competition and to facilitate 
cross-border trade. “Once a wholesale trader is authorised or licensed in one Member State, based 
on well-defined standardised minimum requirements, including in relation to the reliability and 
financial solvency of the entity, this should automatically be recognised in any other Member States 
[that] requires a licence or authorisation for wholesale trading.” This should also be “accompanied 
by a mechanism for enforcement action, such as revoking the licence without undue delay if 
needed. In addition, further steps are needed to mitigate the risk of fraud, including the right to 
exclude parties that have breached requirements in another Member State”.257 

255 Schönherr Rechtsanwälte et al. for DG ENER (2020) Upgrading the gas market - Regulatory and 
administrative requirements to entry and trade on gas wholesale markets in the EU 
256 Schönherr Rechtsanwälte et al. for DG ENER (2020) Upgrading the gas market - Regulatory and 
administrative requirements to entry and trade on gas wholesale markets in the EU 
257 ACER and CEER (2019) The Bridge Beyond 2025 Conclusions Paper. 

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Sector integration – Regulatory framework for hydrogen 

Box 4-3 REMIT and hydrogen markets 

The scope of the REMIT regulation could be extended to also comprise hydrogen. This would 
contribute to the harmonisation of the reporting requirements related to hydrogen trading across 
Member States, improve the level playing field with electricity and methane gas markets, and 
enable the detection and investigation of suspicious market behaviour by ACER and the NRAs by 
employing an established mechanism. It would also minimise the need to impose additional 
reporting requirements to market participants, which in the case of wholesale gas markets has 
been indicated as one of the most frequent barriers to enter and trade on the market.258 

In case REMIT is extended to include hydrogen, the reporting obligations would also cover pre-
existing operators of private hydrogen infrastructure. This could provide ACER and the NRAs with 
relevant information to assess market conditions, the potential abuse of market power by such 
pre-existing operators, especially if they are unregulated or exempt from TPA requirements. This 
measure would also allow authorities, market parties and stakeholders to dispose of relevant 
aggregated market information regarding the hydrogen sector. 

Employing the existing ACER REMIT information system (ARIS) would provide cost savings in the 
monitoring of hydrogen markets, thanks to economies of scope. The current cooperation model 
between ACER and NRAs for the identification and investigation of suspect market activity, could 
also be the main mechanism for the hydrogen market surveillance. If it is deemed that reporting 
requirements and market monitoring activities at the national level would be more adequate in 
an initial phase, the REMIT reporting requirements could be phased in according to the level of 
market development in each Member State (and according to the required update of ARIS). 
However, there are benefits of including hydrogen within the scope of REMIT rather early. 

The operation of ARIS requires a number of other reporting parties besides market participants – 
especially the sectoral TSOs, ENTSOs and organised market operators. Therefore, the inclusion 
of hydrogen in the scope of REMIT and the use of ARIS would imply a certain level of regulation 
of the sector. In case of no immediate regulation of the hydrogen sector at the EU level, market 
monitoring activities could be left for EU and national competition and financial services 
authorities. 

258 Schönherr Rechtsanwälte et al. for DG ENER (2020) Upgrading the gas market - Regulatory and 
administrative requirements to entry and trade on gas wholesale markets in the EU 

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Sector integration – Regulatory framework for hydrogen 

5  DEVELOPMENT AND ASSESSMENT OF OPTIONS FOR A REGULATORY FRAMEWORK 

This chapter develops and assesses four selected policy options for a regulatory framework for 
hydrogen infrastructure and markets. These regulatory framework ‘packages’ are developed by 
combining the options for each of the regulatory elements developed in chapters 3 and 4. 

The assessment considers the criteria required by the Better Regulation Guidelines. Specific criteria 
focusing on aspects particularly important to a hydrogen regulatory framework are comprised 
within these main criteria. As a result, the chapter provides a clear picture of the most relevant 
impacts per option for a hydrogen infrastructure and market regulatory framework, considering the 
hydrogen pathways developed in chapter 1 and the natural monopoly characteristics’ analysis of 
chapter 2. 

This chapter is structured as follows: 

  Context definition, presenting the context which could justify a regulatory intervention 
for hydrogen networks and markets, the underlying drivers, and the necessity and value 
added of action at the EU level; 

  Objective setting, shortly presenting the objectives of the assessment; 
  Assessment methodology, presenting especially the indicators employed for each of the 

main and specific criteria; 

  Regulatory framework options, briefly describing each of the four options as well as 
their specific combination of the regulatory elements developed in chapters 3 and 4; 

  Assessment of the options according to the criteria and indicators developed. 

Definition & scale 

Currently, the investment, ownership and operation of dedicated hydrogen networks is not 
regulated in the EU, except for technical legislation addressing environmental and safety aspects. A 
limited number of hydrogen networks for industrial purposes have been developed in the past in 
areas with large chemical industry clusters; this development was solely market-driven by 
hydrogen end-use and hydrogen production economics. Today, these pipelines, limited in size and 
capacity compared to the methane grids, are operated by industrial gases companies, with no third 
party access rules and carrying hydrogen qualities governed by industry-specific rules. These 
vertically integrated hydrogen producers negotiate prices with large industrial users and currently 
the hydrogen market is limited in size and focused exclusively on fossil-based hydrogen. 

The hydrogen strategy of the European Commission259 indicates that “Renewable and low-carbon 
hydrogen can contribute to reduce greenhouse gas emissions ahead of 2030, to the recovery of the 
EU economy, and is a key building block towards a climate-neutral and zero pollution economy in 
2050”. As part of a number of key actions, it proposes to design an enabling and supportive 
framework for hydrogen, addressing the topics of support schemes, market rules and 
infrastructure. 

Given the importance of hydrogen for the energy transition, the limited development of hydrogen 
infrastructure and markets, and the absence of sector-specific regulation, the main issues can be 
defined as: 

1.  Enabling the development of the hydrogen sector: Hydrogen uptake in the EU economy 

should support meeting energy & climate goals, which will require the development of 
hydrogen infrastructure and markets; 

2.  Need to update the infrastructure regulatory framework: The current energy infrastructure 
regulatory framework does not address hydrogen networks, potential interactions with 
natural gas and electricity infrastructure regulation and systems integration in general - the 
development of hydrogen networks and markets should consider the whole energy systems 
in planning (including for efficient repurposing of methane infrastructure) and operation; 

3.  Lack of liquid and well-functioning hydrogen markets: Market failures could lead to 

insufficient development of hydrogen markets, unfair competition between hydrogen and 
electricity, methane and other energy vectors, or other distortions in the internal energy 
market. 

It should be noted that there is still significant uncertainty regarding the energy transition 
pathways and the role that hydrogen will play, although its relevance is increasingly recognised by 
scenarios developed by public and private actors. Nonetheless, regulatory frameworks for hydrogen 

259 European Commission (2020). A hydrogen strategy for a climate-neutral Europe. COM(2020) 301 final. 

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Sector integration – Regulatory framework for hydrogen 

at the EU and national levels will need to be robust in order to address the multiple possible 
pathways as well as the diversity of national strategies. 

Main drivers 

Enabling the development of the hydrogen sector 

In all scenarios of the Long-term Strategy and the impact assessment of the 2030 Climate Target 
Plan260 achieving net decarbonisation by 2050, hydrogen is expected to play a role. Hydrogen (and 
its derived products like methane or ammonia) will be important especially in hard-to-decarbonise 
market segments such as specific industrial applications and transport (heavy duty road, rail, 
aviation, maritime). The impact assessment of the 2030 Climate Target Plan indicates that “more 
broadly, moderate and uneven efforts in terms of energy system integration, uptake of electricity 
and other low-carbon energy carriers such as advanced biofuels, hydrogen or e-fuels, carbon 
capture and storage (CCS) and CCU technologies, especially if compounded with lack of dedicated 
energy infrastructure and markets, negatively affect the pathway to climate neutrality, especially 
the decarbonisation of industry or the transport sector”.261 

Renewable or low-carbon hydrogen production is expected to grow significantly, starting with some 
Member States. This development will first take place in industry and to a lesser extent transport 
given the challenges in decarbonising these sectors as mentioned, and will mainly be driven by 
supportive regulation and specific incentives, energy & climate targets as well as a number of 
national and EU policy ambitions and strategies (such as the increased ambition for the Climate 
Target Plan and the hydrogen strategy). Chapter 1 analyses the national strategies in detail, while 
the hydrogen strategy pathway is detailed in Box 5-1. 

Blending of limited hydrogen volumes in methane gases networks can support the initial 
deployment of hydrogen production, but in order to efficiently value larger hydrogen volumes, 
dedicated hydrogen networks will be required in specific clusters and eventually for the 
interconnection of hydrogen systems. A majority share of this dedicated hydrogen network could 
arise from the repurposing of methane networks. 

Even though assessments expect renewable and low-carbon hydrogen technology costs to become 
increasingly competitive, it is widely recognised that public intervention is needed to speed up the 
development. The expected cost reductions and the need to kick-start renewable and low-carbon 
hydrogen production for hard-to-decarbonise end-uses justify the need for public intervention. This 
includes not only public support, but also regulation addressing market failures which could 
negatively affect the development of the necessary hydrogen infrastructure and markets, described 
next. 

Need to update the gas infrastructure regulatory framework 

There is currently a lack of certainty concerning the future hydrogen regulatory framework, 
stemming among others from the diversity of national strategies, the lack of sector-specific 
regulation at the moment, the inherent uncertainty of future development pathways, and the lack 
of clarity regarding the role of incumbent methane network operators in dedicated hydrogen 
infrastructure. The expectation of future regulatory intervention at the EU and national levels may 
delay potential investment decisions and the development of hydrogen infrastructure and markets. 

The lack of regulatory certainty and subsequent delays in hydrogen assets investment create a risk 
that the required cross-border backbone infrastructure for hydrogen-intensive pathways will not 
develop in time, limiting the integration of hydrogen clusters and the development of an internal 
hydrogen market. Without adequate regulatory provisions at the EU level, there is an additional 
risk of divergence of national regulatory frameworks, making posterior cross-border harmonisation 
of regulation and integration of hydrogen systems more difficult and costly. Lack of properly 
interconnected pipelines and harmonised rules regarding cross-border capacity allocation, 
congestion management and balancing would limit the market development and integration, and 
increase system costs.  

Even if sufficient investments do occur, the lack of adequate regulatory provisions to ensure non-
discriminatory third party access to hydrogen networks could negatively impact the entry of new 
hydrogen producers or suppliers, and hinder the development of a liquid market. In the absence of 
adequate third-party access regulation, operators of hydrogen networks would have to negotiate 
access with every new user, potentially affecting the speed of development of the network. Lower 

260 European Commission (2020). Impact Assessment for “Stepping up Europe’s 2030 climate ambition -  
Investing in a climate-neutral future for the benefit of our people”. SWD(2020) 176 final. 
261 European Commission (2020). Impact Assessment for “Stepping up Europe’s 2030 climate ambition -  
Investing in a climate-neutral future for the benefit of our people”. SWD(2020) 176 final. 

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investment will also result in more limited reductions in technology costs (e.g. because of reduced 
economies of scale). 

There is furthermore the risk that the development of hydrogen infrastructure does not sufficiently 
consider the benefits of an optimal configuration and dimensioning of the networks (taken into 
account the sub-additive cost curve) and of a system integration as well as the interactions with 
other energy sectors (electricity, methane and heat). A number of issues can be identified in this 
regard: 
 

The planning of electricity and methane infrastructure is being increasingly integrated, but 
hydrogen networks are not yet properly taken into account. This concerns planning for 
national, cross-border and trans-European infrastructure; 

  A substantial part of the hydrogen network is expected to develop by converting existing 

methane infrastructure, which is largely owned by regulated network operators. There is no 
regulatory framework to guide the efficient repurposing of methane infrastructure assets 
and avoid their decommissioning where beneficial from an overall energy system’s 
perspective; 

  Hydrogen can compete with regulated energy vectors (electricity, methane and heat) for 
certain end-uses, potentially distorting the internal energy market in the absence of a 
minimal set of EU hydrogen regulatory provisions. 

Private hydrogen infrastructure and operators exist in some Member States, including a few cross-
border pipelines. While their right to conduct business should be safeguarded, from the societal 
perspective it could be beneficial to mandate third-party access to (some of) their networks. These 
private operators could themselves be inclined to provide third-party access for a number of 
reasons, including to remain competitive with new producers and transporters and to focus on their 
core business which is hydrogen production rather than transport.  

Lack of liquid and well-functioning hydrogen markets 

The assessment of current hydrogen markets in this study revealed no evidence of abuse of market 
power by the large industrial hydrogen producers. However, if the hydrogen sector will develop as 
envisaged in the hydrogen-intensive pathways depicted in this study, market failures might arise. 
The four main factors leading to potential market failures that should be addressed by regulation 
are: 

1.  Due to certain technical properties of hydrogen networks, the infrastructure is 

characterised by a sub-additive cost curve; 

2.  Hydrogen is expected to become a traded commodity with a high number of 

producers/sellers and buyers; 

3.  Leaving the responsibility for hydrogen network planning to investors/operators without 

adequate oversight, might create a monopoly situation in infrastructure development and 
lead to a sub-optimal outcome from a global energy system perspective; 

4.  Refurbished methane pipelines will offer a competitive advantage to the concerned 

owners/operators over operators planning to build new hydrogen pipelines. 

Another potential risk of market failure stems from inefficient hydrogen price formation, as a result 
of the absence of a liquid EU-wide hydrogen market. The lack of hydrogen price benchmarks will 
interact with the limited scale of local hydrogen markets, leading to insufficiently liquid markets 
and preference of market operators for long-term contracts, as they will not be able to hedge their 
risks with forwards, futures or shorter-term market products. The lack of a liquid market with 
appropriate short-term products and an efficient price benchmark will also increase balancing 
costs, and make the role of hydrogen as flexibility provider less efficient. 

Inadequate infrastructure regulation and the prevalence of long-term contracts could lead to 
significant barriers for new market entrants, with possible discrimination for connection to and use 
of the networks for both small-scale hydrogen producers and consumers. The positive externalities 
of renewable or low-carbon hydrogen usage, namely its contribution to climate change mitigation, 
may not be adequately priced in the market in the absence of a liquid market with representative 
price formation and a harmonised system of guarantees of origin.  

Necessity and added value of action at the EU level 

Legal basis for EU action 

The legal basis for regulatory interventions at the EU level regarding hydrogen networks and 
markets is the Article 194 of the TFEU (as established in electricity and natural gas sector 
regulation). In line with Paragraph 1, the considered measures aim to improve the functioning of 
the energy market; promote the interconnection of energy markets; promote energy savings and 
development of new forms of renewable energy, and ensure the security of energy supply in the 
Union. At the same time, the regulatory interventions have to be designed in such a way that 

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enables the Member States to determine their own energy production and supply mix, including by 
opting for pathways that do not heavily rely on hydrogen. 

Added value of EU intervention 

The main added value of EU regulatory intervention is ensuring the efficient functioning of energy 
markets and the development of hydrogen infrastructure supporting the attainment of the energy 
and climate objectives of Member States at least cost. A set of EU rules for hydrogen can 
contribute to better governance of the overall energy sector’s contribution to the EU energy and 
climate targets. 

Although it is expected that some Member States will develop functioning hydrogen markets, it is 
widely recognised that interconnecting national markets further improves their liquidity and 
efficient functioning (as proved by the integration of electricity and methane markets). Timely-
introduced EU level hydrogen market and infrastructure regulation will additionally reduce the 
potential ex-post costs of regulatory harmonisation. 

EU intervention can also foster the integration of hydrogen with electricity and methane 
infrastructure and coupling of markets, which are most efficient if investments and operations are 
planned from a holistic system perspective. It is expected that hydrogen networks will eventually 
form interconnected EU-wide networks; to accelerate and facilitate this process, integrated 
planning for cross-border and trans-European networks on the EU level can bring benefits not 
achievable with national planning alone. Similarly, EU level planning could support the efficient 
repurposing of existing cross-border methane infrastructure to hydrogen. The repurposing or 
decommissioning of methane infrastructure will have potential cross-border effects on the 
hydrogen, methane and also electricity sectors. 

Some level of EU regulation in the hydrogen sector could help to increase the investment certainty, 
also by reducing the risk of inadequate regulatory intervention at the national level and by defining 
the principles and mechanisms for harmonised national regulation in the future.  

There are a number of policy objectives that should be taken into account when designing a 
regulatory framework for hydrogen networks and markets. At the highest level are the EU climate 
and energy goals (decarbonisation, security of energy supply, effective and fair competition, 
development of renewable energy and energy efficiency). These are complemented by generic 
environmental and industrial policy goals, and also the post-covid economic recovery. These policy 
drivers may necessitate a faster development of dedicated hydrogen infrastructure and markets 
than it would happen without policy intervention at the EU level. 

The EU Hydrogen Strategy explicitly considers these policy objectives and lists a number of key 
actions. The Strategy indicates that hydrogen is ‘essential to meet the carbon neutrality by 2050’, 
contributing to the global efforts to implement the Paris Agreement, and eliminating pollution. 
Moreover, an EU hydrogen value chain could employ 1 million people and support the post-COVID-
19 economic recovery. The key actions proposed by the Strategy cover the design of an adequate 
regulatory framework for hydrogen markets and infrastructure. But many others are included, 
comprising the regulatory framework for support, schemes, EU financing, fostering demand and 
scaling up production, promoting R&I, and addressing the international dimension (strengthening 
collaboration and the EU stand in international activities). 

Hence, the Strategy takes a broader approach on the hydrogen sector than this study, and also 
refers to several other instruments and actions. A regulatory framework for dedicated hydrogen 
networks and commodity markets should have clearly established primary objectives for supporting 
the development of the hydrogen sector: 

 

Increasing investment certainty by providing predictability on the regulatory framework, 
also clearly distinguishing between regulated and competitive activities; 

  Guiding the repurposing of existing methane infrastructure to hydrogen infrastructure, if 

and only when efficient from a societal perspective; 
Enabling the development of local hydrogen clusters; 

 
  Developing an efficient energy system capable of integrating high volumes of variable 
renewable energy and of decarbonising the energy supply at least cost through cross-
sectoral network planning and coupling of the electricity, methane, hydrogen and heat 
systems; 
Ensuring fair competition, preventing abuse of market power and removing barriers for 
market entry; 

 

  Creating the basis for efficient cross-border trade that ensures proper valuation of 

hydrogen; 

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Sector integration – Regulatory framework for hydrogen 

 

Fostering innovation in hydrogen technologies and infrastructures. 

Nonetheless, an EU regulatory framework for hydrogen networks and markets can contribute to 
some of the policy objectives not directly related to its main objectives. The main secondary 
objectives are thus: 

 

 

 

Promoting environmental policy objectives, for example by considering pollution impacts in 
the planning of hydrogen networks; 
Fostering R&I in all components of the hydrogen supply chain, including production and 
end-use; 
Promoting the EU hydrogen industry, e.g. through transparent and non-discriminatory 
long-term planning processes considering all available solutions, and providing long-term 
visibility on demand for hydrogen infrastructure products and services; 

  Supporting the up-scaling of investments in hydrogen production and end-use, e.g. by 
enabling long-term hydrogen purchase contracts, providing price signals to market 
participants, and also information on the network status and future development. 

The assessment of the regulatory options follows the Better Regulation Guidelines, considering the 
following additional criteria specified in the Terms of Reference: 

 
 

The ability to accommodate the different hydrogen pathways depicted in chapter 1; 
The need to regulate hydrogen transmission/distribution (and storage) infrastructure, 
according to the analysis of chapter 2; 

  Coherence of the chosen regulatory elements within each option, including between 

 

network regulation and market design elements; 
The incentives to regulated and market actors, including to the efficient conversion of 
methane infrastructure; 
  Diversity between options. 

The hydrogen sector development pathway presented in the strategy should be considered as a 
major reference for the envisaged sector regulation, and is described in the box below. Coherence 
with the principles elaborated in the recent Hydrogen Strategy are assessed, and differences duly 
justified. In addition, to account for the diversity of national strategies and the fact that the 
hydrogen sector will develop with different speeds across Member States, the different pathways 
developed in chapter 1 will be considered to assess the adequacy of the proposed regulatory 
interventions to multiple scenarios, as mentioned. 

In September 2020, the European Commission has released its 2030 Climate Target Plan, 
accompanied by an impact assessment analysing a number of scenarios for achieving GHG 
emission reductions in the range of 50-55% by 2030 compared to 1990 levels. While this 
significantly higher ambition will also impact the deployment of hydrogen technologies, the 
Hydrogen Strategy and the Long-term Strategy already depicted hydrogen-intensive pathways. 
Hence, although the final decarbonisation target will impact the hydrogen sector, it constitutes but 
one of the many highly uncertain variables influencing it. Therefore, it is considered that the 
pathways developed in chapter 1 and in the Hydrogen Strategy already cover a wide range of 
possible future outcomes, including the pathways of the 2030 Climate Target Plan Impact 
Assessment. The expected increase of the climate target to 55% might even increase the relevance 
of the present analysis. 

Transitional measures are proposed for each option to facilitate the gradual roll-out and integration 
of hydrogen systems and markets, as well as potential exemptions for existing and new 
infrastructure (except when pre-defined by the application of the current natural gas regulatory 
framework). A roadmap is also developed to indicate when regulatory framework provisions are 
expected to be phased in and transitional measures are phased out. 

The indicators for the impact assessment are presented in Table 5-1. It must be noted that several 
indicators contribute to the assessment of multiple categories. For example, energy system costs 
savings or tariff levels affect the socio-economic impacts of the regulatory option as well as its 
efficiency. This is properly accounted for in the assessment of the options in section 5.5. 

Ideally, the analysis of coherence of the options would consider the final proposals or even agreed 
versions of other EU legislation and instruments under development (such as the revised TEN-E 
regulation and Energy and Environmental Protection State Aid Guidelines). As this is not possible, 
the coherence analysis is based on the information available in November 2020, and assumes the 
TEN-E regulation will be revised to include hydrogen infrastructure in its scope. 

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Box 5-1 Sector development pathway according to EU hydrogen strategy262 

  From now to 2024, the installation of at least 6 GW of renewable hydrogen electrolysers in 

the EU and an annual production of up to 1 million tonnes of renewable hydrogen. 
o 

Infrastructure needs for transporting hydrogen will remain limited as demand 
will be met initially by production close or on site and in certain areas blending 
with methane gases might occur but planning of medium range and backbone 
transmission infrastructure should begin.  

o  The policy focus will be on laying down the regulatory framework for a liquid and well-
functioning hydrogen market and on incentivising both supply and demand in lead 
markets, including through bridging the cost gap between conventional solutions and 
renewable and low-carbon hydrogen and through appropriate State aid rules. Enabling 
framework conditions will push concrete plans for large wind and solar plants dedicated 
to gigawatt-scale renewable hydrogen production before 2030. 
Investments will be supported also through the development of a strong portfolio by the 
European Clean Hydrogen Alliance and the Strategic Forum for IPCEIs263, and the use of 
EU funding mechanisms, some part of the Commission’s recovery plan. 
In the first phase and later, the EU will support R&I in hydrogen production, 
infrastructure and end-use. Infrastructure R&I will cover hydrogen distribution, storage 
and dispensing, as well as the repurposing of methane infrastructure. 

o 

o 

  From 2025 to 2030, hydrogen needs to become an intrinsic part of our integrated energy 
system, with at least 40 GW of renewable hydrogen electrolysers and an annual production 
of up to 10 million tonnes of renewable hydrogen in the EU. Electrolyser investments in 
2020-2030 could range from 24 to 24 billion €, and investments in hydrogen transport, 
distribution, storage and refuelling stations could reach 65 billion €. 
o  Dedicated demand side policies will be needed for industrial and transport demand to 

gradually include new applications, including steel-making, trucks, rail and some 
maritime transport applications, and other transport modes. Renewable hydrogen 
will start playing a role in balancing a renewables-based electricity system by 
transforming electricity into hydrogen when renewable electricity is abundant and cheap 
and by providing flexibility. Hydrogen will also be used for daily or seasonal storage, 
as a backup and provide buffering functions, enhancing security of supply in the medium 
term. 

o  Local hydrogen clusters, such as remote areas or islands, or regional ecosystems – 
so-called “Hydrogen Valleys” – will develop, relying on local production of hydrogen 
based on decentralised renewable energy production and local demand, transported over 
short distances. In such cases, a dedicated hydrogen infrastructure can serve hydrogen 
use not only for industrial and transport applications, and electricity system balancing, 
but also for residential and commercial buildings. 

o  The need for an EU-wide logistical infrastructure will emerge, and steps will be 
taken to transport hydrogen from areas with large renewable potential to 
demand centres located possibly in other Member States. The backbone of a pan-
European grid will need to be planned and a network of hydrogen refuelling stations 
to be established. The existing gas grid could be partially repurposed for the transport of 
renewable hydrogen over longer distances and the development of larger-scale 
hydrogen storage facilities would become necessary. International trade can also 
develop, in particular with the EU’s neighbouring countries in Eastern Europe and in the 
Southern and Eastern Mediterranean countries. 

o  EU financing instruments in the first phase will be scaled up to support the significant 

investment levels. A pilot support mechanism (preferably at the EU level) will be set-up 
to support hydrogen production (in phase I or II) 

  From 2030 onwards, renewable hydrogen will be deployed at a large scale across all 

hard-to-decarbonise end-use sectors. EU investments in hydrogen production from 2020 
to 2050 would amount to 180-470 billion €. 

262 European Commission (2020). A hydrogen strategy for a climate-neutral Europe. COM(2020) 301 final. 
263 Important Projects of Common European Interest 

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Sector integration – Regulatory framework for hydrogen 

Table 5-1 Indicators for impact assessment 

Indicator 

Socio-economic 
impacts 

1.  Energy system costs savings compared to a system without regulation  
2.  Security of hydrogen supply  
3.  Network tariffs level 
4.  End-user adaptation costs 

Technical 
impacts 

Effectiveness 

5.  Allows interoperability of interconnected hydrogen systems / 
deployment of hydrogen end-use equipment/appliances 

6.  Supports system flexibility / renewable electricity 
7.  Allows repurposing of methane infrastructure when efficient  

8.  Accommodation of chapter 1 pathways  
9.  Planning and use of hydrogen cross-border infrastructure 
10. Ability to satisfy transport and large-scale industry demand 
11. Providing large-scale storage 
12. Development of local hydrogen clusters 

Efficiency 

Coherence 

Proportionality 
and subsidiarity 

13. Delivering a level playing field and competitive market, addressing 

potential abuse of market power 
14. Lowers the overall regulatory costs 
15. Enables efficient planning across energy carriers, levels and areas 
16. Efficient consideration of existing H2 infrastructure 
17. Investment efficiency, use of currently existing hydrogen and methane 
infrastructure, and reduced risk of investment in stranded assets 
18. Incentives for regulated / market operators to deploy innovative 

technologies and market products 

19. With electricity, methane (and heat) sectors regulatory framework 
20. With Hydrogen Strategy 
21. With TEN-E 
22. With Energy and Environmental Protection State Aid Guidelines 
23. Internal coherence 

24. EU has competency to act to:  
o  Contribute to proper functioning of energy markets 
o  Ensure security of energy supply 
o  Promote energy efficiency 
o  Promote interconnection of energy networks 

… which could not be ensured with national regulation alone 

25. MSs maintain right to determine own energy supply mix 

-  Hydrogen/methane/electricity network/storage operators 

(regulated/exempted/new/pre-existing) 

Affected parties 

-  Methane / hydrogen producers / traders / suppliers 
-  Methane / hydrogen consumers (industry, buildings, transport, power 

generation) 

Each regulatory framework option that will be assessed is an internally coherent combination of the 
options for each of the individual network regulation and market design elements addressed in 
chapters 3 and 4. These framework options were designed considering the objectives set in the 
chapter 5.2 (except for the ’no immediate action’ option that describes the status quo). 

Seven options were considered for assessment. After a preliminary assessment of these options 
according to the main and specific criteria, the following four options have been selected in 
concertation with DG ENER:  
  No immediate action 
 
 
 

Light EU regulation 
Full EU regulation 
Full+ EU regulation 

The options are briefly described next. An overview of the regulatory framework option assessed is 
presented in Table 5-2, and these are further detailed in Table 5-3. 

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Description of the regulatory framework options 

No immediate action 

The assessment of a “business as usual” scenario is mandated by the Better Regulation Guidelines, 
to establish the magnitude of impacts of the policy options in comparison to the baseline option. In 
this option, no changes are brought to the EU regulatory framework regarding hydrogen networks 
and markets, and Member States are hence free to regulate on the matter. 

Light EU regulation 

This package sets mainly the rules that define the ownership relations (unbundling) between 
hydrogen and methane network (and storage) infrastructure and production and supply assets and 
activities. This package would thus define the rules for main interactions with the regulated 
methane sector, but leaves the decision on other areas to the Member States, except when there is 
a risk of distortion to the internal energy market due to coupling of the hydrogen with the other 
energy sectors. 

Therefore, the ‘light EU regulation’ option defines the following regulatory elements at the EU level: 
  Role of gas TSOs and horizontal unbundling from methane networks: Common 

operation of hydrogen and methane networks is authorised by EU legislation, with at least 
accounts unbundling required; 

  Role of private hydrogen operators: NRAs may exempt specific hydrogen pipelines 
owned by merchant operators and closed distribution systems from unbundling, TPA or 
tariffication regulation; 

  Third-party access rules: Member States may choose between negotiated or regulated 

third-party access rules for networks and large-scale storage 

No specific EU regulation exists in this option for the following regulatory elements: network 
tariffication and planning, CACM, balancing and regarding organised markets platforms or 
exchanges. A Hydrogen Target Model (HTM) could provide clear guidance to the preferred approach 
for these elements, enabling Member States to develop national legislation and regulation aligned 
to the HTM. 

The package is built around the premise that the growth of the hydrogen sector will be natural and 
market driven. Member States thus would have the opportunity to adjust the level of regulation to 
the specific national situation. Front-running countries have the freedom to set up a supportive 
regulatory framework, which might provide higher better certainty for hydrogen revenue streams 
and encourage large-scale investment in infrastructure. This national framework should in any case 
be compliant with EU competition and state aid rules. 

It is also expected that most advanced countries would cooperate to create rules on cross-border 
interaction on regional level. Experience from early regulatory frameworks can then be drawn upon 
when designing regulation in other Member States, or potentially on EU level, when the cross-
border infrastructure reaches sufficient maturity. By defining a minimum set of rules for the most 
important regulatory elements, the option aims to limit the regulatory divergence. It is possible for 
national regulatory frameworks to converge when the hydrogen sector matures, becomes more 
interconnected and regional cooperation leads to regulatory harmonisation. 

Full EU regulation 

The Full EU regulatory framework is to a large extent coherent with the EU framework for natural 
gas regarding the extent of EU regulatory intervention and chosen approach for the different 
elements, while allowing for a tailored approach to hydrogen where necessary to properly account 
for its specificities compared to natural gas. The Full EU regulation thus draws on lessons learned 
not only from the EU gas regulatory framework but also from the new EU electricity market design. 
The approach of extending the Gas Market Design to hydrogen is not adopted in this or the other 
options, but is briefly analysed in Box 5-3. 

Hence, the approach to elements such as unbundling, TPA, network tariffication, planning, CACM 
and balancing is similar to the EU natural gas regulatory framework. Specifically, the ‘Full EU 
regulation’ option defines the following regulatory elements at the EU level: 

  Role of gas TSOs and horizontal unbundling from methane networks: Common 

operation of hydrogen and methane networks is authorised by EU legislation, with at least 
accounts unbundling required; 

  Role of private hydrogen operators: NRAs may exempt specific hydrogen pipelines or 
isolated systems owned by merchant operators and closed distribution systems from 
unbundling, TPA or tariffication regulation; 
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  Third-party access rules: Third-party access rules is required for all non-exempted 

hydrogen networks. Member States may choose between negotiated or regulated third-
party access rules for large-scale storage; 

  Network tariffication: harmonised principles and tariff structures are in place; 
  Planning: A ENTSO-H2 is set-up with similar responsibilities as the existing ENTSOs, and 

national planning requirements are also defined; 

  CACM:  rules for cross-market area CACM are established; 
  Balancing: Market players have the primary balancing responsibility, with TSOs realising 
the residual balancing. Balancing zones are national/regional depending on the voluntary 
cooperation between Member States and network operators; 

  Organised markets: Harmonised market rules exist, and hydrogen markets are included 

in the REMIT scope. 

Given the different development stages of the methane and hydrogen sectors, a number of 
transitional measures are foreseen (detailed in section 3.9), including a Hydrogen Target Model 
(see Table 1-1). Moreover, a provision similar to Article 49 of the Gas Directive on emergent and 
isolated markets would derogate from several provisions Member States whose hydrogen systems 
are not directly connected to any other Member State. These derogations would apply to relevant 
hydrogen cross-border aspects, while provisions necessary to avoid distortions to the internal 
energy market should still be applied even for isolated hydrogen systems, given the coupling of 
local hydrogen clusters with the electricity and methane systems. 

Box 5-2 The Hydrogen Target Model 

A Hydrogen Target Model (HTM) provides the vision of how an integrated hydrogen system and 
market should function in the medium to long term. It defines an end-point of the regulatory 
process of dedicated hydrogen infrastructure and markets, and also suggests how this end-point 
might be achieved (e.g. with major provisions to be laid down in network codes). It also defines 
the basic principles related to market design and rules. It thus gives clear guidance to the 
regulation, implementation and revision of specific EU regulatory elements, as well as for 
Member States to develop complementary national legislation and regulation aligned to the HTM. 
Determining a Hydrogen Target Model is as such not a regulatory measure, but it is considered 
an adequate preliminary EU action, to guide future initiatives both at EU and national level. 

Full+ EU regulation  

As its name indicates, the Full+ EU regulation builds on the Full EU regulatory option, but is more 
ambitious for a number of aspects. It takes a ‘greenfield’ approach to some regulatory elements 
departing from the methane and electricity EU regulatory frameworks, which were constrained by 
what was feasible at the time of their introduction.  

The ‘Full+ EU regulation’ options consists of the following additional specific measures: 

  Role of private hydrogen operators: Strengthens access to all networks by restricting 

exemptions to existing hydrogen network operators; 

  Organised markets: Establishes nominated hydrogen market operators; 
  Planning: Establishes an EU H2

 TSO and conducts determinative network planning of 

trans-European or EU-relevant hydrogen networks  

o  With EU approval of methodology, scenarios and EU network development plans; 
o  With harmonised requirements for national planning and NRA approval of 

methodology, scenarios and NDPs; 

o  With the requirement for inclusion of EU network projects in NDPs (to the extent 

that this is compliant with the future TEN-E Regulation). 

  CACM: Establishes an EU capacity allocation and congestion management platform, 

integrates day-ahead and intraday hydrogen markets by market coupling and an inter-TSO 
compensation mechanism for cross-border flows; 

  Balancing: Integrates balancing zones through a balancing market coupling platform. 

Furthermore, exemptions to existing hydrogen network operators could be granted only upon 
authorisation from NRAs: 

For a limited duration (i.e. sunset clause); and/or 

 
  With a market test demonstrating there are no existing market participants with firm 

interest in accessing the network. 

The Full+ option is thus the most ambitious option in providing an EU regulatory framework 
advancing integrated planning across market areas, regulated energy carriers and network levels, 
market integration including market coupling measures, and generally providing a level playing 

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field for all internal energy market participants. Nonetheless, it maintains many of the transitional 
measures and exemptions foreseen in the Full EU option. 

Box 5-3 Extension of the Gas Market Design to hydrogen 

A potential approach to develop a regulatory framework for hydrogen is updating the definition 
of gas and other articles of the Gas Directive and Regulation to include hydrogen. In this option 
there would be only one gas sector and one gas definition, encompassing methane and hydrogen 
gases.  

This option has been proposed by some gas sector stakeholders. They argue that with some 
modifications of the Gas Directive and Regulation as well as the consideration of transitional 
measures as necessary, this would be a feasible and beneficial approach, building on the mature 
regulatory framework for natural gas. 

While it would be possible to apply the principles of the EU regulatory framework for natural gas 
to hydrogen networks (and storage) without further modifications, in legal terms it is not 
possible to apply the concerned legislation as is. The EU Gas Directive and Regulation were 
developed for natural gas, addressing hydrogen only in so far as it “can technically and safely be 
injected into, and transported through, the natural gas system”. Hence, there are ambiguities 
and unaddressed aspects in the EU regulatory framework which need to be clarified or modified, 
regardless of whether they are to be applicable to hydrogen,264 to provide further demarcation 
between methane and hydrogen legislation, or to enable a single regulatory framework for both 
gases. 

Taking into account its complexity and drawbacks, this approach was not considered for 
assessment. The design of a regulatory framework for hydrogen can draw on multiple best 
practices of the methane one, and there are advantages of mirroring some regulatory aspects. 
The importance of repurposing methane networks highlights the advantages of allowing 
combined gas network operators and adequately considering the interlinkages between the 
hydrogen and methane sectors. However, there are a number of reasons for not applying a 
single regulatory framework to both gases: 

  While natural gas is mainly imported into the EU based on demand, hydrogen is 

expected to be produced to a large extent within the EU, mainly driven by demand but 
also partly driven by supply (flexibility needs in the electricity system). The network 
configuration and the role of transit will hence be different. 

 

  While methane and hydrogen networks share many common economic and technical 
characteristics, supply technologies and sources for hydrogen (such as power-to-gas) 
may differ significantly. This may require differences in elements such as market product 
characteristics, network revenue regulation and tariff structures; 
Electrolytic hydrogen is expected to play a central role in the hydrogen sector in the long 
run. Coupling of the hydrogen with the electricity sector implies that coherence with the 
electricity market design will be as important as with the methane market design; 
  Addressing the differences in technical & economic characteristics and developmental 
stages between hydrogen and methane would require a large number of specific 
provisions for either sector, unduly complexifying the regulatory framework; 
To some extent, the ‘greenfield’ nature of the hydrogen sector allows for increased 
ambition of the EU regulatory framework to more quickly promote an internal hydrogen 
market, while a single regulatory framework for both natural gas and hydrogen would 
not easily enable increased ambitions (or reduced EU regulatory intervention when 
beneficial); 

 

  Separate regulatory frameworks lead to increased transparency in cost allocation to 

methane and hydrogen network users, reducing the potential for undue cross-
subsidisation. 

264 See for example GEODE (2020). Towards the New Age of Gas Networks: Proposal on the Regulation of a 
European Hydrogen Infrastructure; Benrath (2019). Applicable law to hydrogen pipelines for energy purposes in 
Germany. Journal of Energy & Natural Resources Law; FNBGas et al. (2020) Auf dem Weg zu einem 
wettbewerblichen Wasserstoffmarkt Gemeinsamer Verbändevorschlag zur Anpassung des Rechtsrahmens für 
Wasserstoffnetze 

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Table 5-2 Overview of regulatory framework options assessed265 

Role of gas 
TSOs 

Horizontal 
unbundling 
from 
regulated CH4 
infra 

Role of 
private 
hydrogen 
networks 

TSO network 
TPA rules 

Network 
tariffication 

Planning 

No immediate 
EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

Common operation authorised by EU law 

+ EU-level H2 TSO 

Accounts 

Accounts 
Variant: legal + functional 

Exemption from unbundling, rTPA, 
rTariffs for specific cases 

Legal unbundling, rTPA and rTariffs 
Exemptions requires a market test / sunset clause 

rTPA / nTPA choice 

Regulated TPA 

Not regulated 
at EU level 

Harmonised principles and tariff 
structures 

Market coupling + Harmonised 
principles and tariff structures 

ENTSO-H2 
Requirements for national planning 

With EU TSO organisation 
Requirements for national planning 

CACM 

No H2 specific EU regulation 

Rules for cross-market area CACM 

Market coupling 
Rules for cross-border and domestic 
CACM 

Balancing 

Access to 
storage 

Organised 
market 
platforms or 
exchanges 

Individual balancing responsibility for 
market players 
Residual balancing by TSOs 
National/multinational balancing zones 

Individual balancing responsibility for 
market players 
Residual balancing by EU TSO 
EU balancing zone 

rTPA / nTPA choice 

Regulated TPA 

No H2 specific EU regulation 

Harmonised market rules 
REMIT scope includes hydrogen 

+ market area managers 

265 Transitional measures are not indicated. All network codes (e.g. for congestion) should not be developed in the short term, but the principles (“Target regulatory model”) should be 
defined, and all transitional measures and (national) regulatory initiatives would need to be compliant with the target model. 

129 

 
 
 
 
 
 
 
                                                
Table 5-3 Detailed parameters of the regulatory framework options selected  

Note: - denotes no regulation at the EU level. MSs are free to regulate / market operators to cooperate regarding parameters when applicable. 
No immediate action 

Light EU regulation 

Full EU regulation 

Parameter 

Category 

Full+ EU regulation 

Network 
activity 
regulation 

Unbundling 

Role of 
private 
hydrogen 
networks 

Owning/operating hydrogen networks 
is a competitive/regulated activity 

Hydrogen and methane gases 
definition 

Common ownership/operation of CH4 
and H2 networks? 

Vertical unbundling 

Horizontal unbundling from regulated 
CH4 infra 

Exemptions to existing private 
hydrogen networks? 

Exemptions to new private hydrogen 
networks?267 

TPA 

TSO network third-party access 

Entry-exit / path-based system 

Harmonised cross-market area tariff 
principles? 

Network 
tariffication 

Harmonised intra-market area tariff 
principles? 

Same tariff rules as NG? 

Market coupling mechanism? 

- 

- 

- 

- 

- 

- 

- 

- 

- 

- 

- 

Defined by MS with 
harmonised market 
test principles 

Regulated 

Separate gases 

Allowed 

Accounts 
Legal+functional for 
combined gas 
operators 

Legal+functional 

Accounts 

Accounts 
Variant: legal 

Upon NRA authorisation266 

rTPA / nTPA choice 

- 

- 

- 

rTPA 

Entry-exit 

Yes 

No 

Yes 

Separate, but mirroring possible 

- 

- 

Implicit with ITC-like 
mechanism 

266 NRA authorisation requirements established in EU legislation for all parameters 
267 Exemptions from unbundling, rTPA and rTariffs for hydrogen clusters, isolated markets, merchant operators, closed distribution systems. 

130 

 
 
 
                                                
Sector integration – Regulatory framework for hydrogen 

Category 

Parameter 

No immediate action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

Re-allocation of non-remunerated 
system benefits between 
hydrogen/methane/electricity268 

EU planning process 

Cross-carrier planning269 

Cross-border planning 

Planning 

National planning 

EU oversight 

National oversight 

CACM 

Rules for cross-market area CACM? 

Harmonised rules for domestic CACM? 

Balancing 

Cost recovery 

Balancing responsibility 

Access to 
storage 

Organised 
market 
platforms or 
exchanges 

Balancing market coupling / merger 

TPA to large-scale storage271 

Single gas commodity market? 

Harmonised hydrogen markets rules? 

Mutual recognition of licenses? 

REMIT reporting obligations? 

Market area managers? 

- 

Allowed, harmonised principles 
Variant: single RAB allowed 

- 

- 

- 

- 

- 

- 

- 

- 

- 

- 

- 

TYNDP-like process by 
ENTSO-H2 

Determinative planning 
by EU H2 TSO 

Common scenarios and 
consideration of main 
interactions 

Common scenarios, 
modelling and TYNDP 

EU-level planning 

EU-level planning 

Harmonised 
requirements 

Harmonised 
requirements 

Methodologies and 
scenarios: EC approval, 
ACER opinion. 
TYNDP: ACER 
opinion270 

Methodologies and 
scenarios: EC approval, 
ACER opinion. 
TYNDP: ACER approval 

Required approval 

Required approval 

Yes 

- 

Yes 

Yes 

With BRP 

With BRP 

Residual through tariffs  Residual through tariffs 

- 

Coupling 

rTPA / nTPA choice 

rTPA / nTPA choice 

rTPA 

- 

- 

- 

No 

- 

No 

Yes 

Yes 

Yes 

Yes 

No 

Yes 

Yes 

Yes 

Yes 

- 

- 

- 

- 

- 

- 

- 

- 

- 

- 

- 

- 

- 

- 

- 

No 

- 

268 While subsidisation is not within the scope of hydrogen infrastructure and market regulation, it is addressed in the discussion of the regulatory elements (Chapter 3). Subsidisation 
of hydrogen related activities would be possible under the current EEAG and GBER. 
269 Also with electricity. 
270 At present, the European Commission approves the methodology, while ACER provides opinions on the methodology, scenarios and gas TYNDPs. 
271 Owning/operating hydrogen storage < threshold (TBD) would be a competitive activity. New or refurbished underground storage sites are expected to have a capacity > threshold. 

131 

 
 
 
                                                
The following tables present the assessment of the four hydrogen regulatory framework options, 
according to the indicators listed in Table 5-1 for the following main criteria: 

Economic impacts 
Technical impacts 
Effectiveness 
Efficiency 

 
 
 
 
  Coherence 
 
  Affected parties 

Proportionality and subsidiarity 

These main criteria take into account the specific criteria required by the Terms of Reference: 

  Accommodation of various pathways; 
  Delivering a level playing field and competitive market, addressing potential abuse of 

market power; 
Investment efficiency; 

 
  Reducing ex-post costs, uncertainty and risks for technologies and business models; 
  Accounting for pre-existing infrastructure and operators. 

Table 5-4 provides a summary of the assessment for the criteria. The affected parties are only 
indicated in the detailed assessment tables, available in Annex A. 

132 

 
 
 
 
 
 
No immediate 
action 

Light EU 
regulation 

Full EU 
regulation 

Full+ EU 
regulation 

Table 5-4 Summary of impact of regulatory packages according to assessment criteria 

Economic 
impacts 

Technical 
impacts 

Criteria 

1. Energy system costs savings 

2. Security of hydrogen supply 

3. Network tariffs level 

4. End-user adaptation costs 

5. Interoperability/equipment/appliances 

6. Supports flexibility / renewable electricity  

7. Efficient repurposing of CH4 infrastructure  

8. Pathways accommodation 

9. Planning and use of cross-border H2 infra 

-- 

- 

-- 

0 

0 

- 

- 

+ 

-- 

0 

- 

- 

0 

0 

- 

0 

+ 

-- 

Effectiveness 

10. Ability to satisfy transport/industry demand 

+/++ 

+/++ 

Efficiency 

11. Providing large-scale storage 

12. Development of local hydrogen clusters 

13. Level playing field and competitive market 

14. Overall regulatory costs 

15. Investment efficiency / Asset stranding 

16. Efficient planning (carriers/levels/areas) 

17. Accounting for existing H2 infrastructure 

18. Innovative techs/market products incentives 

19. With energy sectors regulatory framework 

20. With TEN-E 

Coherence 

21. With EEAG 

22. With hydrogen strategy 

23. Internal coherence 

0 

+ 

- 

+ 

-/0 

-- 

+ 

0 

-- 

-/+ 

+ 

-- 

++ 

Legend:  
++ / + : measures explicitly support the objective 
 0 : neutral/no clear relation / impact on the objective 
- / -- : measures pose barriers for achieving the objective 

133 

+ 

++ 

- 

++ 

-/0 

-- 

0 

0 

0 

-/+ 

- 

- 

++ 

Yes 

+ 

+ 

+ 

+ 

+ 

+ 

+ 

++ 

+ 

0 

+ 

0 

+ 

- 

+ 

+ 

0 

++ 

+ 

+ 

- 

+ 

++ 

Yes 

++ 

+ 

++ 

+ 

+ 

++ 

++ 

+ 

++ 

0 

++ 

0 

++ 

-- 

++ 

++ 

- 

+ 

++ 

+ 

- 

+ 

++ 

Yes 

Proportionality & 
subsidiarity 

24. Regulation at EU level is justified 

Not applicable 

25. Right for MS to determine energy supply  

No restrictions 

No restrictions 

No restrictions 

No restrictions 

 
 
Transitional measures 

The measures below aim to providing flexibility for an early development of hydrogen clusters, 
increase the robustness of the regulatory options (i.e. the capacity of each regulatory framework 
option to accommodate the different hydrogen development pathways) and reduce the regulatory 
burden to Member States, network operators and market actors. They would be phased out when 
the (internal) hydrogen market becomes mature. However, some measures may remain in place 
even in a mature hydrogen market, especially potential waivers and exemptions to new 
investments and CDSs – given that even in a mature market these may be necessary in specific 
cases to foster investments. 

The table below indicates which transitional measures are foreseen for each regulatory framework 
option. Based on the analysis of section 3.9, the different possible transitional measures are: 

  Hydrogen Target Model: the HTM should determine all relevant regulatory framework 
elements, including those that are not foreseen to be phased in immediately at the entry 
into force of the EU legislation. The legislation should establish a process for developing EU 
network codes and guidelines for these elements at a later point of time. The target model 
for hydrogen systems and markets should be developed in an early phase at EU level and 
should specify the vision for the final market organisation, in particular with regards to 
cross-border interactions, harmonisation of relevant regulatory elements and coupling of 
market zones. This vision should guide national authorities in designing their regulatory 
framework and prevent regulatory divergence. The experience from more advanced 
Member States and regional cooperation initiatives together with the HTM (that could be 
periodically updated, when necessary) could then also support the development of the 
network codes and guidelines. 

  Exemption procedures for developing isolated hydrogen clusters: These waivers 

should in principle serve to enable the regulatory flexibility of isolated hydrogen clusters, 
even in MSs that might have other interconnected network system (and thus would not 
qualify for the general MS derogation). This could, for example, happen in a country that 
will develop a hydrogen transit pipeline, but where hydrogen clusters might be developed 
in parallel. A transit pipeline requires generally a more detailed network planning analysing 
demand on EU-level to justify the investment, which is irrelevant for the local hydrogen 
cluster. This instrument does not have to be necessary phased out with time to incentivise 
interconnections, but could be limited in duration – a waiver for a particular isolated 
network could be for example limited to 10 years after it was granted. This waiver could be 
granted by respective NRAs, with approval from or a notification procedure to the 
Commission, based on an application from the network operators. 

  MS derogations for isolated systems: These derogations could apply to MSs whose 

networks are not connected to the European hydrogen network, similarly to Article 49 of 
the Gas Directive on emergent and isolated markets. As this instrument should not 
disincentivise MSs from developing interconnections, derogations should be temporary and 
phased out by a certain date, for example 2030 (to reflect the Hydrogen strategy). In cases 
where the exemption procedures for isolated hydrogen clusters are sufficient to enable 
their initial development, an MS derogation should not be granted in order to incentivise 
interconnection.  

  Exemption procedures/waivers for pre-existing network operators: Exemptions to 
unbundling, TPA and other requirements for pre-existing operators should be allowed only 
when it is demonstrated that the social benefits of the considered rules would not outweigh 
its social costs. A market test could be conducted to identify the interest of third-parties in 
accessing a pre-existing network. Incentives could be granted to pre-existing operators to 
unbundle and provide third-party access. Such requirements could also be phased in 
gradually, entering into force only once existing supply contracts expire. 

  Network planning processes: As an EU-level planning process for regulated hydrogen 

infrastructure will need to be developed from scratch, it will need to be improved 
throughout various iterations. In the ‘Full+ EU’ option, requirements such as the use of a 
fully-integrated energy systems model can be phased in when the EU H2 TSO develops its 
planning model. Network operators which are exempted from TPA requirements could be 
also exempted from participating in EU-level planning processes for a limited duration. 
They should nonetheless provide information on e.g. forecasted demand so that it can be 
taken into account in the hydrogen, methane and electricity planning processes. 
  Others: Regulatory sandboxes should address specific regulatory barriers hampering 

technological or business model innovation, such as new forms of investments in hydrogen 
infrastructure or efficient operation of the hydrogen system. The EU sandbox model should 
clearly delimit the scope of application (e.g. specific legislative articles from which the 
experiment could be exempted) and define requirements for the transparent, non-
discriminatory design, monitoring and evaluation of the sandbox. 

134 

 
 
 
Table 5-5 Transitional measures applicable per regulatory framework option 

Transitional 
measure 

No immediate action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

Hydrogen Target 
Model 

 No Hydrogen Target 
Model specified 

 Potential Hydrogen Target 
Model (HTM) on aspects not 
regulated initially such as 
planning, tariffication and 
CACM 

 From vertical unbundling 
and relevant cross-border 
aspects 

 NRAs can exempt operators 
based on defined procedure. 

 No EU level provisions 
requiring derogation 

 Not defined at EU level 

MS derogations 
to isolated 
clusters / 
systems 

Waivers / 
exemption 
procedures for 
pre-existing 
network 
operators 

Network planning 
processes 

Others 

 HTM focuses on CACM, 
harmonisation of market rules 

 HTM focuses on CACM, 
harmonisation of market rules and 
eventual market coupling. 

 Previous option+ 
 From CACM rules 
 From entry-exit system and 
balancing responsibility 
 From market harmonisation 
regulation 

 NRAs can exempt operators based 
on defined procedure. A market test 
can be required and sunset clauses 
foreseen. 
 Exempted networks should still be 
included in the network planning 
process 

 Networks exempted from TPA 
requirements could just provide 
information on e.g. forecasted 
demand to the ENTSO-H2 

 Previous option+ 
 Harmonisation of intra-market area 
tariff principles 
 Implicit market coupling 

 NRAs can exempt operators based 
on defined procedure. A market test 
can be required and sunset clauses 
foreseen. 
 Exempted networks should still be 
included in the network planning 
process 

 Planning requirements to the EU 
H2 TSO could initially focus on cross-
border infrastructure and employ 
less developed integrated energy 
systems models 

 Regulatory sandboxes that are in 
line with the Hydrogen Target Model 
could be allowed  to gain experience 
for later design of missing regulatory 
elements 

 Regulatory sandboxes that are in 
line with the Hydrogen Target Model 
could be allowed  to gain experience 
for later design of missing regulatory 
elements 

135 

 
 
 
Robustness of regulatory framework options to the hydrogen gas infrastructure 
development pathways 

To further evaluate the impacts and appropriateness of the considered regulatory options, an 
additional analysis of their adequacy for the different development pathways (defined in Chapter 1) 
has been undertaken. In those pathways, different regulatory elements will become important for 
the concerned MSs as their network may vary in role, density, size and interconnectedness or type 
of connected consumers. The main factors for every pathway are summarised below. 

Pathway 1: Full H2 grid integration 

-  Characterised by strong coupling of hydrogen with other sectors, further extension of the grid 

and/or cross-border integration. 

-  It is supposed that adequate regulatory frameworks for the development of domestic networks 

and liquid domestic markets can be adopted on a national level. However, supra-national 
harmonised rules on cross-border aspects are necessary to fully capture the potential benefits of 
markets and systems integration, and to avoid internal market distortions. 

-  Since hydrogen imports might be needed in some MSs, and others will exploit their renewable 

energy potential for hydrogen exports, the establishment of an interconnected network and EU-
wide market is needed to enable cross-border trade. 

-  The pathway requires regulatory flexibility for the initial development of hydrogen clusters, which 

will later be connected at the national and cross-border levels. 

-  Cross-sectoral planning is relevant as hydrogen is supposed to provide flexibility to the electricity 
system, to promote the refurbishment of some of the methane networks when efficient (and to 
avoid over-investment in potentially stranded assets), to avoid inefficient decommissioning of 
methane infrastructure, and to develop cross-border infrastructure. 

-  Due to expected significant development of hydrogen networks (not only through repurposing 

existing methane networks, but also by constructing new pipelines), the investment might appear 
attractive not only to incumbent natural gas network operators but also to other actors who 
might compete for the development of hydrogen networks. 

Pathway 2: H2 grid upscaling 

-  Characterised by strong development of the grid and some coupling of hydrogen and other 

sectors, while cross-border integration is less relevant for concerned MSs than in Pathway 1. 
-  There is an important role of planning to determine the future extent of demand and required 

grid, to assure timely development given the fast network growth, to promote the refurbishment 
of some of the methane networks when efficient, and avoid inefficient decommissioning of 
methane infrastructure. The vision also requires firm policy signals on target development levels. 

-  Cross-sectoral planning is also very important as hydrogen is supposed to provide flexibility and 

balancing services to electricity network,  

-  When new hydrogen networks will be constructed, there is more potential to adopt competition 

“for the market”. Organising competition may have a positive impact on the system costs, 
provided that the configuration (route, capacity) is properly determined from an overall energy 
system perspective.  

-  Balancing & storage rules will be the focus of national regulation, given more limited cross-border 

integration. 

-  The pathway requires regulatory flexibility for the initial development of hydrogen clusters, which 

will later be connected at the national and sometimes cross-border level. 

-  Cross-border aspects will be less important (initially) as the focus will be on solving national 

challenges. But strong coupling with the electricity sector will require cross-border harmonisation 
in order not to distort competition also in other energy sectors. 

Pathway 3: H2 grid downsizing 

-  Existing methane infrastructure will be downgraded in size and sometimes repurposed to 

hydrogen. Significant decommissioning and possibly devaluation of existing assets may occur. 

-  Operators will face declining revenues from the operation of methane networks, financing 

hydrogen infrastructure might be problematic without public support. 

-  Protection of methane consumers might be an issue due to grid defection and incentives for the 

network operator to realise inefficient investments in hydrogen (‘gold plating’). 

-  The pathway requires regulatory flexibility for hydrogen clusters which may remain isolated. 
-  Strong planning oversight required to avoid over-investments in H2 networks. 

136 

 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Pathway 4: Transit-focused H2 grid 

-  The focus of countries following this pathway will be on developing transit pipelines, rather than 
on developing domestic systems/markets (or if so, they would focus on large industrial actors, 
which reduces the potential of network operators to abuse their natural monopoly) 

-  Long-term contracts are needed to build new transit pipelines (in case of developing new transit 

routes, e.g. from North Africa) 

-  The pathway requires regulatory flexibility for hydrogen clusters which may remain isolated from 

transit backbones. 

-  EU level system planning beneficial to analyse if existing transit pipelines can be converted, 

without hampering EU security of supply (e.g. pipelines from Ukraine that might face low or no 
utilisation rates when new natural gas import routes will be constructed). 

Based on the factors affecting the main pathways, the adequacy of the regulatory options to each 
pathway is summarised in Table 5-6 and further detailed in Table 5-7. 

Table 5-6 Summary of the pathway assessment 

Pathway 

No immediate action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

PW1: Full 
H2 grid 
integration 

PW2: H2 
grid 
upscaling 

PW3: H2 
grid 
downsizing 

PW4: 
Transit-
focused H2 
grid 

Provides regulatory 
flexibility to develop 
local hydrogen 
clusters. Does not 
allow sufficient network 
development, cross-
border integration and 
sector coupling. 

Provides regulatory 
flexibility to develop 
local hydrogen 
clusters. Lack of 
network planning and 
cross-border 
integration reduces the 
potential benefits of 
cross-sectoral 
integration. No 
regulation to ensure 
fair competition across 
sectors. 

Provides regulatory 
flexibility to develop 
local hydrogen 
clusters. Risk of 
overinvestment in 
hydrogen infrastructure 
by incumbent methane 
TSO (and also 
increased tariffs for 
remaining NG grid 
users).  

Does not provide EU-
level planning 
framework to justify 
development of transit 
pipelines. EU-level 
security of supply is 
not considered if major 
methane transit 
pipelines are 
converted. Lack of 
investment certainty 
for the large projects. 

Provides basic rules 
for competition and 
non-discriminatory 
access, but cross-
border integration and 
sector coupling still 
not sufficiently 
addressed. 

Provides investment 
certainty for network 
development, 
facilitates cross-border 
market integration. 
Exemptions provide 
regulatory flexibility. 

Provides investment 
certainty for network 
development, 
maximises cross-
border and sector 
coupling synergies. 
Exemptions provide 
regulatory flexibility. 

Network planning and 
cross-border rules 
sufficient to realise 
benefits of integrating 
energy sectors (also 
increasing investment 
certainty). Rules for 
fair competition across 
sectors established. 

Provides regulatory & 
investment certainty 
for timely network 
development. Focus on 
EU level benefits might 
be detrimental to the 
initial goal of fulfilling 
national needs 
(integration of RES). 

Provides regulatory 
framework to ensure 
fair transition of the 
methane grid. 
Exemption procedures 
foreseen for local 
hydrogen clusters 
development if not 
addressed by 
exemptions. 

EU-level planning 
guides the efficient 
transformation of 
methane 
infrastructure. EU 
regulation would be too 
restrictive for local 
hydrogen clusters 
development if not 
addressed by 
exemptions. 

Provides more 
substantial justification 
for development of 
transit pipelines and 
harmonisation of rules 
for cross-border 
trading. EU regulation 
would be too restrictive 
for local hydrogen 
clusters development if 
not addressed by 
exemptions. 

EU-level TSO might be 
in better position to 
develop transit 
pipelines than national 
players. EU regulation 
would be too restrictive 
for local hydrogen 
clusters development if 
not addressed by 
exemptions. 

Provides basic rules for 
competition and non-
discriminatory access. 
Lack of network 
planning and cross-
border integration 
reduces the potential 
benefits of cross-
sectoral integration. No 
regulation to ensure 
fair competition across 
sectors. 

Provides basic rules for 
competition and non-
discriminatory access. 
Allows regulatory 
flexibility to develop 
local hydrogen 
clusters. Risk of 
overinvestment and 
unfair tariffs for NG 
grid customers only 
partially addressed by 
horizontal accounts 
unbundling.  

Provides basic rules for 
competition and non-
discriminatory access. 
Lacks EU-level 
planning framework for 
development of transit 
pipelines. EU-level 
security of supply is 
not considered if major 
methane transit 
pipelines are 
converted. Lack of 
investment certainty 
for large projects. 

137 

 
 
 
 
 
Table 5-7 Regulatory framework options robustness 

Pathway 

No immediate action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

PW1: Full H2 
grid 
integration 

PW2: H2 grid 
upscaling 

 Regulatory flexibility for MSs to 
design tailored regulation, enabling 
liquid domestic markets 
 Reduces investment certainty and 
increases transaction costs for 
network expansion, delaying 
investments and market integration, 
creating risk of underinvestment. 
 EU regulation at later stage will 
probably lead to ex-post costs 
 Lack of cross-border cost and 
capacity allocation mechanism and 
EU-level planning will make it harder 
to develop cross-border capacities 
and integrate markets 
 Lack of TPA enforcement would limit 
the access of small actors to the 
network if not addressed on national 
level. 

 Hydrogen network build-up can be 
coordinated with electricity sector on 
national level, but without EU-level 
planning & coordination the benefits 
of large-scale system integration will 
be lost 
 Regulation of balancing and storage 
will have to be designed on national 
level 
 No need for designing cross-border 
rules early on if they are not needed 
 Market oversight to guarantee fair 
competition across sectors (e.g. 
electricity and H2 markets) not 
guaranteed  

 MSs can adopt early regulation 
complementing the EU framework 
 EU regulation will have to be adjusted at 
later stage (due to Hydrogen Strategy 
ambitions). This poses a risk of ex-post cost 
of regulatory adjustment; reduces 
investment certainty and may delay the 
necessary investment to develop hydrogen 
markets 
 Lack of cross-border harmonisation and 
EU-level planning will make it harder to 
establish import routes for developed 
markets with large demand 
 Horizontal accounts unbundling for CH4 
TSOs will reduce their competitive 
advantage over new network operators 

 Unbundling, TPA rules and 
measures for market integration 
provide regulatory certainty, 
facilitating investments in the long-
term. 
 Exemption procedures for certain 
networks and staged applicability 
of cross-border-related rules 
provides flexibility for initial roll-
out of networks 
 Harmonisation of tariffs, cross-
border capacity allocation 
regulation and EU level planning 
harmonisation fosters cross-border 
integration of networks and 
markets and potentially enables 
creation of import routes to 
developed hydrogen markets 

 Hydrogen network build-up can be 
coordinated with electricity sector on 
national level, but without EU-level planning 
& coordination the benefits of large-scale 
system integration will be lost 
 Regulation of balancing will have to be 
designed on national level 
 EU-level regulation of storage provides 
more certainty for the business  
 No need for designing cross-border rules 
early on if they are not needed 
 Basic EU rules regulating “competition for 
the market” ensure market power abuse 
will be checked, horizontal accounts 
unbundling for CH4 TSOs will reduce their 
competitive advantage 
 Market oversight to guarantee fair 
competition across sectors (e.g. electricity 
and H2 markets) not guaranteed 

 Unbundling, TPA rules and 
measures for market integration 
provide regulatory certainty, 
facilitating investments in the long-
term. These rules also provide 
better link to external markets, 
improving the EU-level system 
efficiency 
 Exemption procedures for certain 
networks and staged applicability 
of cross-border-related rules 
provides flexibility for initial focus 
on domestic system integration 
 Competition for the market 
sufficiently regulated on the EU 
level 
 EU-level market regulation 
provides better guarantees for fair 
competition across sectors 

 Unbundling, TPA rules and 
measures for market integration 
provide regulatory certainty, 
facilitating investments in the 
long-term. 
 Exemption procedures for 
certain networks and staged 
applicability of cross-border-
related rules provides flexibility for 
initial roll-out of networks 
 Creation of EU TSO and EU-level 
network planning facilitates 
creation of import routes for 
developed hydrogen markets 

 Unbundling, TPA rules and 
measures for market integration 
provide regulatory certainty, 
facilitating investments in the 
long-term. These rules also 
provide better link to external 
markets, improving the EU-level 
system efficiency 
 Focus on EU level (EU TSO) 
might be detrimental to 
addressing national needs 
(integration of renewable 
electricity) 
 Competition for market problem 
solved by creating EU TSO 

PW3: H2 grid 
downsizing 

 Effective planning and revenue 
regulation not ensured on EU level, 
thus it might lead to inefficient 
investment in hydrogen infrastructure 

 Efficient network planning not guaranteed 
at EU level, potentially risking inefficient 
infrastructure transformation in hydrogen 
infrastructure (gold plating), 

 EU requirements on national 
planning can ensure the 
transformation of infrastructure will 

 Harmonised EU-level network 
planning will guide the efficient 
transformation of infrastructure 

138 

 
 
Sector integration – Regulatory framework for hydrogen 

Pathway 

No immediate action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

(gold plating), NG users paying for 
investments in hydrogen 
infrastructure in MSs with now 
incentives to develop proper 
regulatory framework 
 Risk of increasing tariffs for 
remaining CH4 users due to lack of 
tariff and revenue regulation 
 Allows flexibility for development of 
local hydrogen clusters 

 Horizontal accounts unbundling (from CH4 
infrastructure) ensures better transparency 
in revenue regulation, thus reduces risk of 
revenue reallocation from CH4 to H2 
infrastructure construction 
 Risk of increasing tariffs for remaining 
CH4 users due to lack or tariff and revenue 
regulation 
 Allows flexibility for development of local 
hydrogen clusters 

 Due to absence of EU level planning 
and scenarios predicting future 
demand, sound justification for 
building the transit pipelines will be 
missing 
 (EU-level) security of supply is not 
considered 
 Allows long-term contracts to secure 
revenues for transit pipeline 
development 
 Lack of rules on cross-border 
interactions will be a barrier to 
development of cross-border transit 
pipelines 
 Uncertainty regarding regulatory 
frameworks and market 
developments in other MSs can raise 
the costs of project financing and 
deter (or delay) necessary investment 
 Minimal market regulation allows 
more flexibility for market that is 
expected to be focused on large 
consumers, allows flexibility for 
potential development of hydrogen 
clusters separately from transit routes 

 Due to absence of EU level planning and 
scenarios predicting future demand, sound 
justification for building the transit pipelines 
will be missing 
 (EU-level) security of supply is not 
considered 
 Allows policy support for transit projects 
 Lack of rules on cross-border interactions 
will be a barrier to development of inter-
state pipelines 
 Uncertainty regarding regulatory 
frameworks and market developments in 
foreign countries can raise the costs of 
project financing and deter (or delay) 
necessary investment 
 Minimal market regulation allows more 
flexibility for market that is expected to be 
focused on large consumers, allows 
flexibility for potential development of 
hydrogen clusters separately from transit 
routes 

be efficient and will take into 
account remaining CH4 consumers 
 EU-level guidelines on 
reallocation of revenues across 
sectors and tariffication rules 
ensure fair prices for CH4 and H2 
users 
 Rules on balancing, organised 
market platform or establishing 
entry-exit system might be too 
restrictive for local hydrogen 
clusters 

 EU-level demand scenarios will 
provide justification for transit 
pipeline development, although 
lack of common network models 
for all sectors does not assure 
efficient investment 
 Security of supply issues are 
partly considered 
 Rules on cross-border capacity 
allocation might be too strict for 
the national actors to develop 
international projects with long-
term returns 
 Rules on balancing, organised 
market platform or establishing 
entry-exit system might be too 
restrictive for local hydrogen 
clusters developing separately from 
transit routes 

PW4: Transit-
focused H2 
grid 

and will take into account 
remaining CH4 consumers 
 EU-level guidelines on 
reallocation of revenues across 
sectors and tariffication rules 
ensure fair prices for CH4 and H2 
users 
 Rules on balancing, organised 
market platform or establishing 
entry-exit system might be too 
restrictive for local hydrogen 
clusters 

 EU level scenarios and network 
planning will enable development 
of transit pipelines and will take 
into account security of supply 
considerations 
 EU-level TSO would be in good 
position to develop costly transit 
projects due to its size 

139 

 
 
 
Roadmap for implementing the regulatory framework options 

To avoid unnecessary regulatory costs where the hydrogen sector is not fully developed yet, and to 
enable sufficient regulatory flexibility, some elements of the proposed regulatory frameworks can 
be implemented at a later time, when the market reaches sufficient maturity.  

As already elaborated in the section on transitory measures, this would mean that some of the 
regulatory elements would be defined only in general terms in the adopted legislation, but 
elaborated further with the help of Hydrogen Target Model. At a later stage, more detailed rules 
would be formalised with help of Commission implementing regulations or a similar legal 
instrument. Additionally, some of the exemptions designed to reduce the regulatory burden on 
developing isolated markets should be phased out with time in order not to incentivise the 
fragmentation of the networks. An appropriate moment to phase out these MSs derogations could 
be 2030, in line with the goals of the Hydrogen Strategy (with the possibility for extension 
depending on the actual development of the hydrogen sector). Similarly, exemptions or waivers for 
private network operators should be phased by a certain date. The timing of this phase-out is less 
clear, but it could be dependent on the duration of existing long-term hydrogen purchase 
agreements. 

No immediate action 

No immediate action would be taken in the short term up to 2025. However, if the hydrogen sector 
actually develops enough to play a relevant role in the overall EU energy sector, there will be an 
increasing need to address at least the interactions between hydrogen and other regulated energy 
sector activities. An evaluation of the market conditions and the need for a regulatory framework 
proposal might be needed in the medium-term up to 2030.  

Light EU regulation 

The main logic behind this option is to set the basic regulation that reduce the risks of 
discriminatory access to hydrogen networks and of distortion of the internal energy market, but 
otherwise sector regulation is left to Member States. For this reason, the basic rules on e.g. 
unbundling or TPA should be defined in the short term. For a similar reason to the “No immediate 
action” option, an assessment of the market conditions should be carried out e.g. around 2030 to 
evaluate if a further revision of EU regulatory framework is necessary. 

Full EU regulation 

Although the main regulatory elements should be defined in EU law as soon as possible to provide 
the regulatory certainty facilitating the necessary investments in the hydrogen sector, the entry 
into force of some elements could be delayed. Furthermore, some elements can be defined in more 
detail through the network codes and guidelines. The final vision for the hydrogen market should 
be nonetheless defined in the Hydrogen Target Model (HTM). The HTM will help frontrunner MSs to 
align their regulation with the expected future EU framework, reducing ex-post regulatory costs. In 
an iterative process, the HTM should be periodically reviewed (setting the adoption of a first HTM in 
2025 with an update every five years would be in line with the Hydrogen Strategy milestones). 

The main elements applicable immediately should concern unbundling and the role of gas network 
operators, setting regulated network TPA rules and an entry-exit based system together with rules 
for grid balancing. The process of creation of the hydrogen ENTSO should also start right away, to 
finalise a first hydrogen TYNDP by 2025. Based on the gained experience, common cross-sectoral 
scenarios for network planning could be developed in the 2025-2030 period. 

Since it is expected that the hydrogen markets will initially develop in smaller clusters which will be 
interconnected only gradually, the rules setting up a framework for EU-wide internal market for 
hydrogen do not have to be introduced in the short term. However, the rules for cross-border 
capacity allocation should be defined by 2030, when more substantial interconnection can be 
expected for the MSs following more ambitious pathways (and also to adhere to the Hydrogen 
Strategy). Further harmonisation of market rules and regulation of organised markets will be 
necessary by 2030 or only in the long term, when the cross-border trade will reach a more 
significant volume. 

Full+ EU regulation 

The implementation timeline of Full+ EU regulation option is in many cases similar to Full EU 
option. The major challenge for this option is however setting up the EU hydrogen TSO.  

 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

On the one hand, it would be beneficial to postpone the creation of such entity to a later phase 
(towards 2030), in order to give the sector enough time to adjust to this model and to leave 
enough time to clarify the future role of the EU H2 TSO. However, one of the key competencies of 
an EU-level TSO would be determinative network planning, leading the planning of the European 
backbone infrastructure. Postponing (EU-level) network planning process would significantly reduce 
the potential benefits and probably also delay the necessary investment. 

For this reason, the EU TSO should be set up from the start and assume its role in network 
planning. Due to the expected duration of the legislative process, a first EU-level hydrogen network 
development plan would anyway be published only around 2025. At a later stage (by 2030 or later, 
depending on the actual development of  the networks) the EU TSO would work on establishing 
implicit market coupling and establishing an EU-level balancing platform. 

Table 5-8 Roadmap for implementation of the regulatory framework options 

Pathway 

No immediate 
EU action 

Light EU 
regulation 

Full EU regulation 

Full+ EU regulation 

 Defining the role 
of gas TSOs, 
horizontal 
unbundling 
 Defining possible 
exemptions for 
private hydrogen 
networks  
 Defining the TPA 
regime possibilities 
for networks and 
large-scale storage 

  Evaluation of 
existing market 
conditions and 
potential proposal 
for revision of 
regulation 
 End of 
derogations to 
isolated markets 
 End of 
exemptions for 
private hydrogen 
networks 

 Setting up the 
Hydrogen Target Model 
 Defining the role of 
gas TSOs, horizontal 
unbundling 
 Setting up ENTSO-H2, 
TYNP for hydrogen 
 Defining the rules for 
re-allocation of non-
remunerated system 
benefits between sectors  
 Setting up entry-exit 
system, rules for 
balancing, cross-border 
capacity allocation 

 Defining common 
cross-carrier scenarios 
with hydrogen 
 Cross-border CACM 
rules 
 End of derogations to 
isolated markets 
 End of exemptions for 
private hydrogen 
networks 

 Setting up the 
Hydrogen Target Model 
 Defining the role of 
gas TSOs, horizontal 
unbundling 
 Setting up EU H2 TSO, 
TYNP for hydrogen 
 Defining the rules for 
re-allocation of non-
remunerated system 
benefits between  
sectors  
 Setting up entry-exit 
system, rules for 
balancing, cross-border 
capacity allocation 

 Harmonised intra-
market area market 
principles  
 Harmonised cross-
market rules 
 Cross-border CACM 
rules 
 End of derogations to 
isolated markets 
 End of exemptions for 
private hydrogen 
networks 

 Harmonised cross-
border market rules, 
mutual recognition of 
licenses, market area 
managers 

 Setting up spot market 
coupling and market 
area managers 
 Setting up balancing 
market coupling 

Short-term 
(to 2025)  

 No action 

 Evaluation of 
market 
conditions and 
potential 
proposal for 
regulation of 
hydrogen 
networks and 
markets 

Medium-term 
(to 2030)  

Long-term 
(after 2030)  

Design variants on the horizontal unbundling option for gas network operators 

In Table 5-2 and Table 5-3, two variants regarding the horizontal unbundling of hydrogen network 
operators are presented: 

 

In the Full+ EU regulatory framework, legal & functional unbundling could be employed as 
a variant to the main option of accounts unbundling; 

  An opposite variant is that any EU regulatory framework option (Light/Full/Full+) does not 
impose unbundling requirements between the regulatory asset bases for hydrogen and 
methane gases. 

As the impacts of legal & functional or no unbundling requirements are similar in all regulatory 
framework options, their impact compared to the default option of ‘accounts unbundling’ according 
to the relevant criteria is presented in the following table. 

141 

 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Table 5-9 Assessment of variants on the horizontal unbundling option for gas network 
operators 

Legal+functional 

No EU unbundling requirement 

Economic impacts 

-  Could reduce economies of scope, 

increasing total fixed costs. 

-  May lead to cross-subsidisation 

between hydrogen and methane 
network users. 

-  Revenue regulation and tariff 

structures may not account for 
differences in economic and technical 
characteristics. 

Effectiveness 

- No change compared to accounts 
unbundling 

-  Facilitates repurposing of methane 

networks by combined gas operators. 

Efficiency 

-  Increases administrative costs due to 

required transfer of repurposed 
methane assets. Undue re-evaluation 
of the residual regulated value of 
refurbished assets can be avoided by 
specific provisions in EU (or national) 
legislation. 

-  Increases oversight costs and 

transparency of network operator 
costs. 

-  Reduces administrative costs for 
repurposing methane networks. 
-  Increases regulatory costs due to 

need for closer oversight by 
regulators and competition 
authorities to avoid discriminatory 
practices and abuse of natural 
monopoly by network operators. 

Coherence 

-  Not coherent with unbundling 

-  Not coherent with unbundling 

requirements for electricity and 
methane network operators. 

requirements for electricity and 
methane network operators. 

Affected parties 

-  Increases total fixed costs of 

combined gas network operators. 

-  Further impacts pre-existing 

operators if they are not exempted 
from unbundling requirement by 
NRA, in Full+ EU option. 

-  Could negatively affect hydrogen or 
methane network users in case of 
cross-subsidisation. 

142 

 
 
 
 
 
 
 
  
 
 
 
Sector integration – Regulatory framework for hydrogen 

6  KEY FINDINGS AND RECOMMENDATIONS 

Prototype pathways for hydrogen gas infrastructure 

In view of the development of four generic or prototype pathways for the deployment of renewable 
and/or low-carbon hydrogen in the EU energy system, the most relevant hydrogen related plans 
and strategies published by European countries or industries have first been identified and 
analysed. On the basis of this analysis, it was found that both the Member State specific 
frameworks as well as strategic goals of relevant actors in industry and politics are multi-facetted. 
Analysis of potential factors having an impact on the emergence of a dedicated hydrogen 
infrastructure across Europe covering the full value chain of gas provision, infrastructure and end-
use, made clear that the potential development paths will be quite different across EU Member 
States, depending on their ambitions and their potential for renewable energy, their existing 
methane gas infrastructure, and the specific characteristics of their energy system and end-uses.  

The four generic pathways suggested therefore comprise (in parenthesis: starting from): 

  Pathway 1. Full hydrogen grid integration 

(Large RES potential, well-established gas grid) 

  Pathway 2: Hydrogen grid upscaling 

(Large RES potential, modestly-established gas grid) 

  Pathway 3: Hydrogen grid downsizing 

(Small RES potential, modestly-established gas grid) 

  Pathway 4: Transit-focused hydrogen grid 

(Small RES potential, modestly-established gas grid) 

The exercise to identify and analyse potential generic development pathways clearly results in the 
learning that an EU-wide harmonised regulatory approach would enable EU Member States to 
benefit from higher techno-economic benefits (economies of scale) and infrastructural synergies 
(cross-border hydrogen exchange) and hence from improved efficiencies and significant cost 
reductions, compared to a scenario with uncoordinated and hence possibly diverging national 
regulatory approaches.  

Non-exhaustive arguments for an EU hydrogen regulatory framework are: 

  Hydrogen production base: Member States with significant renewable electricity 

generation potential could aim to substitute their natural gas use by renewable electricity-
based hydrogen and even become net exporters, and consequently have an interest in 
repurposing their methane networks which would otherwise be decommissioned. This 
could help to efficiently facilitate the upscaling of hydrogen as an energy carrier in Member 
States with hydrogen-intensive energy strategies, which would in turn contribute to fulfil 
some of EC’s most important energy and climate policy goals (climate change mitigation, 
reducing energy import dependency and improve energy efficiency). 

  Hydrogen quality definition: An EU-wide hydrogen quality harmonisation may facilitate 
the development of hydrogen end-use equipment and appliances at larger production 
scales as well as foster the integration of the EU hydrogen market, helping to align 
national hydrogen pathways. 

  Hydrogen-blending level: Shared learning as well as an exchange on and testing of 

concepts will foster a rapid EU-wide implementation of blending hydrogen into the natural 
gas grid, which is an adequate option to facilitate the deployment of hydrogen. Several EU 
Member States are already taking initiatives to this end. As far as observed, all concerned 
grid operators have indicated their willingness for cooperation and EU-wide harmonisation. 
  Conversion of existing methane networks to hydrogen or new-build: Early analysis 
has shown that the conversion of existing methane infrastructure to hydrogen operation is 
significantly cheaper than new-build hydrogen pipelines. Common material standards and 
operating routines will support conversion activities across the EU. If deemed necessary, 
this will also help to develop well-defined interfaces to import renewable or low-carbon 
hydrogen through pipelines from outside of Europe. 

  Today’s hydrogen gas pipeline business: An early European regulatory framework 

could consider the long-term supply contracts and network assets of existing private 
hydrogen operators and, at the same time, build on the existing infrastructure to develop 
the wider energy system use of hydrogen in a stepwise manner. 

Pipelines as a natural monopoly? 

Chapter 2 analyses whether and to what extent dedicated hydrogen networks give rise to a natural 
monopoly justifying regulatory intervention. Although the hydrogen market development is in very 
early stages, there are strong indications that hydrogen transmission and distribution networks 
may constitute a natural monopoly in mature hydrogen markets, where hydrogen becomes or is 
close to becoming a traded commodity. This would coincide with phase 2 (2025-2030), and more 

143 

 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

broadly phase 3 (2030 towards 2050) defined in the European Commission’s Hydrogen Strategy. 
Also, in emerging markets, there is a relevant probability of natural monopolies to occur due to the 
sub-additive investment cost curves of pipelines, and the fact that repurposing methane pipelines 
to hydrogen will be less expensive than new-build and will hence provide a competitive advantage 
to the concerned owners/operators.  

The views of stakeholders diverge on the exact circumstances and the adequate timing for 
regulatory intervention with some stakeholders supporting rather early regulatory intervention, 
while others prefer late actions. A view voiced rather widely is to apply market tests, and to 
actively develop regulatory approaches step by step. Starting early with thorough tests and 
validations accompanied by scientific evaluation support is a robust no-regret approach before 
implementing any regulation.  

Regulatory elements for dedicated hydrogen networks and markets 

Chapters 3 and 4 develop a number of options for the different network regulation and market 
design elements shown in the figure below. The options developed for each regulatory element are 
either based on the EU natural gas regulatory framework or are developed as a ‘greenfield’ 
approach. While an analysis per regulatory element facilitates the development of the options, any 
EU regulatory framework for hydrogen must be developed and assessed holistically, given the 
interdependencies between the different regulatory elements. This global analysis is extensively 
presented in chapter 5 of this study. 

Network access

k
r
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t
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N

n Unbundling
o
i
t
a
u
g
e
r

l

Network planning

Revenue regulation

Network charging

t
e
k
r
a
M

n Trade platforms & exchanges
g
i
s
e
d

Hydrogen balancing

Definition of market product types

Access to large-scale storage

Licensing for suppliers and traders 

Capacity allocation and congestion 
management

Distribution networks

Development and assessment of EU hydrogen regulatory framework options 

Hydrogen is poised to play an important role in the EU energy transition, as indicated by the EU 
Hydrogen Strategy, the impact assessment for the 2030 Climate Target Plan, and the Long-term 
Strategy. 

To facilitate the large-scale development of the hydrogen sector according to the pathways 
identified in chapter 1, adequate policies will be necessary to enable the deployment of hydrogen 
production, trade, supply, transmission/distribution, storage, as well as of end-use equipment and 
appliances at the pace required for the energy transition. Given the current absence of economic 
regulation of the hydrogen sector at the EU and Member State level, this study contributes to 
determining the appropriate level of EU regulation to facilitate the optimal development of 
hydrogen infrastructure and markets. 

The analysis of chapter 2 indicates that several factors may justify some level of hydrogen sector 
regulation, including the sub-additive investment costs of hydrogen network assets leading to the 
need to ensure non-discriminatory third party access to networks (and to large-scale storage), the 
societal benefits of integrated network planning, and the potential cost savings resulting from 
repurposing methane infrastructure to hydrogen compared to new-build. 

Both regulated and market actors of the EU energy sector highlighted the need for regulatory 
certainty at both the EU and national levels. EU regulatory action for hydrogen can be based on 
article 194 of the Treaty on the Functioning of the EU (TFEU), which is also the basis for the EU 
regulatory framework for electricity and natural gas. 

By providing a level playing field for all market participants and technologies across the EU, 
adequate EU action can provide regulatory certainty, promote integrated network planning and 
operation of the energy system, facilitate the integration of the future hydrogen market, and 
minimise the risks of distortion to the overall EU internal energy market. EU action should employ 
the best practices and lessons learned from the experience in the natural gas and electricity 
sectors, and also leverage existing EU-level organisations and institutions where appropriate. 

144 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

The design of a new EU regulatory framework for hydrogen needs to be robust (i.e. perform 
adequately in any foreseeable transition pathway) and properly take into account the high 
uncertainty level at this stage, the overall incipient stage of development of hydrogen 
infrastructure and markets, and the different development speeds across end-use sectors and 
Member States. Moreover, any hydrogen regulation should be aligned with other developments in 
energy regulation, particularly regarding the promotion of electricity and gas systems integration, 
the use of incentive-based network regulation, and the simultaneous provision of regulatory 
stability and flexibility. 

The EU regulatory framework for natural gas has been introduced when the EU gas sector had 
already developed for several decades, which constrained regulatory options. The future hydrogen 
sector regulation is comparatively less constrained and must take a number of specific points into 
account. Repurposing methane infrastructure to hydrogen will facilitate the development of large 
segments of the future hydrogen networks, which will in particular support hydrogen-intensive 
scenarios. Hence, there is a significant potential role for methane network operators, but also for 
existing private hydrogen operators given their relevant assets and expertise. Moreover, trading 
hydrogen via organised market platforms and exchanges for methane gases can accelerate the 
development of a well-functioning, liquid hydrogen market. Finally, existing long-term supply 
contracts and network assets of private hydrogen network operators should properly be considered 
when implementing a regulatory framework.  

The EU regulatory framework options assessed in this study and summarised in the table below 
range from a de minimis intervention to avoid distortions of the internal energy market (the ‘EU 
light’ option), to a regulatory framework similar to that for natural gas (the ‘Full EU’ option), and 
finally an ambitious regulatory framework further advancing the integration of the internal energy 
market (the ‘Full+ EU’ option). Competition for-the-market (i.e. tendering hydrogen network 
concessions) could be used to introduce a competitive element and complement the regulation of 
hydrogen networks.  

There is still strong uncertainty regarding the energy transition pathways, but given the ambitious 
EU climate and energy targets, competition and energy sector-specific regulation at EU level should 
accommodate pathways where renewable and low-carbon hydrogen play an increasing role, while 
also respecting the right of Member States to pursue other decarbonisation pathways. 

The Full/Full+ EU options provide, from the start, an adequate regulatory framework for the timely 
development of an internal hydrogen market, supported by dedicated infrastructure accessible to 
all network users and coordinated with the electricity, methane, and heat sectors. These options 
also provide sufficient flexibility through transitional rules and a Hydrogen Target Model for the 
development of local hydrogen clusters or valleys and allow Member States to develop economies 
of scale and of scope with the methane sector, while also ensuring a level-playing field and 
respecting existing long-term hydrogen supply contracts and network assets. By being compatible 
with the long-term policy targets and providing flexibility to Member States, they minimise the ex-
post regulatory costs and provide regulatory certainty. 

By fostering integrated network planning and market coupling especially, the Full+ EU regulation 
would provide an improved level playing field for hydrogen market participants across Europe. 
However, harnessing the full benefits of the option implies addressing existing differences in the 
regulatory provisions and structure of the electricity and methane sectors. 

Chapter 5 provides a detailed assessment of the options, including the robustness to the pathways 
and a roadmap for implementation. Whichever regulatory approach is ultimately opted for, a 
number of key principles should be respected to enable the hydrogen sector to efficiently 
contribute to reaching the major EU and national energy and climate objectives: 

  Non-discriminatory third-party access to hydrogen networks (and large-scale storage) 
should be guaranteed for all market operators, with only limited and duly justified 
exemptions; 

  Network planning should be integrated across market areas, energy carriers, and network 
levels, with strong EU and national regulatory oversight and public consultation. It should 
also be aligned to policy objectives. The risk for stranded assets should be minimised, not 
only when considering conversion of existing methane infrastructure to hydrogen, but also 
when considering new investment in fossil gas or fossil-based hydrogen infrastructure. 
Given the EU decarbonisation targets and the pathways uncertainty, it is necessary to 
carefully assess the needs for fossil gas-based infrastructure and to apply adequate 
sustainability requirements to new energy infrastructure investments; 

  Member States should be allowed to realise efficiency gains and economies of scope 
through combined natural gas and hydrogen network operators. But this should not 
compromise transparency and cost-reflectiveness of grid tariffs; 

145 

 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

 

The regulatory framework should provide flexibility through transitional measures such as 
exemption procedures to isolated hydrogen clusters. A Hydrogen Target Model could be 
defined in order to guide Member States in developing regulation which is aligned with the 
EU framework and does not hamper the later interconnection of their hydrogen system. 

146 

 
 
 
 
ANNEX A DETAILED ASSESSMENT OF REGULATORY FRAMEWORK OPTIONS 

Economic 
impacts 

No immediate EU action (BAU) 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

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2

 System cost savings of PW1/PW2 
(related to economies of scale, sector 
coupling and hydrogen market 
integration) difficult to achieve without 
any EU regulatory framework. Hydrogen 
development restricted to certain MSs / 
slowed due to increased reliance on MSs 
for regulatory certainty, lack of EU 
measures for cross-border interconnection 
and hydrogen market integration.  

 Cost savings resulting from sub-
additivity might not be fully realised / 
occur later, as planning will be 
predominantly national and cross-border 
hydrogen network interconnection is 
hence expected to be very limited. 

 Limited cross-border market integration 
leads to less efficient use of hydrogen 
system and renewable energy resources. 

 Cost savings resulting from systems 
integration potentially not fully realised 
as there is no EU obligation for 
integrated planning. However, savings 
may be achieved at national level for 
(frontrunner) MSs with combined gas 
network operators. 

 Cost savings resulting from sub-
additivity might not be fully realised / 
occur later, as EU hydrogen network 
development is expected to be mainly 
national, without strong interconnection. 

 Limited cross-border market 
integration leads to less efficient use of 
hydrogen system and renewable energy 
resources. 

 Cost savings resulting from systems 
integration realised to a large extent 
(but less than in the Full+ option), 
thanks to EU-wide planning coordination 
with other carriers, coherent regulated 
approach to energy infrastructures. 

 Cost savings realised on national 
level, resulting from common planning 
scenarios and CBA methodology but in 
the absence of integrated energy 
systems modelling investments might 
not be realised in the most efficient way 
possible. 

 Harmonised market rules enable 
better competition in markets. 
Common network scenarios and CBA 
methodology indicate the future 
demand for energy carriers and 
flexibility, guiding investment in 
flexibility resources and renewables. 

 Cost savings resulting from systems 
integration realised to a large extent 
thanks to integrated planning, coherent 
regulated approach to energy 
infrastructures. 

 Cost savings related to infrastructure 
investment realised to a large extent, as 
EU hydrogen network develops 
according to policy objectives and with 
integrated EU-wide planning. 

 Efficient use of hydrogen system and 
renewable energy resources, and 
decreased risks for distortion of the 
internal energy market thanks to 
integrated EU-wide planning, market 
integration (including coupling of 
wholesale and balancing markets) and 
establishment of organised trading 
platforms with appropriate market 
products. 

 SoS guaranteed for existing networks 
with long-term contracts. For other 
actors, the potential lack of organised 
trading platforms to hedge their short and 
long term risks, and the lack of 
negotiated and/or regulated TPA to 
network (and storage) infrastructure 
might lead to low security of hydrogen 
supply at affordable prices. 

 As TPA is not imposed by EU law, 
converted methane infrastructure could, 
in the absence of adequate national law, 
become 'closed' hydrogen pipelines, 
potentially excluding new network users 
and reducing security of hydrogen supply. 

 SoS guaranteed for existing networks 
with long-term contracts. For other 
actors, the potential lack of organised 
trading platforms to hedge their short 
and long term risks, and the lack of 
negotiated and/or regulated TPA to 
network (and storage) infrastructure 
might lead to low security of hydrogen 
supply at affordable prices. 

 As rTPA is not imposed by EU Law, 
converted methane infrastructure under 
rTPA could, in the absence of adequate 
national law, become hydrogen 
pipelines under nTPA, potentially 
excluding new network users and 
reducing security of hydrogen supply. 

 Market integration, liquidity measures 
and networks rTPA increases H2 SoS, 
including to small network users, by 
reducing dependence on single or 
limited number of supply sources. 

 rTPA for hydrogen networks assures 
non-discriminatory access for all 
network users. 

 Market integration, liquidity measures, 
integrated EU-wide planning and 
networks rTPA increases H2 SoS, 
including to small network users, by 
reducing dependence on single or 
limited number of supply sources. 

 rTPA for hydrogen networks assures 
non-discriminatory access for all 
network users. 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Economic 
impacts 

No immediate EU action (BAU) 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

 Does not ensure that network tariffs are 
cost-reflective and non-discriminatory, 
and set with transparent and objective 
criteria. Inefficient investments may 
increase tariff levels. 

 Without EU wide harmonised network 
revenue regulation and tariff structure 
principles, national approaches regarding 
connection cost allocation or 
volume/capacity tariff components might 
unduly burden certain network users, 
such as first movers or users with a low 
network utilisation. 

 Lack of EU-wide horizontal unbundling 
requirements for new hydrogen / 
combined gas network operators may in 
some MSs lead to cross-subsidisation 
between hydrogen and methane network 
users.  

 Does not ensure that network tariffs 
are cost-reflective and non-
discriminatory, and set with transparent 
and objective criteria. 

 Without EU wide harmonised network 
revenue regulation and tariff structure 
principles, elements like connection cost 
allocation or inadequate 
volume/capacity tariff components 
might unduly burden certain network 
users, such as first movers or users with 
a low network utilisation. 

 Lack of integrated EU-wide planning 
processes can lead to inefficient 
investments and higher tariff levels. 

 Energy system cost savings lead to 
lower overall tariff levels to energy 
consumers. 

 Requirements ensure that network 
tariffs are cost-reflective and non-
discriminatory, and set with transparent 
and objective criteria. 

 Harmonised revenue regulation and 
tariff structure principles addressing 
elements such as connection cost 
allocation increase tariff cost-reflectivity 
and decrease cross-border distortions. 

 Energy system cost savings lead to 
lower overall tariff levels to energy 
consumers. 

 Requirements ensure that network 
tariffs are cost-reflective and non-
discriminatory, and set with transparent 
and objective criteria 

 Wholesale and balancing markets 
coupling eliminate effects of tariff 
pancaking and foster cross-border 
trade, with inter-TSO compensation 
allocating costs first to areas and 
subsequently to network users in each 
area. 

 Harmonised revenue regulation and 
tariff structure principles addressing 
elements such as connection cost 
allocation increase tariff cost-reflectivity 
and decrease cross-border distortions 

 Some network users might be forced to 
convert equipment and appliances for 
hydrogen, but the lack of harmonised 
rules for markets' integration and XB 
trade negatively affects competitiveness 
of hydrogen supply. 

 Some network users might be forced 
to convert equipment and appliances for 
hydrogen, but the lack of harmonised 
rules for markets' integration and XB 
trade negatively affects competitiveness 
of hydrogen supply. 

 The potentially slower uptake of 
hydrogen markets enables more time for 
converting/replacing equipment and 
appliances, but might be outweighed by 
lack of economies of scale and EU-wide 
standardisation, and lower competition in 
hydrogen supply.  

 The potentially slower uptake of 
hydrogen markets enables more time 
for converting/replacing equipment and 
appliances, but might be outweighed by 
lack of economies of scale and EU-wide 
standardisation, and lower competition 
in hydrogen supply. 

 Some end-users might be enforced to 
convert equipment / appliances. 
Coordination of hydrogen networks roll-
out with policy objectives should allow 
for staged conversion of equipment and 
appliances with assistance from the 
regulated network operators. 

 Some network users might be 
enforced to convert equipment / 
appliances. Coordination of hydrogen 
networks roll-out with policy objectives 
should allow for staged conversion of 
equipment and appliances with 
assistance from the regulated network 
operators. 

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148 

 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Technical 
impacts 

No immediate EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

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 Lack of EU harmonised gas quality 
standards and interoperability 
network code at EU level may hamper 
interconnection of hydrogen networks 
and the conversion of end-user 
equipment/appliances. 

 Lack of EU harmonised gas quality 
standards and interoperability network 
code at EU level may hamper 
interconnection of hydrogen networks 
and the conversion of end-user 
equipment/appliances. 

 Gas quality standards and 
interoperability network code enable 
interconnection of hydrogen 
networks and the conversion of end-
user equipment/appliances. 
Common scenarios indicate where 
future interactions with electricity 
and methane systems will be 
needed. However, this is arguably 
already done by common electricity 
& methane scenarios which indicate 
the potential future infrastructure 
bottlenecks. 

 Gas quality standards and 
interoperability network code (out of 
scope of this assessment) enable 
interconnection of hydrogen networks 
and the conversion of end-user 
equipment/appliances. 
Common scenarios and modelling 
provide clear signals on capacity and 
bottlenecks of electricity, methane and 
hydrogen systems. 

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 May limit the efficient use of 
renewable energy sources for 
electricity and supply of flexibility to 
the energy system, due to the lack of 
requirements on integrated EU-wide 
planning (both cross-border and 
cross-energy carriers), slower 
establishment of organised trading 
platforms with appropriate market 
products, and low level of internal 
hydrogen market integration. 

 May limit the efficient use of 
renewable energy sources for 
electricity and supply of flexibility to 
the energy system, due to the lack of 
requirements on integrated EU-wide 
planning (both cross-border and cross-
energy carriers) and slower 
establishment of organised trading 
platforms with appropriate market 
products. 

  Efficient use of hydrogen system 
and renewable energy resources 
(though lower than in Full+), and 
decreased risks for distortion of the 
internal energy market due to 
coordinated EU-wide planning, 
market integration and 
establishment of organised trading 
platforms with appropriate market 
products. 

  Efficient use of hydrogen system and 
renewable energy resources, and 
decreased risks for distortion of the 
internal energy market due to 
integrated EU-wide planning, market 
integration (including coupling of 
wholesale and balancing markets) and 
establishment of organised trading 
platforms with appropriate market 
products. 

7. Allows repurposing of methane infrastructure when efficient: See 17. 

149 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Effectivenes
s 

No immediate EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

* A full assessment of the suitability of regulatory options to accommodate national pathways is presented in the Table 5-7. 

 Regulatory flexibility to MSs early on. 
Frontrunners MSs (PW1) can adopt early 
regulatory framework, laggards (PW4) 
can delay / not implement sector-specific 
regulation. 

 Integrated hydrogen market by 2030 
of Hydrogen Strategy / PW1 MSs 
unlikely, given missing measures, and 
risk perception due to lack of regulatory 
certainty. Significant entry barriers for 
new (smaller) market participants due to 
potential absence of TPA requirements, 
non-transparent price formation. 

 Lack of integrated planning may lead to 
inefficient decommissioning of methane 
infrastructure in PW3. 

 Long-term supply/transport contracts 
may assure demand for (some) 
hydrogen networks. But does not 
guarantee investments are aligned to 
national and EU energy plans, due to 
lack of EU regulation on integrated 
planning. 

 Limited EU regulation gives 
regulatory flexibility to MSs early on. 
Frontrunners MSs (PW1) can adopt 
early regulation complementing the EU 
framework, laggards (PW4) can delay / 
not implement sector-specific 
regulation 

 Integrated H2 market by 2030 of 
Hydrogen Strategy / for PW1 MSs 
unlikely given missing measures, and 
risk perception due to potential 
necessity to update the framework 
later on to match EU policy objectives 
in hydrogen-intensive pathways 
(PW1/PW2). 

 Lack of integrated planning may lead 
to inefficient decommissioning of 
methane infrastructure in PW3. 

 National flexibility to choose for nTPA 
may facilitate long-term hydrogen 
purchase and transport contracts, thus 
enabling development of transit 
pipelines in PW 4. 

 Unbundling, TPA rules and measures 
for market integration provide 
regulatory certainty for hydrogen-
intensive pathways (PW1 / PW2 / 
Hydrogen Strategy), facilitating 
investments in the long-term. 

 Cooperative EU-wide planning 
facilitates efficient decommissioning of 
methane infrastructure in PW3. 

 Exemption procedures for certain 
networks and staged applicability of 
cross-border-related rules provides 
flexibility for initial roll-out in PW1/PW2 

 rTPA and CACM rules offer better 
investment certainty for transit 
countries (PW4), but measures are 
needed to facilitate long-term 
hydrogen purchase / transport capacity 
contracts, otherwise can have negative 
impact on investments. 

 Increased market liquidity and rTPA 
may increase market size, potentially 
lowering H2 prices and facilitating 
pathways.  

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 Absence of an EU-wide framework for 
integrated network planning and 
differences in TPA requirements may 
lead to a suboptimal outcome, as 
voluntary cooperation of Member States 
may be less efficient. 

 Absence of an EU-wide framework for 
integrated network planning and 
differences in TPA requirements may 
lead to a suboptimal outcome, as 
voluntary cooperation of Member 
States may be less efficient. 

 Higher risk perception by investors due 
to lack of certainty regarding national 

 Higher risk perception by investors 
due to lack of certainty regarding 

 Establishes hydrogen networks as a 
regulated activity, defines EU-wide 
planning process for developing 
networks and repurposing methane 
networks. 

150 

 Integrated EU-wide planning, 
unbundling, TPA rules and measures 
for market integration (including 
market coupling) provide regulatory 
certainty for hydrogen-intensive 
pathways (PW1 / PW2 / Hydrogen 
Strategy), facilitating investments in 
the long-term. 

 Integrated planning facilitates 
efficient decommissioning of methane 
infrastructure in PW3. 

 Integrated planning provides 
additional investment certainty for 
transit pipelines construction (PW4). 

 Exemption procedures for certain 
new networks and staged applicability 
of cross-border-related rules provides 
flexibility for initial roll-out in PW1/PW2 

 rTPA and CACM rules offer better 
investment certainty for transit 
countries (PW4), but measures needed 
to facilitate long-term hydrogen 
purchase / transport capacity 
contracts, can otherwise have negative 
impact on investments 

 Increased market liquidity and rTPA 
may increase market size, potentially 
lowering H2 prices and facilitating 
pathways. 

 Establishes hydrogen networks as a 
regulated activity, defines EU-wide 
planning process for developing 
networks and repurposing methane 
networks. 

 Establishment of wholesale and 
balancing markets coupling, cross-
border CACM and organised exchanges 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Effectivenes
s 

No immediate EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

regulatory framework and differences in 
strong hydrogen growth pathways (PW1) 
result in higher investment costs and 
potentially under-development of the 
hydrogen backbone. 

national regulatory framework and 
differences in strong hydrogen growth 
pathways (PW1) result in higher 
investment costs and potentially 
under-development of the hydrogen 
backbone. 

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 Allows MSs to tailor framework for 
early hydrogen applications in industry 
and transport. Access of 
producers/suppliers to smaller transport 
users (especially FCEV refuelling 
stations) will depend on national 
regulation. 

 MSs could allow vertically integrated 
hydrogen producers to supply directly 
industrial users and hydrogen refuelling 
stations without the need for exemption 
procedures. 

 Private H2 networks can stay under 
current regulatory framework. 

 Allows MSs to tailor framework for 
early hydrogen applications in industry 
and transport, while TPA requirements 
can facilitate access to smaller 
transport users. 

 MSs could allow vertically integrated 
hydrogen producers to supply directly 
industrial users and hydrogen 
refuelling stations without the need for 
exemption procedures. 

 Private hydrogen networks can stay 
under current regulatory framework. 

  Lack of common EU-wide planning 
models risks sub-optimal planning 
from systems integration perspective. 

accelerates the development of well-
functioning liquid markets and 
facilitates cross-border investments. 

 Establishment of harmonised market 
rules, cross-border CACM and 
organised exchanges accelerates the 
development of well-functioning liquid 
markets and facilitates cross-border 
investments. 

 Unbundling, rTPA should facilitate 
cross-border network development, 
access to smaller transport users. New 
large and small hydrogen consumers 
would have to rely especially on 
regulated network operators. 

 Unbundling, rTPA should facilitate 
cross-border network development, 
access to smaller transport users. New 
large and small hydrogen consumers 
would have to rely especially on 
regulated network operators. 

 Private hydrogen networks can stay 
under current regulatory framework if 
exempted by NRA, suitable for long-
term hydrogen supply contracts. 

 Private hydrogen networks can stay 
under current regulatory framework if 
exempted by NRA, suitable for long-
term hydrogen supply contracts. 

151 

 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Effectivenes
s 

No immediate EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

 Lack of EU provisions may delay 
investments until MS define adequate 
regulatory framework, including 
particular incentives for development of 
storage. 

 Allows different national regulatory 
framework (e.g. ownership of storage 
facilities), depending on national 
specificities, including market situation 
and technical potential. 

 Risk of non-harmonised approaches 
between MS, possibly leading to less 
efficient use of the capacities, and also 
uneven possibilities of market 
participants across MSs to access storage 
services. 

 Potential distortions between rTPA and 
nTPA storage assets, and abuse of 
market power by large-scale storage 
under an nTPA regime or in the absence 
of TPA requirements. 

 Sets a basic rTPA/nTPA framework 
for large-scale storage, although it 
does not offers particular incentives for 
development of storage. 

 Sets a basic rTPA/nTPA framework 
for large-scale storage, although it 
does not offers particular incentives for 
development of storage. 

 Allows differentiation depending on 
market situation and technical 
potential. 

 Allows differentiation depending on 
market situation and technical 
potential. 

 Risk of non-harmonised approaches 
between MS and of non-coordinated 
use of underground storage capacities. 

 Risk of non-harmonised approaches 
between MS and of non-coordinated 
use of underground storage capacities. 

 Potential distortions between rTPA 
and nTPA storage assets, and abuse of 
market power by large-scale storage 
under an nTPA regime. 

 Potential distortions between rTPA 
and nTPA storage assets, and abuse of 
market power by large-scale storage 
under an nTPA regime. 

 rTPA for large-scale storage 
guarantees non-discriminatory access 
to large-scale storage, important 
especially if there is a limited number 
of suitable sites. 

 Reduces competition distortion 
between large-scale storages. 

 Operators of methane storage under 
a nTPA regime may be interested or 
not to repurpose facilities with a rTPA 
regime, depending on hydrogen and 
methane market conditions for 
storage. 

 rTPA regime can lower cost of capital 
for repurposing methane storage sites. 

 Allows MSs to tailor framework for 
early hydrogen clusters, but access of 
smaller transport network users will 
depend on national regulation. 

 Sufficient regulatory space for 
development of isolated local hydrogen 
clusters is provided, due to limited / no 
rules on unbundling, network planning, 
and wholesale and balancing markets. 

 Requirement for rTPA facilitates 
development of clusters serving not 
only industry and transport but also 
small-scale hydrogen producers and 
consumers. 

 Requirement for rTPA facilitates 
development of clusters serving not 
only industry and transport but also 
small-scale hydrogen producers and 
consumers. 

 Exemption procedures for certain 
new networks and staged applicability 
of cross-border-related rules provides 
flexibility for hydrogen clusters as well 
as long-term visibility on HTM. 

 Exemption procedures for certain 
new networks and staged applicability 
of cross-border-related rules provides 
flexibility for hydrogen clusters as well 
as long-term visibility on HTM. 

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152 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Efficiency 

No immediate EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

 Lack of integrated planning and 
measures such as harmonised market 
rules and products, CACM and network 
charging may lead to barriers to 
market entry and integration. 

 Does not preclude development of 
national markets, and voluntary 
harmonisation and market integration 
is still possible. Liquid hubs for 
hydrogen likely to remain restricted to 
a few regions/countries and with 
limited coupling of markets. 

  The lack of harmonised market rules 
can lead to opaque price formation / 
barriers to foreign participants. 
Information asymmetry can lead to 
competitive advantages against market 
participants on methane and electricity 
markets. 

 Significant entry barriers for new 
(smaller) market participants due to 
potential lack of TPA or hydrogen 
sector planning requirements, non-
transparent price formation, unless 
national regulatory framework 
addresses these aspects. 

 New network operators may be 
disadvantaged vis-a-vis incumbent 
methane network operators as 
planning is a function of the latter 

 Lack of integrated planning and 
measures such as harmonised market 
rules and products may lead to barriers 
to market entry and integration. 

 Does not preclude development of 
national markets, and voluntary 
harmonisation and market integration 
is still possible. But liquid hubs for 
hydrogen may develop only in a few 
regions/countries and with limited 
coupling of markets. 

 The lack of harmonised market rules 
can lead to opaque price formation in 
the hydrogen market / barriers to 
foreign participants. Information 
asymmetry can lead to competitive 
advantages against market players on 
the natural gas and electricity markets. 

 Significant entry barriers for new 
(smaller) market participants due to 
potential absence of rTPA or hydrogen 
sector planning requirements, non-
transparent price formation unless 
national regulatory framework 
addresses these aspects. 

 New network operators may be 
disadvantaged vis-a-vis incumbent 
methane network operators as 
planning is a function of the latter. 

 Competition regulation could address 
eventual market power abuses, but at 
significant delay and with burden of 
proof to regulators. 

 Competition regulation could address 
eventual market power abuses, but at 
significant delay and with burden of 
proof to regulators. 

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153 

 Provides non-discriminatory access 
to all hydrogen network users. 
Measures for market integration, 
coordinated EU-wide planning aligned 
to policy objectives and fostering 
cross-border infrastructure, and non-
discriminatory access for users support 
the development of hydrogen 
infrastructure and markets in MSs and 
regions with hydrogen-intensive 
pathways. 

  Due to lack of market coupling, 
more significant price differentials 
might occur initially. 

  Harmonised market rules reduce the 
information disparity between actors.  

 Competition regulation can still be 
applied to complement and reinforce 
sector-specific regulation. 

 Provides non-discriminatory access 
to all hydrogen network users. 
Measures for market integration 
(including market coupling), 
integrated EU-wide planning aligned 
to policy objectives and fostering 
cross-border infrastructure, and non-
discriminatory access for users 
support the development of hydrogen 
infrastructure and markets in MSs 
and regions with hydrogen-intensive 
pathways. 

  Competition regulation can still be 
applied to complement and reinforce 
sector-specific regulation. 

 Increasingly integrated EU 
hydrogen markets with separate 
prices for hydrogen and methane 
gases allows hydrogen to be 
employed where most valued. 

 Harmonised market rules reduce 
the information disparity between 
actors. 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Efficiency 

No immediate EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

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 Regulatory costs depend on national 
legislation (no EU legislation which 
needs to be implemented/ 
transposed). 

 Uncertainty about potential future 
regulation of the sector can lead to 
posterior regulatory costs after 2030 
(also to harmonise national 
frameworks). 

 Low initial cost for MSs with limited 
interest in hydrogen, but when an EU-
wide market will develop, these MSs 
may need to develop adequate 
national regulation and/or adapt their 
initial regulation to properly address 
cross-border issues (and then incur ex-
post regulatory costs). 

 Low regulatory costs for 
transposing/implementing EU 
legislation. Further design of regulatory 
frameworks on national level leads to 
additional regulatory costs. If liquid 
European market for hydrogen is to 
materialise as envisaged in hydrogen 
strategy, additional rules will have to 
be developed, leading to further 
regulatory costs. 

 Low initial cost for MSs with low 
interest in hydrogen but as EU-wide 
market develops under PW1 these MSs 
may also need to develop regulation. 

 Limited integrated planning due to 
lack of EU-level processes and 
harmonised requirements for MS. 
Cross-sectoral planning can take place 
on national level or voluntarily in 
certain regions, but this is more 
efficiently done on a wider scale given 
electricity and methane sectors are 
already highly integrated. 

 Limited integrated planning due to 
lack of EU-level processes and 
harmonised requirements for MS. 
Cross-sectoral planning can take place 
on national level or voluntarily in 
certain regions, but this is more 
efficiently done on a wider scale given 
electricity and methane sectors are 
already highly integrated. 

 There is no required assessment on 
costs and benefits of using private 
infrastructure to integrate regulated 
hydrogen networks. 

 There is no required assessment on 
costs and benefits of using private 
infrastructure to integrate regulated 
hydrogen networks. 

154 

 Additional costs for planning, setting-
up and operating the ENTSO-H2 and 
platforms for balancing, CACM. 

 Regulatory authorities have more 
tasks, requiring resources. 

 Stricter oversight might pose 
disproportionately higher burden on 
smaller market participants. 

 Low initial cost for MSs without 
interest if EU provisions with a cross-
border impact are waivered until their 
hydrogen systems are interconnected. 

 Network planning process requires 
additional costs that will be transferred 
to network users, but can be 
counterbalanced by the systemic 
benefits. 

 Harmonising market rules/licenses 
might be a potentially unnecessary 
burden for markets/clusters that are 
not interconnected (this could be 
covered by derogations or other 
transitional measures). 

 Clear definition of competitive and 
regulated activities, Hydrogen Target 
Model and harmonisation of 
regulatory elements minimises ex-
post regulatory costs. 

 Additional costs for planning, 
setting up the EU H2 TSO, wholesale 
and balancing market coupling, 
CACM platforms. 

 Regulatory authorities have more 
tasks, requiring resources. 

  

 Stricter oversight might pose 
disproportionately higher burden on 
smaller market participants. 

 Low initial cost for MSs without 
interest if EU provisions with a cross-
border impact are waivered until 
their hydrogen systems are 
interconnected. 

 Efficient EU-wide planning of cross-
border network. 
Possible interactions between energy 
systems not explored to a full extent. 

  Integrated EU-wide planning takes 
place with EU H2 TSO and 
harmonised requirements for MS 
planning are in place. 

 Planning process assesses benefits of 
integrating private networks in 
hydrogen system 

 Planning process assesses benefits 
of integrating private networks in 
hydrogen system 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Efficiency 

No immediate EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

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 Pre-existing infrastructure operators 
can maintain business model. 

 Possible exemption procedures allow 
pre-existing infrastructure operators to 
maintain business model, if authorised. 

 Possible exemption procedures allow 
pre-existing infrastructure operators to 
maintain business model, if authorised. 

 Possible exemption procedures 
allow pre-existing infrastructure 
operators to maintain business 
model, if authorised. 

 Inefficient repurposing from EU 
perspective likely, as decision may not 
optimise the planning from a 
multinational and multi-vector 
perspective. Regulatory regimes for 
methane and hydrogen may differ, 
complicating the repurposing. 

 Long-term supply/transport contracts 
under nTPA or from vertically 
integrated undertakings may assure 
sufficient interest exists in transport 
capacity for the entire lifetime of 
(some) hydrogen infrastructure assets. 
However, it does not guarantee 
investments are aligned to national 
and EU energy plans, due to lack of EU 
regulation on integrated planning and 
oversight. 

 Potentially leads to inefficient 
repurposing from EU perspective, as 
the decision on infrastructure 
repurposing depends on national 
regulation only and there are no EU 
requirements for integrated or 
coordinated planning. 

 Long-term contracts under nTPA may 
assure sufficient interest exists in 
transport capacity. However, it does 
not guarantee investments are aligned 
to national and EU energy plans. 

 Possibility for re-allocation of non-
internalised system benefits might 
enable to hedge some of the risks 
related to early hydrogen network 
development and decommissioning/ 
repurposing of methane networks. 

 Efficient repurposing from EU 
perspective, given coordinated but not 
fully integrated planning aligned with 
policy objectives, oversight by policy 
makers and regulators, possibility of 
combined network operators, and 
accounts unbundling of methane and 
hydrogen network operators. 

 Alternatives to network expansion 
may be overlooked if not assessed in 
the coordinated planning.  

 Possibility for re-allocation of non-
internalised system benefits might 
enable to hedge some of the risks 
related to early stage of hydrogen 
network development and 
decommissioning/ repurposing of 
methane networks. 

 Efficient repurposing from EU 
perspective, given integrated 
planning aligned with policy 
objectives, oversight by policy 
makers and regulators, possibility of 
combined network operators and 
accounts unbundling of methane and 
hydrogen network operators. 

 Possibility for re-allocation of non-
internalised system benefits might 
enable to hedge some of the risks 
related to early stage of hydrogen 
network development and 
decommissioning/ repurposing of 
methane networks. 

155 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Efficiency 

No immediate EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

 Can lead to innovative network 
regulation or business models. 
However, in the short-term, offering 
clarity and certainty regarding network 
capacity availability and access rules is 
more likely to kick-start innovation in 
H2 production and end-use. 

 Can lead to innovative regulation or 
business models. However, in the 
short-term, investment certainty is 
more likely to kick-start the hydrogen 
sector than innovative market 
products. 

 Incentives to employ innovative 
solutions for hydrogen infrastructure 
and for planning process to consider 
alternatives to network expansion 
depend on national regulation. 

 Incentives to employ innovative 
solutions for hydrogen infrastructure 
and for planning process to consider 
alternatives to network expansion 
depend on national regulation. 

 Market operators may set up 
organised market platforms and 
exchanges, developing innovative 
market products. 

 Market operators may set up 
organised market platforms and 
exchanges, developing innovative 
market products. 

 Market participants may develop 
hydrogen networks without need for 
authorisation/exemption from NRAs if 
hydrogen networks operation is 
deemed a competitive activity by MSs. 
However, investments are likely 
delayed until MSs define this. 

 NRAs may exempt hydrogen 
networks from unbundling, regulated 
TPA and tariffs, incentivising innovative 
business models. Non-regulated 
network operators may face increased 
capital cost due to higher risks. 

 Less room for innovative regulation 
or business models, but Member 
States are still free to provide 
incentives for innovation to regulated 
network operators. 

 Entry/exit system is more flexible, 
enabling shorter-term trading 
(especially for smaller market 
participants) and exploring possibilities 
in interactions with other energy 
markets. 

 Harmonising market rules/licenses 
might be a potentially unnecessary 
burden for markets/clusters that are 
not interconnected (this could be 
covered by derogations for non-
interconnected systems or other 
transitional measures). 

 Less room for innovative regulation 
or business models, but Member 
States are still free to provide 
incentives for innovation to regulated 
network operators. 

 Market area managers and 
harmonised markets rules limit the 
space for products innovation. 
Regulatory sandboxes and the 
network code development and 
amendment process can potentially 
provide room for innovation in 
market design. 

 Entry/exit system is more flexible, 
enabling shorter-term trading 
(especially for smaller market 
participants) and exploring 
possibilities in interactions with other 
energy markets. 

 NRAs may exempt hydrogen 
networks from unbundling, regulated 
TPA and tariffs, incentivising 
innovative business models. Non-
regulated network operators may 
face increased capital cost. 

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156 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Coherence 

No immediate EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

 Not coherent with EU regulatory 
framework for electricity and 
methane. 

 Lack of harmonised hydrogen 
market rules and alignment with 
other energy sectors regulation can 
lead to competition distortion and to 
inefficient arbitrage between energy 
markets (i.e. not allowing to 
optimally exploit price differentials 
for the different energy vectors in 
the respective markets). 

 Lack of network tariffs regulation 
in some MSs could lead non-
regulated hydrogen system 
operators cross-subsidising against 
specific price-insensitive users such 
as households, distorting 
competition in end-uses where 
hydrogen is substitute to electricity 
or natural gas. Combined gas 
operators could cross-subsidise fixed 
costs between regulated and non-
regulated network users. 

 Coherent definition of network 
transport as a regulated activity. 

 Lack of harmonised hydrogen 
market rules and alignment with 
other energy sectors regulation can 
lead to uneven competition and 
inefficient arbitrage between market 
participants in different MSs or 
energy sectors. 

 May incentivise market operators 
active in electricity and methane 
markets to offload balancing 
responsibility to hydrogen TSO. 

 Lack of network tariffs regulation 
in some MSs could lead non-
regulated hydrogen system 
operators cross-subsidising against 
specific price-insensitive users such 
as households. 

 This regulatory package can be 
considered as coherent with TEN-E 
regulation in its current form, as the 
common understanding is that it 
does not cover hydrogen (unless 
blended).  

 This regulatory package can be 
considered as coherent with TEN-E 
regulation in its current form, as the 
common understanding is that it 
does not cover hydrogen (unless 
blended).  

 Would be incompatible with TEN-E 
regulation should it be amended to 
cover hydrogen as well. 

 Would be incompatible with TEN-E 
regulation should it be amended to 
cover hydrogen as well. 

 Coherent definition of network 
transport as a regulated activity, 
requirement of TPA, balancing 
market, use of an entry-exit system. 

 H2 ENTSO would have coherent 
structure and tasks to electricity and 
methane counterparts. 

 Due to lack of market coupling, 
significant price differentials on 
national hydrogen markets might 
initially occur. This can also lead to 
uneven competition and inefficient 
arbitrage between market 
participants in different MSs or 
energy sectors. 

 Coherent definition of network 
transport as a regulated activity, 
requirement of TPA, balancing 
market, use of an entry-exit system 

 Market coupling coherent with 
electricity regulatory framework 
approach, not with methane. 
Market area manager coherent with 
approach for methane. 

 Harmonised hydrogen market 
rules and mutual recognition of 
licenses not coherent with (current) 
methane regulatory framework. 

 EU H2 TSO has no correspondent 
organisation for methane or 
electricity. 

 Coherent approach to multiple 
regulatory elements reduces 
potential for distortions in the 
internal energy market. 

 EU-wide network planning process 
aligned with current TEN-E 
regulation, it would be possible to 
incorporate hydrogen networks in 
the PCI process if the TEN-E 
regulation would be amended to 
include hydrogen. 

 EU-wide network planning process 
aligned with current TEN-E 
regulation, it would be possible to 
incorporate hydrogen networks in 
the PCI process if the TEN-E 
regulation would be amended to 
include hydrogen. 

19. With electricity, 
methane (and heat) 
sectors regulatory 
framework 

20. With TEN-E 

21. With EEAG 

 Coherent as hydrogen 
infrastructure would not need to be 
included in definition of energy 
infrastructure. 

22. With Hydrogen Strategy: See 8. 

 Requires EEAG adaptation to 
include hydrogen infrastructure. 

 Requires EEAG adaptation to 
include hydrogen infrastructure. 

 Requires EEAG adaptation to 
include hydrogen infrastructure. 

157 

 
 
 
Sector integration – Regulatory framework for hydrogen 

Coherence 

No immediate EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

23. Internal 
coherence 

 Coherent as there are no EU-level 
provisions for all regulatory 
elements 

 Coherent as it contains only 
provisions on unbundling (accounts), 
TPA and role of private network 
operators exist at EU level. Defines 
the minimum requirements for 
ensuring non-discriminatory access 
while MSs are free to regulate (or 
not) other aspects. 

 Coherent as provisions at EU level 
for all regulatory elements 
guarantee non-discriminatory 
access, foster market integration 
and minimise distortions of the 
internal energy market. 
Nonetheless, national authorities 
and network operators retain 
significant room for further defining 
the regulatory framework and 
developing the hydrogen system. 

 Coherent as regulatory elements 
(especially on network regulation) 
are further defined at EU level 
(compared to  ‘Full EU’, with 
integrated planning, market coupling 
(spot and balancing) and CACM. 

158 

 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Proportionality & 
subsidiarity 

No immediate EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

24. Regulation at 
EU level is 
justified to: 
· Contribute to 
proper 
functioning of 
energy markets 
· Ensure SoS  
· Promote energy 
efficiency 
· Promote 
interconnection 
of energy 
networks 

 Not applicable 

 EU regulation justified to provide 
minimum requirements on the 
regulation of hydrogen 
infrastructures and markets to 
ensure non-discriminatory third-
party access, with MSs being allowed 
to determine hydrogen network 
investment and operation are 
competitive activities only based on 
a market test assessing the potential 
for distortions of the internal energy 
market. 

 EU regulation justified to provide 
minimum requirements on the 
regulation of hydrogen infrastructures 
and markets to ensure non-
discriminatory third-party access, 
promote interconnection of hydrogen 
networks under the expectation of 
strong development in certain MSs and 
contribute to a well-functional internal 
hydrogen market without undue 
distortions to the internal electricity and 
methane markets. 

 The shift of decision-making powers to 
EU level is justified as it concerns areas 
with cross-border impacts (e.g. network 
planning, harmonised market rules). 

 Package proportional due to waivers 
and exemption procedures allowing MSs 
to not adopt cross-border regulatory 
elements until their hydrogen systems 
are interconnected, with minimum 
requirements to avoid distortions to the 
internal electricity and methane 
markets. 

 EU regulation justified to provide 
minimum requirements on the regulation of 
hydrogen infrastructures and markets to 
ensure non-discriminatory third-party 
access, promote interconnection of 
hydrogen networks under the expectation 
of strong development in certain MSs and 
contribute to a well-functional internal 
hydrogen market without undue distortions 
to the internal electricity and methane 
markets. 

 Package proportional due to waivers and 
exemption procedures allowing MSs to not 
adopt cross-border regulatory elements 
until their hydrogen systems are 
interconnected, with minimum 
requirements to avoid distortions to the 
internal electricity and methane markets. 
Setting up an EU H2 TSO seems a priori 
proportional given the importance and 
economic benefits of integrated planning 
and of cross-border systems and markets 
coupling. Based on lessons learned from the 
(lengthy and complex) integration process 
of the electricity and methane markets and 
networks, this regulatory package might be 
adequate to efficiently reach the objective 
of a pan-European interconnected hydrogen 
backbone and an integrated and liquid 
market.  

25. MS maintain 
right to 
determine own 
energy supply 
mix 

 No restrictions on 
hydrogen/methane usage or 
production pathways are imposed, 
the right of MSs is maintained. 

 No restrictions on 
hydrogen/methane usage or 
production pathways are imposed, 
the right of MSs is maintained. 

 No restrictions on hydrogen/methane 
usage or production pathways are 
imposed, the right of MSs is maintained. 

 No restrictions on hydrogen/methane 
usage or production pathways are imposed, 
the right of MSs is maintained. 

159 

 
 
 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Affected 
parties 

26. Most 
affected 
parties 

No immediate EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

 In markets with fast-developing 
demand, the network growth might not be 
quick enough due to difficulties in 
planning, negotiating with new users and 
acquiring right of way. Also, if no 
regulation of third party access is assured, 
this might lead to discriminatory access. 

 Smaller scale market participants are not 
guaranteed the same level of market 
access even if hydrogen networks develop, 
if only negotiated TPA exists and there are 
no transparent price signals from 
organised markets. 

 Methane network operators may develop 
hydrogen networks if NRAs provide 
adequate regulation; repurposing methane 
infrastructure could be easier (less 
administrative constraints) but efficiency 
might be lower due to lack of integrated 
planning. 

 New network operators may be 
disadvantaged vis-a-vis incumbent 
methane network operators due to higher 
costs of new hydrogen infrastructure (in 
comparison to repurposing). 

 Pre-existing infrastructure operators can 
maintain business model. 

 More suitable if it is expected that 
mainly the actors that have access to 
information / scale (e.g. large industrial 
consumers; networks operators, large-
scale producers) will be the main actors in 
hydrogen sector. 

 Smaller scale market participants are not 
guaranteed the same level of market 
access, if only negotiated TPA exists and 
there are no transparent price signals from 
organised markets. 

 Methane network operators may develop 
hydrogen networks, but repurposing of 
methane infrastructure more difficult due 
to lack of integrated planning. 

 New network operators may be 
disadvantaged vis-a-vis incumbent 
methane network operators as planning is 
a function of the latter. 

 Exemptions assure pre-existing 
infrastructure operators can maintain 
business model. 

 Provides non-discriminatory access to all 
hydrogen network users. 

  
Balancing responsibility with market 
participants requires additional costs that 
can be disproportionately higher on 
smaller market players, but transitional 
measures can address this. 

 Infrastructure operators/owners have 
less risky business due to regulated 
revenues, but face more administrative 
burdens & need technical expertise for 
systemic network planning. 

 Increased oversight and other tasks for 
policy-makers, NRAs and ACER. 

 Provides non-discriminatory 
access to all hydrogen network 
users. 
Balancing responsibility with market 
participants requires additional costs 
that can be disproportionately 
higher on smaller market players, 
but transitional measures can 
address this. 

 Methane network operators may 
develop hydrogen networks, with 
efficient repurposing of methane 
infrastructure facilitated through 
integrated planning. 

 Existing private hydrogen network 
operators will need to comply with 
unbundling, regulated TPA and other 
provisions or be granted an 
exemption by NRAs. 

 Increased oversight and other 
tasks for policy-makers, NRAs and 
ACER. 

160 

 
 
 
 
 
Sector integration – Regulatory framework for hydrogen 

Transitional 
measures 

No immediate 
EU action 

Light EU regulation 

Full EU regulation 

Full+ EU regulation 

27. Ability to ensure 
flexibility to 
network/market 
development 
according to 
pathways and 
national differences 

 Not applicable 

 Member States may be derogated from 
unbundling and cross-border requirements 
following regulatory requirements until 
their hydrogen systems become 
interconnected.  

 Member States may be derogated from 
the following regulatory requirements until 
their hydrogen systems become 
interconnected: unbundling, network 
tariffication, planning, CACM, storage TPA 
requirements 

 Member States may be derogated from 
the following regulatory requirements until 
their hydrogen systems become 
interconnected: unbundling, network 
tariffication, planning, CACM, storage TPA 
requirements 

 Sets an indicative Hydrogen Target 
Model, promote voluntary regional 
harmonisation and define a deadline (e.g. 
2030) for an impact assessment for 
revision of the EU hydrogen regulatory 
framework. 

 Sets a Hydrogen Target Model and legal 
framework to enable the gradual 
development and implementation of 
necessary network codes and guidelines, 
on initiative of ACER or the Commission, 
for the following regulatory requirements: 
harmonised tariff principles, market 
coupling, CACM, balancing, harmonised 
market rules 

 Sets a Hydrogen Target Model and legal 
framework to enable the gradual 
development and implementation of 
necessary network codes and guidelines, 
on initiative of ACER or the Commission, 
for the following regulatory requirements: 
harmonised tariff principles, market 
coupling, CACM, balancing, harmonised 
market rules 

 For interconnected systems272, clearly 
define requirements for waivers and 
exemption procedures of hydrogen 
network operators, covering pre-existing 
operators, direct lines and closed 
distribution systems. 

 For interconnected systems, clearly 
define requirements for waivers and 
exemption procedures of hydrogen 
network operators, covering pre-existing 
operators, direct lines and closed 
distribution systems. 

 For interconnected systems, clearly 
define requirements for waivers and 
exemption procedures of hydrogen 
network operators, covering pre-existing 
operators, direct lines and closed 
distribution systems. 

 Sets clear exemption procedures to new 
and pre-existing hydrogen network 
operators. 

 Sets clear exemption procedures to new 
and pre-existing hydrogen network 
operators. 

 Sets clear exemption procedures to new 
and pre-existing hydrogen network 
operators. 

 Include guidelines on tests for further 
regulatory intervention, to increase 
investment certainty. 

 Develop EU network planning CBA 
methodologies, scenarios and models 
gradually, through each plan. 

 Develop EU network planning CBA 
methodologies, scenarios and models 
gradually, through each plan 

272 These requirements could be defined at national level for isolated clusters that are not interconnected. For interconnected systems, harmonised rules would be required to avoid 
market and competition distortions.  

161 

 
 
 
 
                                                
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2020 

Directorate-General for Energy  
Internal Energy Market 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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