Measuring the contribution of gas infrastructure projects to sustainability as defined in the TEN-E regulation : final report.
Date: 2020-10-21
Institutions: Directorate-General for Energy
Subjects: cost-benefit analysis, economic consequence, economic indicator, electrical energy, energy grid, energy market, environmental impact, environmental indicator, gas, greenhouse gas, reduction of gas emissions, regulation (EU), report, supply and demand, sustainable development, trans-European network

Measuring the contribution of 
gas infrastructure projects to 
sustainability as defined in the 
TEN-E Regulation 

Final Report 

June 2020 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2020 

Directorate-General for Energy  
Internal Energy Market 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Authors: 
Luc van Nuffel (Trinomics) 
João Gorenstein Dedecca (Trinomics) 
Ondřej Černý (Trinomics) 
Christopher Andrey (Artelys) 
Maxime Chammas (Artelys) 
Amaury Salauze (Artelys) 

EUROPEAN COMMISSION 

Directorate-General for Energy 
Directorate B — Internal Energy Market 
Unit B1 — Networks & Regional Initiatives 

Contact:  Chryssa Argyriou 

E-mail:  chrysoula.argyriou@ec.europa.eu 

European Commission 
B-1049 Brussels 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Measuring the contribution of 
gas infrastructure projects to 
sustainability as defined in 
the TEN-E Regulation 

2020 

Directorate-General for Energy 
Internal Energy Market 

 
 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EUROPEAN COMMISSION 

Europe Direct is a service to help you find answers  
to your questions about the European Union. 

Freephone number (*): 

00 800 6 7 8 9 10 11 

(*) 

The information given is free, as are most calls (though some operators, phone 

boxes or hotels may charge you). 

LEGAL NOTICE 

This document has been prepared for the European Commission however, it reflects the views only of the 
authors, and the Commission cannot be held responsible for any use which may be made of the information 
contained therein. 

More information on the European Union is available on the Internet (http://www.europa.eu ). 

Luxembourg: Publications Office of the European Union, 2020 

ISBN 978-92-76-23298-8 
doi: 10.2833/395467 

© European Union, 2020 
Reproduction is authorised provided the source is acknowledged. 

2020 

Directorate-General for Energy  
Internal Energy Market 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

TABLE OF CONTENTS 

EXECUTIVE SUMMARY .................................................................................................... 7 

THE ENTSOG CBA 2.0 SUSTAINABILITY INDICATOR ................................................... 1 

1.1.  Sustainability in the current TEN-E Regulation (EC) 347/2013 ............................ 1 
1.2.  Overview of 2nd ENTSOG Cost-Benefit Analysis ................................................ 2 
1.3.  Sustainability in ENTSOG’s Cost-Benefit Analysis 2.0 ......................................... 3 
1.4.  Evaluation  of  the  current  sustainability  approach  used  by  ENTSOG  for  TYNDP 

projects ....................................................................................................... 7 

  DEVELOPMENT AND TESTING OF A NEW SUSTAINABILITY INDICATOR ......................... 9 

2.1.  Development of a sustainability indicator ......................................................... 9 
2.2.  Dealing with methane emissions ................................................................... 15 
2.1.  Non-GHG emissions (PM, SOx, NOx) .............................................................. 17 

INDICATOR DESCRIPTION AND IMPLEMENTATION ................................................... 20 

3.1.  Description of the indicator implementation ................................................... 20 

  GAS-RELATED 

INFRASTRUCTURE 

PROJECTS  AND 

THEIR  SUSTAINABILITY 

CHARACTERISTICS .............................................................................................. 26 

4.1.  Gas-related infrastructure projects ................................................................ 26 
4.2.  Overall sustainability characteristics of the selected projects ............................ 30 

PCI  ELIGIBILITY  AND  TEN-E  SUSTAINABILITY  OF  GAS-RELATED  INFRASTRUCTURE 
PROJECTS ........................................................................................................... 54 

5.1.  PCI eligibility of gas-related infrastructure projects ......................................... 54 
5.2.  TEN-E sustainability of gas-related infrastructure projects ............................... 59 

ANNEX A - BREAKDOWN OF EMISSIONS FROM BIOGAS PRODUCTION STEPSERROR!  BOOKMARK 

NOT DEFINED. 

ANNEX B – DETAILED CALCULATION OF FOSSIL FUEL SUBSTITUTION EMISSION FACTORSERROR! 

BOOKMARK NOT DEFINED. 

 
 
 
 
 
 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

EXECUTIVE SUMMARY 

The main objective of this study is to define and test a comprehensive indicator for 
the  sustainability  impacts  of  gas  infrastructure  projects  considering  the  TEN-E 
Regulation  requirements  of  Art.  4.2  (b)  (iv)  and  Annex  IV.3  (chapters  1-3).  The 
proposed indicator improves the consideration of the projects’ sustainability impacts that 
feed  in  the  gas  PCI  selection  process.  The  proposed  indicator  addresses  some  of  the 
weaknesses  of  the  current  sustainability  indicator  as  defined  in  the  gas  cost-benefit 
analysis (CBA) methodology, such as possible misestimation/misallocation of sustainability 
impacts and increase the comparability of project-specific CBAs, and thus the ranking of 
PCIs  in  the  regional  groups.  The  proposed  indicator  can  be  implemented  without 
introducing  any  additional  complexity  in  ENTSOG’s  model.  Furthermore,  we  propose  a 
methodology to calculate sustainability benefits based on the use of an interlinked model 
that recognises the coupling of the gas and electricity systems. Such an indicator could be 
calculated using the METIS model. 

A  secondary  objective  is  to  analyse  the  (TEN-E)  sustainability  aspects  of  a  wide 
range of gas-related infrastructure projects, as well as their eligibility as a gas 
PCI (chapters 4-5). The scope of this analysis is broader than the sustainability indicator 
developed  in  the  first  part  of  the  study,  and  covers  more  types  of  projects  than  those 
considered  in  either  the  PCI  or  TYNDP  processes.  The  study  allows  to  identify  potential 
improvements  in  the  current  TEN-E  Regulation  and  the  gas  cost-benefit  analysis 
methodology. 

Overall structure of the study 

Chapters 1-3
Sustainability indicator

1 – The ENTSOG CBA 2.0 sustainability 
indicator
2 – Development and testing of a new 
sustainability indicator
3 – Indicator description and implementation 
plan

Chapters 4-5
Gas-related infrastructure projects

4 – Gas-related infrastructure projects and 
their sustainability characteristics
5 – PCI eligibility and TEN-E sustainability of 
gas-related infrastructure projects

A new gas sustainability indicator considering the TEN-E Regulation requirements 

The first step of the study has been to review the requirements from the TEN-E Regulation 
and  the  definition  of  the  sustainability  indicator  as  currently  defined  in  the  cost-benefit 
analysis methodology developed by ENTSOG (CBA 2.0). The current indicator defined in 
CBA 2.0 covers two sustainability aspects. The first part of the indicator is an evaluation of 
the CO2 emission savings enabled by the development of the project being assessed, the 
gas it brings in the downstream system allowing to reduce the consumption of other more 
CO2-intensive fuels in the area. The second part is a qualitative analysis of the measures 
the promoter has taken to mitigate the impact of the project on the environment. In this 
aspect, the current indicator does not cover other sustainability impacts, in particular the 
effect of the project on methane emissions, on non-GHG emissions and on the integration 
of intermittent renewable electricity generation or synthetic gas. The computation of the 
indicator  evaluating  CO2  savings  has  some  important  limitations,  some  of  which  being 
directly linked to the limitations of the gas system model currently being used by ENTSOG 
to assess infrastructure projects, in particular the fact that dynamic interlinkages with other 
vectors (including electricity) are not captured and that its temporal granularity is limited 
to two points a year (winter and summer). The main limitations identified are as follows:  

  The calculated CO2  emission savings are independent from the potential use of the 
assessed project (i.e. the value of the indicator only depends on the capacity of the 
project and not on its use rate). 

 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  The allocation of CO2 emission savings treats existing infrastructure and new projects 
in  the  same  way,  regardless  of  the  possibility  of  achieving  the  same  level  of  fuel 
switching without the assessed project.  

  The computation cannot capture the transit effects: e.g. a project built between area 
A and area B allowing a fuel switching from coal to gas in area C will not be attributed 
any CO2 emission savings. 

  The reduced representation of the dynamics of the gas system (two representative 
days) does not allow to precisely capture the operational management of gas storage 
assets. Therefore, the evaluation of their sustainability impacts lacks robustness.  

In order to address these issues, an updated indicator is proposed in this study. Beyond 
small  refinements  related  to  the  computation  of  the  CO2  emission  savings  due  to  fuel 
switches, the main change with respect to the current indicator is the allocation key (which 
encodes  how  CO2  savings  are  allocated  to  projects).  The  allocation  key  of  the  updated 
indicator is based on flows instead of capacities, ensuring that projects which are not used 
in  simulations  are  not  allocated  CO2  emission  savings.  Furthermore,  the  report 
recommends, for computing this updated indicator, to use simulations prioritising existing 
infrastructure  over  projects  in  the  operation  of  the  gas  network.  The  latter  point  would 
ensure that projects that grant access to cheaper gas but do not decrease the use of more 
CO2-emitting  fuels  (coal,  oil)  are  not  allocated  CO2  emission  savings  for  decreasing  gas 
flows  in  neighbour  infrastructure.  This updated  indicator  could  be  used  with  the current 
modelling framework available to ENTSOG and thus be used by ENTSOG to compute the 
sustainability indicator of projects in upcoming TYNDP cycles. Similar methodologies have 
been proposed to assess the effect of fuel switches on non-GHG gases emissions and on 
methane  emissions,  linked  to  the  increased  use  and  leakages  of  methane  in  the 
downstream  network.  Insights  on  the  quantification  of  RES  gases  and  RES  electricity 
integrated in the network are also provided. The proposed indicator allows to reduce the 
weaknesses  of  the  current  indicator,  and  to  better  cover  the  sustainability  aspects 
mentioned in the TEN-E Regulation.  

However, some of the limitations of the current indicator remain despite the recommended 
updates.  In  particular  transits  between  countries  are  not  well  captured,  the  benefits  of 
storages  cannot  be  assessed  accurately,  and  direct  interlinkages  between  gas  and 
electricity (i.e. gas-to-power, power-to-gas and hybrid consumption technologies) are not 
well accounted for. For that purpose, an indicator building on an interlinked gas, heat and 
electricity  model  is  proposed.  This  indicator  would  allow  for  a  better  computation  of 
sustainability indicators on all aspects (CO2, non GHG emissions, impact of RES integration 
and renewable gas integration).  

As  far  as  we  are  aware,  ENTSOG  is  not  currently  equipped  with  an  interlinked  model. 
Options where another entity could be tasked with evaluating the effect of projects on the 
system, for instance using METIS1, could therefore be explored. 

Finally,  the  question  of  the  compatibility  of  projects  towards  a  2050  net-zero  emission 
future  has  also  been  raised.  The  definition  of  these  indicators  (improved  indicator  and 
interlinked model indicator) could help assess the relevance of projects for reaching a net-
zero emission future but would require assessing projects at the 2050 horizon (which is 
not  foreseen  in  TYNDP  2020  as  far  as  we  are  aware).  Scenarios  reaching  the  European 
objectives,  such  as  the  Long-Term  Strategy  pathways  1.5TECH  or  1.5LIFE,  could  be 
considered to assess whether projects are future-proof.  

1 METIS is an interlinked model developed by Artelys on behalf of the European Commission. It has been used 
to inform policy making in various areas (e.g. proposals of the Clean Energy Package) and is available to the 
Joint Research Centre. For more information on METIS, we refer the reader to 
https://ec.europa.eu/energy/data-analysis/energy-modelling/metis_en 

 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Figure 1 Comparison between the different indicators 

Current 
Sustainability 
indicator 

Improved 
Sustainability 
indicator  

Interlinked model 
Sustainability 
indicator  

 

 
 
 
 

Simplicity to compute the indicator 

Possibility to attribute a negative CO2 impact 
to a project 

CO2 savings allocation prioritise existing 
infrastructure. 

CO2 savings are linked to expected flows in 
the project.  

Evaluation of the effect of projects on CO2 
based on a marginal approach (operation of 
the system with/without the project similarly 
to the CBA) 

Accuracy for the evaluation of CO2 savings 
of storages 

Cross sectoral assessment (incl. P2G) 

Trans-national assessment  

 
 
 
 

 
 
 

Gas-related infrastructure projects 

The sustainability characteristics of eight selected gas-related infrastructure project types 
analysed in chapter 4, are illustrated by their impact on greenhouse gas emissions (CO2, 
CH4  and  other  gases),  on  the  reduction  of  local  pollutant  emissions,  and  on  the 
development of renewable electricity, biomethane and hydrogen. The projects selected for 
detailed  analysis  are  related  to  hydrogen  (pure  or  admixed  in  natural  gas  networks), 
biomethane  or  methane  emission  reduction,  covering  the  gas  supply  chain  stages  of 
transport, distribution, storage and conversion. 

The  emission  reduction  impact  of  the  different  project  types  varies  significantly,  from 
potentially negative to neutral or strongly positive impacts. Quantitatively, the impact may 
vary from around under -200 to over 200 tCO2eq of avoided GHG emissions per TJ of fossil 
fuel substituted due to gas projects. However, the impacts of individual projects will vary 
according to not only aspects considered in this study, but also characteristics specific to 
each project and the energy system they are integrated in. 

Section 5.1 considers the PCI eligibility of the gas-related infrastructure projects according 
to the TEN-E criteria (general, Annex II and specific criteria). Of the eight project types 
analysed, half would not be eligible for PCI status, while specific projects in the other four 
types could potentially satisfy the eligibility criteria. 

As for the sustainability impacts that gas-related infrastructure can have, these are already 
considered in the TEN-E regulation at a high level. However, several options for potential 
improvements are identified in the study. They concern the eligibility criteria mentioned in 
the TEN-E regulation, the gas CBA methodology and the sustainability indicator to assess 
the positive and negative sustainability impacts of candidate PCI-projects: 

  Asses the sustainability characteristics of PCI candidates, preferably 
with an integrated electricity-gas model, in order to fully account for the 
benefits of projects to enable the integration of both renewable gas and 
electricity into the system as well as to consider the electricity-gas systems 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

interlinkages. This substantial change could be preceded by short-term 
improvements in the CBA methodology, including by implementing the 
improved sustainability indicator developed in chapter 2; 

  Consider implementing minimum sustainability criteria for gases in the 
calculation of the projects’ sustainability benefits, using RED II criteria, 
while  also  including  gases  with  comparable  carbon  footprints  to  renewable 
gases, such as low-carbon hydrogen; 

  Use eligibility and assessment criteria for PCIs to avoid a lock-in in 
unsustainable pathways, considering the carbon footprint of the various 
gases facilitated by gas-related infrastructure; 

  Consider  developing  an  integrated  hydrogen-electricity-gas  model  if 
and  when  the  scope  of  the  TEN-E  Regulation  is  expanded,  to  include 
hydrogen systems when these reach significant scale and interaction with other 
energy infrastructure. Meanwhile, hydrogen projects can be considered through 
scenarios,  with  verified  project-specific  data  and  at  the  interface  of  methane 
and of electricity systems. 

Finally,  it  is  important  to  recognize  the  importance  of  scenarios’  formulation  and  the 
subsequent choice of scenario(s) for performing the cost-benefit analysis on the resulting 
project assessment. In order to ensure the neutrality of scenarios, they should be aligned 
to general policy goals (such as the 2050 Long-Term Strategy), and reflect alternatives to 
infrastructure  investments,  such  as  energy  efficiency  measures,  in  line  with  the  Energy 
Efficiency First principle of the Energy Union. Furthermore, there should be strong oversight 
and  consultation  of  stakeholders  to  ensure  the  scenario  development  and  project 
assessment are transparent and scientific, and avoid the risk of lock-in in unsustainable 
pathways or stranded investments. 

 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  THE ENTSOG CBA 2.0 SUSTAINABILITY INDICATOR 

This  chapter  presents  a  description  of  the  current  approach  used  by  ENTSOG  and  gas 
project promoters to assess the sustainability impacts of gas infrastructure projects in the 
context of TYNDP 2018. We then proceed to describing our assessment of the strengths 
and weaknesses  of the  approach. The description and evaluation of ENTSOG’s approach 
are  based  on  publicly-available  documents  as  well  as  on  bilateral  contacts  between  the 
consultants  and  ENTSOG  staff  members.  The  key  ENTSOG  documents  that  have  been 
consulted to describe ENTSOG’s approach are:  

  ENTSOG  (2018),  2nd  ENTSOG  Methodology  for  Cost-Benefit  Analysis  of  Gas 

Infrastructure Projects 

  ENTSOG (2018), TYNDP 2018, Annex D – Methodology  

  ENTSOG (2018), TYNDP 2018, Project-Specific Cost-Benefit Analysis  

Several other documents have been consulted to assess the strengths and weaknesses of 
the sustainability indicators currently used by ENTSOG, for instance: 

  EC, Regulation (EU) No 347/2013 

  ACER, Opinion No 15/2017  

  ACER, Recommendation No 02/2019 

 

 

 

 

 

 Navigant  (2019),  Study  on  an  assessment  methodology  for  the  benefits  of 
electricity storage projects for the PCI process 

 Deloitte/FSR (2017), Study on recommendable updates and improvements of the 
ENTSOG methodology for cost-benefit analysis of gas infrastructures 

 ENTSO-E  (2018),  2nd  ENTSO-E  Guideline  For  Cost  Benefit  Analysis  of  Grid 
Development Projects 

 ENTSO-E (2019), Draft CBA 3.0 

 EIB (2018), Project Carbon Footprint Methodologies 

The following paragraphs present an overview of the 2nd ENTSOG methodology for cost-
benefit  analysis  (CBA),  with  a  focus  on  the  sustainability  indicators.  We  then  present  a 
detailed description of the way the sustainability indicators are calculated, the input data, 
and the role of stakeholders in supplying datasets and/or running calculations. Finally, the 
strengths and weaknesses of the current indicator are presented. 

1.1.  Sustainability in the current TEN-E Regulation (EC) 347/2013 

Article 4 “Criteria for projects of common interest” of the TEN-E Regulation states that gas 
projects  falling under  the energy  infrastructure  categories  (set  out  in  Annex  II.2), must 
contribute significantly to at least one of the following specific criteria:  

 

 

 

 

 Market integration, inter alia through lifting the isolation of at least one Member 
State and reducing energy infrastructure bottlenecks; interoperability and system 
flexibility;  

 Security of supply, inter alia through appropriate connections and diversification 
of supply sources, supplying counterparts and routes;  

 Competition,  inter  alia  through  diversification  of  supply  sources,  supplying 
counterparts and routes;  

 Sustainability,  inter  alia  through  reducing  emissions,  supporting  intermittent 
renewable generation and enhancing deployment of renewable gas.  

Annex IV “Rules and indicators concerning criteria for projects of common interest” to the 
TEN-E  Regulation  further  specifies  that  “sustainability  shall  be  measured  as  the 

1 

 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

contribution  of  a  project  to  reduce  emissions,  to  support  the  back-up  of  renewable 
electricity  generation  or  power-to-gas  and  biogas  transportation,  taking  into  account 
expected changes in climatic conditions” (Annex IV.3).  

In the TEN-E Regulation as it stands today, sustainability is only one of the four considered 
criteria,  meaning  that  PCI  projects  do  not  necessarily  have  to  meet  this  sustainability 
criterion, as the four mentioned criteria are not cumulative.  

1.2.  Overview of 2nd ENTSOG Cost-Benefit Analysis 

Chapter IV of Regulation (EC) 347/2013 provides the regulatory reference for the energy 
system wide cost-benefit analysis methodology. It defines the use of the CBA methodology 
for the development of the TYNDP, as input for the selection of Projects of Common Interest 
(PCIs),  as  basis  to  investment  request,  and  as  basis  to  allow  promoters  to  apply  for 
financial assistance. The latest CBA methodology developed by ENTSOG and approved by 
the  European  Commission  on  1  December  2018,  aims  at  delivering  a  comprehensive 
assessment bringing more clarity than its predecessor with a reduced number of indicators 
and an easier interpretation of the results. 

The methodology includes two steps: 

 

 

 The system assessment aims (among others) at providing an overall assessment 
of the European gas system under different infrastructure levels: a reference level 
(current + projects having reached the final investment decision), an advanced level 
(with advanced non-FID projects) and a PCI level (with non-FID projects having PCI 
label); 

 The project-specific assessment aims at providing an individual assessment of 
each  of  the  projects submitted to  ENTSOG during  the  TYNDP process  in  order  to 
evaluate the costs and benefits associated with the project. 

The  CBA  methodology  consists  in  an  analysis  of  the  contribution  of  the  project  to  four 
criteria:  market  integration,  security  of  supply,  competition  and  sustainability.  Several 
indicators of the CBA can qualify each of these four criteria. The latest CBA methodology 
developed by ENTSOG to assess specific projects (PS-CBA) and approved by the European 
Commission2 is structured as follows: 

2 https://www.entsog.eu/sites/default/files/2019-
03/1.%20ADAPTED_2nd%20CBA%20Methodology_Main%20document_EC%20APPROVED.pdf 

2 

 
 
                                                 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Figure 1-1 ENTSOG CBA - Structure of the PS cost-benefit analysis 

The different benefits are quantified via simulations of the operations of the European gas 
system,  based  on  a  bottom-up  representation  of  the  system:  the  gas  sources 
(production/imports/LNG), storage assets and interconnections are explicitly represented 
with a country-level spatial granularity. The operations of these assets are then simulated 
by enforcing a demand-supply equilibrium, in particular in periods of stress (cold winters, 
disruptions, etc.). The annual figures are obtained by simulating two days (one for winter, 
the other for summer, linked via a storage-related constraint).  

For most indicators, the projects are assessed by comparing two situations: one situation 
without the project and another one where the project is present. The contribution of the 
project  to  the  corresponding  criteria  is  then  calculated  as  the  difference  of  the  key 
indicators presented in the figure above between the two situations.  

However,  the  way  the  sustainability  indicators  are  calculated  is  not  based  on  such  an 
approach: these indicators are calculated by comparing two different time horizons. The 
details and motivation for choosing a different approach are presented in Section 1.3. 

1.3.  Sustainability in ENTSOG’s Cost-Benefit Analysis 2.0 

As described above, one of the four criteria defined in the TEN-E Regulation to assess gas 
projects  is  sustainability.  The  following  paragraphs  present  our  understanding  of  the 
methodology  developed  by  ENTSOG  to  capture  the  sustainability  impacts  of  a  gas 
infrastructure project.  

The current CBA methodology includes two indicators related to sustainability:  

 

 CO2 emission savings (quantitative indicator, monetized): The objective of 
the “CO2 savings” indicator is to quantify and monetize the impacts of the project 
on CO2 emissions. The rationale is that a given gas infrastructure project can enable 
gas to substitute more carbon-intensive fuels;  

3 

 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

 

 Environmental  impact  (qualitative  indicator,  with  associated  costs):  The 
objective of the “Environmental impact” indicator is to provide an appreciation of 
the mitigation measures put in place by project promoters in order to reduce the 
impact of the project on its surroundings.  

The 2nd CBA methodology also imposes that the calculation must be performed both in 
CO2 emissions (MtCO2) and in monetary value (in €) using two possible approaches for the 
monetization (CO2 market price or social cost of carbon).  

In the following section, we provide a description of the calculation of the “CO2 emission 
savings”  indicator, and  illustrate  this  method  with  a  virtual example  based  on  a project 
with impacts in 3 countries.  

As described in Annex D of ENTSOG TYNDP 2018, ENTSOG has left the final calculation of 
project-specific  CO2  savings  to  the  responsibility  of  promoters.  However,  in  order  to 
facilitate this calculation, ENTSOG provides a number of indicative figures to the promoters, 
which are based on an analysis of the evolution of gas use over the period covered by the 
TYNDP  scenarios.  In  practice,  ENTSOG  figures  are  used  unless  project  promoters  can 
propose alternative figures that are duly justified by them. 

The key steps of the ENTSOG methodology to assess the effect of infrastructure projects 
between  two  consecutive  years  of  the  modelled  scenarios  (e.g.  2020  to  2025,  2025  to 
2030) are the following:  

 

 Step 1: Assessment of evolution of the use of gas by sector during the period 

  Step 2: Computation of CO2 savings from fuel switching per sector 

  Step 3: Evaluation of CO2 savings in each country 

  Step 4: Allocation of CO2 savings to projects in the country  

We describe in the following sections the steps in more details. 

As far as the environmental impact indicator is concerned, the promoter has to provide a 
table with the impacts and an overview of the mitigation measures that will be undertaken 
to comply with the EU Environmental acquis. 

Methane  emissions  are  not  taken  into  account  in  the  current  ENTSOG  approach  (no 
methane emissions allocated to projects).  

According to ENTSOG, in TYNDP 2020, the total GHG non-CO2 emissions are considered 
in the scenarios by taking the average of 1.5LIFE and 1.5TECH scenarios of the European 
Commission’s Long-Term Strategy. However, these emissions are not allocated to projects 
during the project-specific cost-benefit analysis. 

1.3.1.  Step 1: Assessment of the evolution of the use of gas by sector over 

the period 

The first step of the computation consists in the identification of the sectoral evolution of 
gas use between two consecutive years in the modelling (e.g. 2025 and 2030). For this 
purpose, ENTSOG relies on the scenario assumptions by sector.  

For TYNDP 2018, since the scenarios did not cover the full energy system, the assumptions 
for the energy mix by sector partly rely on Eurostat 2016 datasets.  

4 

 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

In TYNDP 2020, the full energy mixes will be provided for two top-down scenarios (Global 
Ambition  and  Distributed  Energy).  For  the  remaining  bottom-up  scenario  (National 
Trends),  based  on  NECPs,  additional  assumptions  will  have  to  be  made  on  the  energy 
mixes.  

Required input: gas use in all sectors (electricity, heating, transport, industry), at country 
level, for the two considered years.  

Output example: In country A, the gas use will increase by 10 TWh in the heating sector 
and by 25 TWh in the industry sector. The gas use will decrease by 5 TWh in the electricity 
generation sector, and will remain constant in the transport sector between 2025 and 2030. 

1.3.2.  Step 2: Computation of CO2 emission savings from fuel switching per 

sector 

The  objective  of  this  step  is,  for  sectors  for  which  an  increase  in  gas  consumption  is 
expected (as assessed in step 1), to compute CO2 emission savings that are expected in 
the concerned sectors by fuel switching.  

For  that purpose,  for  each  sector, the  current  methodology assumes  that the  additional 
gas consumption replaces consumption of more carbon-intensive fuels such as oil and coal, 
up to the volume of oil and coal present in the energy mix in the starting year of the period. 
In this sense, the case of a nuclear phase-out leading to an increase of gas consumption 
for electricity is not accounted as an increase of CO2 in the methodology. 

The CO2 content of the fuel(s) replaced is estimated on the basis of the energy mix in the 
given sector at the starting point of the period for TYNDP2020 or of the energy mix in 2016 
(based on Eurostat data) for TYNDP2018.  

For instance, in a given sector, if the share of oil is 9% and the share of coal 1%, a unit of 
gas replaces 9/10 unit of oil and 1/10 unit of coal. The savings associated to this switch 
are thus 9/10 oilCO2content + 1/10 coalCO2content – 1 gasCO2content.  

Although it is not fully clear in the methodology, the difference in efficiencies of gas-based 
or coal/oil-based technology can also be accounted for in the computation.  

The savings computed are thus:  

CO(cid:2870)Savings(cid:2929)(cid:2915)(cid:2913)(cid:2930)(cid:2925)(cid:2928) =  gasConsumptionIncrease(cid:2929)(cid:2915)(cid:2913)(cid:2930)(cid:2925)(cid:2928)(fuelReplacedCO2content − gasCO2content) 

Required  input:  fuel  mix  in  all  sectors  (Residential  &  Commercial,  Power,  Industry, 
Transport), at country level, for the starting year of the period or the reference year (year 
2016 for  TYNDP 2018).  Efficiencies of gas-based, coal-based  and oil-based  technologies 
used in each sector.  

Output  example:  in  country  A,  in  sector  S,  the  substitution  of  coal  by  gas  has  led  to 
saving of 0.5 MtCO2.  

1.3.3.  Step 3: Estimate the CO2 emission savings in each country 

In each country the CO2 emission savings of each sector are simply added. This leads to a 
figure of total CO2 emission saving per country during the period. 

Required input: CO2 emission savings per sector from step 2. 

Output example: in country A, CO2 emissions have decreased by 0.75 MtCO2 during the 
period.  

5 

 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

1.3.4.  Step 4: Allocation of CO2 emission savings to projects in the country 

The CO2 emission savings in a country are allocated to projects in this country via a pro-
rata allocation of the different projects’ capacity compared to the total capacity (including 
projects and existing or planned infrastructure).  

CO2savings allocated to project = (cid:3533) [CO2savings(country) ∗

(cid:2887)(cid:2925)(cid:2931)(cid:2924)(cid:2930)(cid:2928)(cid:2919)(cid:2915)(cid:2929) 

Project Capacity
Total Capacity(country)

]

In the above formula, “Countries” stands for the countries that host the considered project 
(i.e.  a  single  country  for  LNG  terminals  and  gas  storage  assets,  two  countries  for  an 
interconnector), and “Total Capacity” is the sum of the capacities of the gas infrastructure 
(including all projects) in each of the hosting countries. 

1.3.5.  Fictional examples of application of the methodology  

CO2 emission reduction in the power sector in country A between two scenarios 
for 2025 and 2030 

  Gas  consumption  increases  by  3.9  TWh/y  between  2025  and  2030  in  the  power 
sector (i.e. there is an increase of 2.34TWh of electricity from gas-based electricity 
generation – with 60% efficiency) 

  The reference electricity mix contains respectively 14% and 1% of coal and oil used 
for  power  generation  and  the  volume  of  coal-based  and  oil-based  electricity 
generation is higher than 2.34 TWh.  

  The CO2 content of the fuel replaced is 14/15  coal Content + 1/15 oil Content = 

0.344 t/MWh 

  The carbon intensity of natural gas is 0.2 t CO2/MWh.  

  The efficiency ratio of gas-based generation (60% for a CCGT) and coal-based or 

oil-based generation (around 40-45% for coal and oil plants) is 60% /45% =1.33 

  The  yearly  carbon  emission  savings  are  computed  as  3900*(0.344*1.33-0.2)  = 

1004 tCO2 per year. 

  The total carbon emission savings are computed as 1004*5 = 5020 tCO2 over the 

period 

  This calculation is then undertaken for the other concerned sectors in order to obtain 
the  total  carbon  emission  saving  per  country  which  is  then  allocated  to  the 
considered gas infrastructure. 

Allocation of CO2 emission savings in the case of a 1 GW LNG terminal 

  The project is a 1 LNG terminal connected to the gas grid in country A.  

  During the period considered, A has allowed for 0.75 MtCO2 of CO2 emission savings 

  A has some existing or planned (FID) capacities: 2 GW of LNG terminals and 4 GW 

of interconnectors 

  A has no other gas infrastructure projects  

  The benefit allocated to the project is thus 0.75 MtCO2 * 1 GW / (2+4+1 GW) = 

0.11 MtCO2 for the period.  

Application to the case of a 1 GW interconnector between two countries  

  The project is a 1 GW interconnector connecting two countries A and B.  

  CO2 emission savings would in practice only occur in country B: 3 MtCO2 savings  

6 

 
 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  Existing capacity in country A is not relevant in this computation.  

  Existing  capacity  in  country  B:  4  GW  of  interconnectors  (including  a  1.5  GW 

interconnection with A)  

  The benefit allocated to the project is 3 MtCO2 * 1 GW / (4 + 1 GW) = 0.6 Mt CO2  

1.4.  Evaluation  of  the  current  sustainability  approach  used  by 

ENTSOG for TYNDP projects 

As  discussed  in  the  previous  section,  the  methodology  currently  used  by  ENTSOG  to 
compute  the  sustainability  impacts  of  gas  infrastructure  projects  primarily  relies  on 
computing  the  CO2 emission  savings  in  each  country  during  a  given  period  of  time  and 
allocating part of these emission savings to projects. We provide below our assessment of 
the strengths and weaknesses of the current approach. 

The  main  strength  of  the  indicator  is  that  its  objective  is  clear:  computing  the  CO2 
emission savings enabled by the changes in the fuel mix, allowed by the new project. The 
indicator is also relatively easy to compute. Its computation is not based on simulations 
(unlike other indicators such as those relative to security of supply) but on data of the fuel 
mix per sector, and requires as input the capacities of projects and existing infrastructure 
(both characteristics are directly available in the TYNDP).  

Its simplicity is however also its main weakness. The approach currently used by ENTSOG 
leads to several aspects being difficult to capture, for instance:  

  The results of CO2 emission savings are independent from the potential use 
of the project. Indeed, the allocation key is solely based on capacity and not on 
flows. The potential use of a project could be estimated by considering the gas flows 
obtained in the simulations performed for other indicators of the CBA analysis for 
the considered scenarios. Flows could then be used as an allocation key to reflect 
the fact that CO2 emission savings can only be allocated to projects if these projects 
are actually used. 

  The  current  allocation  key  based  on  installed  capacities  treats  existing 
infrastructure and new projects in the same way in terms of their effect on 
fuel switching. While this could be valid for an ex post calculation (allocation of CO2 
savings to elements of an existing system assuming the project is already installed), 
we consider it is not well adapted for an ex ante analysis (calculation of CO2 savings 
for  an  investment  option).  The  benefits  of  a  project  should  be  measured  by  its 
contribution  to  sustainability,  and  not  by  the  average  contribution  of  the  gas 
infrastructure. 

  Its geographic scope is limited: for each project, fuel switches are assessed only 
for one (in case of LNG terminal or UGS facilities) or two countries (for cross-border 
pipelines).  This  approach  cannot  capture  the  transit  effects:  e.g.  a  project  built 
between A and B could help bring gas from A to C and reduce emissions in C. The 
current  approach  would  not  attribute  such  savings  to  the  project  while  it  clearly 
enables the reduction of GHG emissions. This is critical for large projects that would 
incur significant imports of gas transiting through a large number of countries.  

  Another weakness of the indicator is that it only focuses on CO2 and especially 
on CO2 avoided by fuel switch. As such, it does not capture other sustainability 
characteristics of the project, in particular its effect on methane emissions or other 
GHG and non-GHG emissions.  

  Also, the methodology does not capture  cross-sectoral dynamics. In particular, it 
does  not  account  for  the  additional  benefits  from  integrating  more  renewable 
electricity or gas or synthetic gas into the network. 

7 

 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

The computation of CO2 emission savings as currently defined is relatively straightforward 
but  presents  limitations.  Some  of  these  limitations  could  be  addressed  in  the  current 
modelling framework: 

  For  each sector, increases in gas consumption are assumed to  reduce the use  of 
fuels with higher specific CO2 emissions. This is a key assumption that requires to 
be validated, for instance by checking the feasibility of the switch (depth of the fuel 
switch). This work seems to be done by ENTSOG but could benefit from more clarity 
and transparency to be enable stakeholders to check the plausibility of the results.  

  The evolution of the energy mix and its effect on the fuel switching opportunities 
are  not  well  captured  in  the  TYNDP  2018:  its  assumptions  only  cover  gas  and 
electricity but no other fuels. This limitation is currently addressed by  using as a 
reference the energy mix of 2016 as a proxy. In the TYNDP 2020, scenarios cover 
all  fuels,  so  we  understand  that  this  proxy  will  not  be  required,  except  for  the 
‘National Trends’ scenario, which reflects Member States’ draft National Energy and 
Climate Plans3 (NECPs).  

  CO2 emission  savings are computed only for  sectors  for  which an increase in gas 
consumption  is  expected.  In  a  country  where  the  overall  gas  consumption  is 
decreasing,  there  still  can  be  CO2 emission  savings  linked  to  the  switch  of  other 
fuels.  

In order to address the other limitations, the use of an interlinked electricity-gas model for 
project-specific cost-benefit analysis is required. 

3 Most NECPs have now been published. They are available at: https://ec.europa.eu/energy/topics/energy-
strategy/national-energy-climate-plans_en 

8 

 
 
 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  DEVELOPMENT AND TESTING OF A NEW SUSTAINABILITY 
INDICATOR 

The objective of this section is to present the characteristics of an updated sustainability 
indicator.  

Based  on  discussions  with  the  European  Commission  and  with  ENTSOG,  and  given  the 
current modelling capabilities of ENTSOG, it has been agreed to focus first on improving 
the current CO2 savings indicator, trying to address its main identified drawbacks, and in 
a second time, to propose a framework to compute a more complete sustainability indicator 
that could be implemented with an interlinked model such as METIS4.  

Finally,  in  Sections  2.2  and  2.3,  we  propose  sub-indicators  to  capture  the  impacts  of  a 
project on methane emissions and non-GHG emissions. 

2.1.  Development of a sustainability indicator 

2.1.1.  Proposed  improvements  to  the  current  CO2  emission  savings 

indicator 

In this section we present possible improvements in the existing indicator calculation by 
addressing  its  key  weaknesses  and  proposing  (a)  an  updated  way  of  calculating  CO2 
emission savings and (b) an updated allocation of CO2 emission savings to projects. The 
proposed adapted CO2 indicator methodology is similar to the current version, and aims at 
computing the potential CO2 emission savings brought by a new project which leads to a 
growth of the gas demand while reducing the consumption of other more carbon-intensive 
fuels.  

In particular, similarly to the CO2 indicator currently used by ENTSOG:  

  CO2  emission  savings  are  computed  by  looking  at  potential  fuel  switches  for 
each period. The same assumptions are made on the replacement of fuels: gas 
replaces coal, oil and other more carbon-intensive fuels in priority.  

  The  computation of savings still relies  on the evaluation of the energy mix  in 
each sector for each period. In each country, the gas consumption increase in 
each  sector  will  be  assumed  to  replace  other  carbon-intensive  fuels  up  to  their 
volume in the energy mix.  

  An assumption is made on the average efficiency of technologies relative to gas 
and more  carbon-intensive fuels to be able to  compute the CO2 emission savings 
per sector taking into account the efficiencies. 

  The  approach remains mostly national, thus not capturing the supra-national 
effects  of  projects.  A  project  solving  a  bottleneck  between  A  and  B  will  not  see 
benefits from the fuel switching happening in C even if there are any (these benefits 
are captured by the interlinked approach we propose in Section 2.1.2).  

The main changes are the following:  

  The  updated  approach  does  not  associate  CO2  emission  savings  to  new 
infrastructure when there is no increase in net gas demand (local gas demand minus 

4 METIS is an interlinked model developed by Artelys on behalf of the European Commission. It has been used 
to inform policy making in various areas (e.g. proposals of the Clean Energy Package) and is available to the 
Joint Research Centre. For more information on METIS, we refer the reader to 
https://ec.europa.eu/energy/data-analysis/energy-modelling/metis_en 

9 

 
 
 
                                                 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

the  local  gas  production).  With  this  approach,  fuel  switches  are  thus  only 
assessed when there is an increase of gas demand compared to the reference 
year  (e.g.  2020).  This  choice  is  made  to  prevent  infrastructure  projects  to  claim 
part of the CO2 emission savings when the consumption in the future scenario (e.g. 
2030)  is  lower  than  today’s  consumption  and  could  be  covered  by  the  existing 
infrastructure.  

  The  increase  of  gas  demand  results  in  fuel  switches  only  when  there  is  a 
corresponding decrease of the demand for other carbon-intensive fuels. In 
each sector, if the expected gas demand increase exceeds the reduction in demand 
for other carbon-intensive fuels, the excess gas demand is counted as an increase 
of CO2. This allows to better account for the increase of gas demand either when 
there  is  an overall increase  of  consumption  in  the  sector,  or  a  switch  from  other 
fuels (e.g. a nuclear phase out replaced by gas). 

 

Instead of using capacities to allocate the CO2 emission savings resulting from fuel 
switches, the allocation key uses flows in the infrastructure. This is to account 
for the fact that CO2 emission savings are linked to the use of the project: a project 
that is not expected to be used in the future gas system should not be able to claim 
to contribute to CO2 emission reductions.  

  Additionally,  the  evaluation  of  flows  in  the  infrastructure,  either  obtained  with  a 
modelling approach or a proxy based on demand curves (more detail in chapter 3) 
assumes that the existing infrastructure is used first and new infrastructure is used 
only if necessary from a security of supply perspective: the CO2 emission savings 
that could be made without the infrastructure projects are not attributed 
to infrastructure projects.  

  RES  gases  are  also  accounted  for  in  the  approach.  CO2  emission  savings 
associated  to  production  and  use  of  RES  gases  (biogas/biomethane  and  P2G 
projects) are assessed by taking into account the benefits of having “carbon-neutral 
gas”  compared  to  natural  gas.  These  savings  are  added  to  the  savings  a  non-
renewable gas production project would be allocated (with the approach described 
above. CO2 emission savings associated to infrastructure such as interconnections 
enabling integration of RES gases are also assessed. 

  The methodology obtained with these changes can also be applied to evaluate the 

effects of fuel switching on emissions of other gases (NOx, SO2)  

The implementation of this indicator is described in more detail in chapter 3.  

10 

 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

To validate the proposed approach, the indicator has been tested for 10 projects 
of different types (LNG, pipelines, storage, ETR projects) from the  TYNDP. For that 
purpose,  ENTSOG  has  provided  us  confidential  data  from  the  TYNDP2020  and 
TYNDP2018.  

The results show that the proposed methodology avoids certain of the limitations of 
the previous indicator. In particular, CO2 savings are not allocated to  projects that 
would not be used. Also, CO2 savings from ETR projects are adequately captured.  

Some drawbacks from the methodology however remain: the CO2 savings of storages 
are  not  well  captured  due  to  the  temporal  structure  of  the  model  (with  only  two 
periods).  Also,  the  approach  remain  national,  and  does  not  allow  the  capture  of 
savings enabled by a project in countries not directly connected to the project.  

2.1.2.  Proposal  of  an 

indicator  computable  with  an 

interlinked 

electricity/gas model 

The  proposed  improvements  to  the  current  sustainability  indicator  allow  to  remove  or 
reduce some of the flaws of the existing indicator but still has some limitations that are 
difficult  to  address  without  a  substantial  improvement  of  the  modelling  approach.  In 
particular, the main limitations of the updated indicator are that:  

  The  computation  of  CO2  emission  savings  per  country  is  based  on  considered 
impacts  on  energy  consumption  only  and  remains  independent  from  projects.  In 
this  sense,  the  computation  of  the  effects  on  sustainability is  not  consistent  with 
the  CBA  approach  which  evaluates  the  benefits  of  a  project  by  comparing  the 
situations with/without the project. 

  Trans-national  CO2  emission  savings  (e.g.  situations  where  a  project  between 

country A and country B enable CO2 savings in country C) are not captured.  

  The evaluation of CO2 emission savings associated to seasonal gas storage is not 

well captured since the approach relies on yearly figures.  

  Cross sectoral dynamics, and in particular the link between the development of gas 
infrastructure  projects  and  the  development  of  renewable  electricity,  are  not 
accurately taken into account.  

These  limitations  mostly result  from the  existing limitations  of  the  modelling  framework 
used  by  ENTSOG  in  the  context  of  the  TYNDP,  indeed  it  does  not  capture  entirely  the 
interactions between gas and electricity, in particular in situations where gas and electricity 
interlinkages are important, i.e. when gas-to-power, power-to-gas or hybrid consumption 
technologies represent a non-negligible part on the energy mix5. 

We describe below the gas modelling used for  the TYNDP, the benefits of an interlinked 
model, and the indicators that could be computed with such an interlinked model.  

Since, as far as we are aware, the ENTSOs do not yet have such an interlinked model at 
their disposal, it is likely that another entity would have to carry out these calculations for 
the assessment of the projects for the establishment of the fifth PCI list. The Joint Research 
Centre  could  be  considered  for  such  an  assignment,  as  they  have  access  to  the  METIS 
model and to important calculation capabilities. 

Synthetic description of the gas modelling used for the TYNDP 

5  The  focus  study  from  ENTSOG  and  ENTSOE  on  gas/electricity  interlinkages  provides  more  detail  on  these 
phenomena. 

11 

 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

The main characteristics of the gas modelling used for the TYDNP are the following: 

  The model features one node per country. 

  The  year  is  represented  with  one  day  in  summer  and  one  day  in  winter, 

multiplied by 182/183 days. 

  The  interactions  between  gas  and  electricity  are  fixed:  the  consumption  of 
gas for power generation, the gas generation via P2G and the consumption of hybrid 
technologies are an input of the gas model, coming from the electricity simulations 
carried out by ENTSO-E.  

  The current modelling approach does not allow to switch to other fuels (e.g. 
if a gas pipeline is congested, the gas consumed by CCGTs cannot be lowered to 
reduce the congestion level). In previous exercises, ENTSOG had defined a limited 
flexibility  of  the  demand  for  gas  coming  from  the  electricity  sector  (called  the 
thermal gap) that allowed gas consumption for power to decrease, at a given cost. 
Now that gas consumption for electricity comes from the electricity modelling from 
ENTSO-E, this flexibility has been removed from the ENTSOG model.  

  Sources of gas are modelled with cost curves (piecewise linear costs) 

  Domestic  production  is  always  taken  as  priority  over  imports,  with  Norway 

considered as import.  

  There is no distinction between natural gas, hydrogen, biomethane, methane from 

P2G units. 

With  this  modelling,  simulations  are  performed  for  different  levels  of  infrastructure: 
existing,  low,  advanced  and  high  corresponding  to  set  of  projects  that  are  at  different 
statuses of development. Simulations are also done incrementally for the CBA evaluation 
of  projects.  As  flows  are  very  sensitive  to  grid  tariffs,  simulations  are  performed  three 
times, for the current tariff levels, for -50% on the tariffs and for +100% on the tariffs. 

Output of these simulations are in particular:  

  The yearly volume of gas imported by source, 

  The yearly gas production in each country,  

  The yearly flows in every infrastructure  

In  the  CBA  evaluation  of  project,  different  indicators  relative  to  security of  supply  or  to 
supply source dependence are also computed with and without the project being assessed. 

Benefits of an interlinked electricity/gas model 

As  described  above,  the  current  gas  modelling  used  by  ENTSOG  does  not  capture  the 
flexibility  linked  to  direct  interlinkages  between  gas  and  electricity  (i.e.  gas-to-power, 
power-to-gas and hybrid consumption technologies). In addition, its time resolution is too 
low  to  capture  the  dynamics  of  these  interlinkages,  which  would  require  an  hourly 
modelling  (with  virtual storage  assets to  represent  the  impact  of  linepack  storage), and 
even the dynamics of gas storages, which would benefit from a granularity higher than two 
days in the year.  

These  limitations  affect  the  assessment  of  gas  projects,  especially  in  countries  (and 
scenarios) where gas and electricity interlinkages are important, i.e. when gas-to-power, 
power-to-gas or hybrid consumption technologies represent a non-negligible part on the 
energy mix.  In  particular,  instances  of  bottlenecks  in the  gas  system due  to  a  high  gas 
consumption for G2P identified in a gas-only approach could sometimes be avoided if there 

12 

 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

are  alternatives  to  G2P  in  the  electricity  system,  e.g.  electricity  storage  or  demand 
response.  The  dynamics  of  P2G  (related  with  the  overall  carbon  content  of  electricity) 
would also be better captured. 

To reduce or remove these limitations, an interlinked model, representing simultaneously 
the gas and electricity systems, could be used. Key features of the modelling would have 
to include: 

  Modelling  of  gas,  electricity  and  heat  –  as  presented  above,  interlinkages 
between gas and electricity are significant, and with the increasing electrification of 
heat, this interlinkage is also significant with heat. The operation of gas-based heat 
generation is very likely to depend on the electricity system (e.g. electricity prices 
for combined heat and power). 

  Hourly time step – evaluating the operation of gas-based electricity generation, 
P2G,  and  hybrid  consumption  technologies  requires  to  capture  the  variability  of 
renewable  electricity  production  and  of  the  electricity  demand  and  the  use  of 
flexibilities in the electricity system.  

  CO2 emissions – in order to assess accurately the CO2 emission savings linked to 
a given project, CO2 emissions of the energy system have to be well accounted for. 
For  the  electricity  system,  it  requires  having  a  detailed  model  of  the  thermal 
generation, with for instance several age classes for assets. For the gas system, it 
requires differentiating between types of gas: natural gas, hydrogen, biomethane, 
synthetic gas from P2G, and their respective impact on CO2 emissions. 

  EU-wide  modelling  –  the  modelling  has  to  account  for  exchanges  of  energy 
between countries at the same temporal granularity as the rest of the system.  

Sustainability indicators compatible with an interlinked gas/electricity model 

With  such  an  interlinked  gas/electricity  model,  sustainability  indicators  for  gas  projects 
would be evaluated by comparing simulations with and without the assessed project, for 
the different scenarios and timeframes covered by the TYNDP scenarios. The two situations 
would then be compared in terms of CO2 emissions, RES integration, etc, similarly to what 
is done in the current CBA methodology for security of supply or supply source dependence. 
In particular, the following indicators could be produced:  

  CO2 savings – the comparison of the two situations would allow to evaluate the 
reduction  of  CO2  emissions  linked  to  the  installation  of  the  infrastructure.  In 
particular,  a  gas  infrastructure  could  enable  the  use  of  CCGTs  for  electricity 
production,  thus  avoiding  the  use  of  coal-based  generation,  thus  providing  CO2 
savings.  These  computations  would  require  the  interlinked  model  to  include  a 
sufficiently  detailed  model  of  the  thermal  generation  in  each  country,  with  for 
instance several age classes for assets.  

  Emissions of other gases – if included in the modelling, the emissions of other 
gas linked to fuel combustion could be included as an indicator. The scope of these 
emissions could for instance include methane, NOx and SO2.  

  Integration of RES-e – The interlinked model will allow to assess the effect of a 
P2G project in terms of quantity of RES integrated by comparing the curtailments 
of RES-e in each situation. The model would also allow to study the effect of different 
operational modes for P2G on the integration of RES-e and on the overall emissions. 
In particular, the effect of a power-to-gas infrastructure on CO2 emissions is very 
different between an operation in baseload or an operation following (and limited 
to) the curtailment of RES-e.  

  Integration  of  RES  gases  –  Similarly,  the  effect  of  projects  in  terms  of  the 
integration  of  RES  gases can  also  be  evaluated  by  comparing  the  two  situations. 
Competition  between  sources  (bio-methane,  hydrogen  from  P2G,  methane  from 

13 

 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

P2G, natural gas) will be more accurate with the explicit modelling of power-to-gas 
which captures the limitations of the gas and electricity systems.  

This  proposed  methodology  for  computing  sustainability  indicators  would  be  consistent 
with  the  current  definition  of  the  other  indicators  included  in  the  CBA  (which  aims  at 
assessing,  in  given  scenarios,  how  a  project  brings  benefits  in  a  given  system 
configuration) than the current indicator that focuses  on the benefits  from fuel switches 
along a trajectory.  

A summary of the characteristics of the approaches for the computation of CO2 emission 
savings is presented in the figure below. 

Figure 2-1 Comparison between the different indicators 

Current 
Sustainability 
indicator 

Improved 
sustainability 
indicator  

Interlinked 
model 
Sustainability 
indicator  

 

 
 
 
 

Simplicity to compute the indicator 

Possibility to attribute a negative CO2 impact 
to a project 

CO2 savings allocation prioritise existing 
infrastructure. 

CO2 savings are linked to expected flows in 
the project.  

Evaluation of the effect of projects on CO2 
based on a marginal approach (operation of 
the system with/without the project similarly 
to the CBA) 

Accuracy for the evaluation of CO2 savings 
of storages 

Cross sectoral assessment (incl. P2G) 

Trans-national assessment  

 
 
 
 

 
 
 

Compatibility with a net-zero emissions future 

Given  the  ambitious  objectives  of  the  European  Commission  in  terms  of  CO2  emissions 
reduction at the 2050 horizon, the question of the compatibility of projects with a climate 
neutral future has to be raised, in particular to avoid investing in projects that are not likely 
to  be  used  in  a  decarbonised  economy  (potential  stranded  assets).  The  European 
Commission’s  Long-Term  Strategy,  in  particular  in  the  pathways  complying  with  a 
limitation  to  a  1.5°C  temperature  increase  objective,  1.5TECH  and  1.5LIFE,  envisions  a 
high electrification of demand, usually accompanied with a reduction of the gas demand 
and a diversification of the sources and types of gas being consumed. In this context, the 
development of new infrastructure faces two main risks:  

  The infrastructure could be useless for the operation of the system in 2050, with 

lower levels of gas demand in Europe, and structurally different flows.  

  The  infrastructure  could  be  incompatible  with  a  network  with  high  shares  of 

hydrogen.  

14 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

One way to identify the first situation is to extend the scope of the cost-benefit analyses 
to be performed in the TYNDP to climate neutral scenarios for 2050 (we understand that 
there  will  be  no  project-specific  simulations  for  2050  in  TYNDP  2020).  In  this  case,  the 
“standard” application of the CBA will identify which projects are useful for the system in 
2050, both from an economical and an environmental perspective. The extension of the 
TYNDP to pathways produced by the European Commission could be considered to be able 
to  ensure  that  assets  are  assessed  on  situations  meeting  the  European  objectives.  This 
could also be relevant for the 2030 time horizon, for which the ambition levels are likely to 
be revised upwards. 

The second situation (incompatibility with high shares of hydrogen) is related to the type 
of  infrastructure  itself.  Project  promoters  should  describe  whether  their  project  is 
compatible with high shares or 100% share of hydrogen. 

2.2.  Dealing with methane emissions  

2.2.1.  Methane emissions 

Methane  emissions  are  emissions  (fugitive  or  from  venting  and incomplete  combustion) 
coming from different sources all along the natural gas value chain, from exploration to 
end-consumption of the gas. The precise levels of methane emissions are complicated to 
evaluate due to several factors, including the lack of measurements and the low level of 
transparency. 

In  its  methane  emissions  tracker6,  the  IEA  quotes  several  mitigation  measures  for 
downstream gas, including: 

  Leak detection and repair (LDAR) refers to the process of locating and repairing 
fugitive  leaks.  LDAR  encompasses  several  techniques  and  equipment  types.  One 
common  approach  is  the  use  of  infrared  cameras,  which  make  methane  leaks 
visible.  

  Replace with instrument air systems: Pumps and controllers are  used at well 
sites  and  across  the  oil  and  natural  gas  supply  chains  for  a  variety  of  purposes. 
Commonly, they are pneumatic, using pressurized natural gas as a power source. 
These  pumps  vent  natural  gas  in  the  ordinary  course  of  business.  They  can  be 
replaced  by  instrument air systems, which pressurize  ambient  air  to  perform  the 
same functions without emitting methane. 

  Vapour Recovery Units (VRUs): VRUs are small compressors designed to capture 
emissions that build up in pieces of equipment across the oil and natural gas supply 
chains. For instance, VRUs can pull off gases that accumulate in oil storage tanks 
and that are otherwise periodically vented to the atmosphere to prevent explosion. 

  Install flares if relevant 

  Replace compressor seal or rod: Maintenance of the seal and rods over the time 

can significantly reduce the methane emissions. 

In their report « Potential ways the gas industry can contribute to the reduction of methane 
emissions » presented during the 32nd Madrid Forum in June 2019, GIE and MARCOGAZ 
present  the  Best  Available  Techniques  in  transmission,  LNG  terminals,  storage  and 
distribution to reduce the methane emissions: 

  LDAR programmes; 

6 https://www.iea.org/reports/methane-tracker-2020/methane-abatement-options#abatement-technologies-
and-costs 

15 

 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  Minimise  venting  of  hydrocarbons  from  purges  and  pilots,  without  compromising 
safety, through measures including installation of purge gas reduction devices, flare 
gas recovery units and inert purge gas; 

  Replacing natural gas pneumatic valves with electric or air equipment or mechanical 

controls; 

 

Implement minimising vents programmes; 

  Recompression instead venting; 

  Recover boil off gas during ship loading and eliminate – to the extent practicable – 

flaring; 

 

Implement excess flow valve; 

  Use of vacuum pressure pumps during commissioning of distribution networks; 

  Replacing natural gas starters with electric engine starters at compressors, hence 

reducing operational venting; 

  Hot tapping techniques procedures. 

2.2.2.  Sub-indicators related to methane emissions 

We  propose  that  two  sub-indicators  related to methane  emissions are  introduced  in the 
sustainability indicator: 

  Indicator relative to project-level emissions (S-ME1): The first sub-indicator 
is  an  indicator  presenting  the  efforts  the  project  promoter  is  making  to  take 
appropriate measures to reduce the level of methane emissions directly linked to 
the construction and operation of its project.  

  Indicator  relative  to  system-wide  emissions  (S-ME2):  This  second  sub-
indicator is an indicator that aims at capturing the impact of the project on methane 
on the overall system due to the additional gas consumption enabled by the project.  

In the following paragraphs, we describe our approach for these two sub-indicators: 

Indicator relative to project-level emissions (S-ME1) 

This indicator shall be based on a benchmarking approach. The objective of the comparison 
is to assess whether the project promoter proposes technologies or processes that reach 
state-of-the-art quality levels. The project promoter shall also be able to provide comments 
to explain what mitigation measures are being taken to ensure that only the lowest possible 
levels of methane emissions will materialise (only for the emissions directly linked with the 
project). The costs of these measures should be mentioned by the project promoter.  

In addition, the project promoter is encouraged to propose mitigation measures should its 
project cause methane emissions that are not in its direct control. 

The  definition  of  the  parameters  and  corresponding  values  to  be  considered  in  the 
benchmark is beyond the scope of the project. We recommend that they are defined by 
ENTSOG’s specialists. The indicator should at least capture the following steps of the life 
of a project: 

  Construction  –  Ensuring  the  technology  installed  is  state-of-the-art  in  terms  of 

methane emissions.  

  Inspection  and  measure  of  the  emissions  or  leakages  –  Ensuring  the 

emissions are tracked and reported.  

16 

 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  Maintenance  and  renovation  –  Ensuring  proper  maintenance  is  planned,  and 

pieces of the infrastructure are replaced with the adequate timing. 

We  recommend that ENTSOG is tasked with the definition of project characteristics that 
should be benchmarked and of the value of the benchmarking parameters. These values 
should be updated at least for each TYNDP exercise (i.e. at least every second year). 

Indicator relative to system-wide emissions (S-ME2) 

Estimating the total methane emissions caused by the modifications of the structure of gas 
flows  that  can  be  linked  with  the  presence  of  a  new  project  is  a  complex  task.  Indeed, 
several facts complicate the analysis: 

  The methane leaking factors of all infrastructure should be measured and reported. 

  The  structure  of  the  gas  flows  and  how  a  new  infrastructure  may  impact  them 
depends on commercial arrangements between market participants. Most of these 
arrangements are not publicly available. 

 

In the case of LNG terminals, the analysis is even more complicated since the source 
of LNG might have very different methane leaking factors (depending on the gas 
extraction methods) 

Based on this, we propose to only include the additional volumes of methane emissions at 
the national level (i.e. due to the additional consumption of gas in the country/countries 
that host the project). The approach thus includes potential increase in emissions on the 
transportation and distribution networks. The proposed procedure is as follows: 

1. Use the IEA methane emissions tracker7 (or a similar source) to obtain the volume of 
methane emissions from downstream gas for each country (for the latest year available), 
measured in ktCH4.  

2. Divide these methane emissions by the gas consumption in the country during the same 
year. The result is a methane emission factor for each country in ktCH4/MWh representing 
the emissions from downstream gas. 

3. Multiply this methane emission factor by the level of gas consumption allocated to the 
assessed infrastructure projects. For this last step, use the same allocation key as for CO2 
emissions (see Section 3.1.2 for more details). 

2.3.  Non-GHG emissions (PM, SOx, NOx) 

In  the  European  Union,  the  National  Emission  ceilings  directive  sets  national  emission 
reduction commitments for 5 different pollutants:  

  nitrogen oxides (NOx)  

 

 

sulphur dioxides (SO2) 

fine particulate matter (PM2.5)  

  non-methane volatile organic compounds (NMVOCs) 

  ammonia (NH3) 

7https://www.iea.org/reports/methane-tracker-2020/interactive-country-and-regional-estimates 

17 

 
 
 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

These pollutants contribute to poor air quality, leading to significant negative impacts on 
human health and the environment. Energy use in transport, industry and in power and 
heat generation are major sources of emissions especially for NOx and SO2.8 

Figure 2-2 Estimated impact of different factors on the reduction in emissions of 
SO2 and NOx from public electricity and heat production between 1990 and 
2004, EU-25 

SO2 

NOx 

Source: European Environmental Agency9 

Following the same approach as the one developed for CO2 (and detailed in sections 2.1.1 
and  3.1),  a  sub-indicator  for  non-GHG  emissions  could  be  built,  based  on  emission 
factors by types of fuel for each pollutant. The computation of emissions would rely on the 
evaluation of fuel switches and the use of emission factors per fuel and per sector for each 
gas.  

The limit of such an approach is that the emissions factors greatly differ depending on the 
use of the fuel, and in particular depending on the combustion techniques and abatement 
techniques. This is already true today and will be even more visible if more constraints are 
set on the emission of these pollutants. The use of this methodology would thus require 
corresponding  detail  on  the  consumption  of  fuel  by  sub-sector,  with  the  corresponding 
abatement techniques used with each fuel, for each scenario. This would help compute the 
benefits in terms of emissions due to fuel switches in each sub-sectors.  

For that purpose, we thus suggest that ENTSO-E and ENTSOG construct, for their TYNDP 
works, a joint database of emissions factors of non-GHG, with a decomposition by fuel and 
by sector  and  sub-sector  and by  country.  Those  emissions  factors  should  also  take  into 
account the expected decrease of the specific emissions over the years to come, with the 
improvement  of  abatement  techniques.  This  would  be  a  prerequisite  for  a  reliable 
computation of these emissions. 

Sources  for  these  sector-specific  emission  factors  could  be  the  IPCC  database10,  which 
follows a methodology they developed to calculate those emissions for different sources of 
energy  and  different  usages.  The  UNFCCC  national  inventory  report,  gathered  in  the 
Greenhouse  Gas  Inventory database11,  could also be exploited. For each of the Annex  I 
Parties to the Kyoto Protocol, this database contains all greenhouse gas (GHG) emissions 
and removals, implied emission factors and activity data. However, the required level of 
precision in order to be used for the sustainability indicator, is only available for CO2, CH4 
and N2O. For the other non-GHG gases such as NOx, SO2 and NMVOC, the emissions are 

8https://www.eea.europa.eu/data-and-maps/indicators/main-anthropogenic-air-pollutant-
emissions/assessment-6 
9 https://www.eea.europa.eu/data-and-maps/indicators/en09-emissions-co2-so2-and/emissions-co2-so2-and-
nox 
10 https://www.ipcc-nggip.iges.or.jp/EFDB/find_ef.php?ipcc_code=1&ipcc_level=0 
11 https://di.unfccc.int/flex_annex1 

18 

 
 
 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

aggregated and are not imputed to specific fuels. One possibility is to directly use the IPPC 
database12  to  obtain  default  values  for  emissions  factors  of  NOx  and  NMVOC  (for  other 
gases the availability of the data is not systematic). An important drawback of the IPCC 
database is that the default data are rather old and do not take into account abatement 
measures that enabled a clear decline of non-GHG emissions over the past few years13.As 
far  as  PM  are  concerned,  the  level  of  emissions  and  the  size  of  the  particles  are  very 
complicated to compute given that they depend on the sector, on the fuel properties, but 
also on the technologies and emission process, which is highly dependent on the quality of 
the combustion14. Therefore, the same issues are applicable here. As PM pollution is a local 
issue  rather  than  a  global issue,  it  is  difficult  to  compare  sources  of  emissions  because 
these emissions are far more problematic if they reach inhabitants. 

As an exercise the proposed methodology has been used without differentiating the type 
of technologies inside each sector, and using the emission factors by fuel provided in Box 
4.1 (see below on section 4.2.3). With this level of detail, the approach shows that the fuel 
switch from coal or oil to gas tends to reduce significantly the emissions of these pollutants, 
since emissions factors remain significantly lower (or nil) when burning gas.  

12 https://www.ipcc-nggip.iges.or.jp/EFDB/find_ef.php?ipcc_code=1&ipcc_level=0 
13 https://www.eea.europa.eu/data-and-maps/dashboards/air-pollutant-emissions-data-viewer-2 

14 M. Guevara, Emissions of Primary Particulate Matter , in Airborne Particulate Matter: Sources, Atmospheric 
Processes and Health, 2016, pp. 1-34 DOI: 10.1039/9781782626589-00001 

19 

 
 
                                                 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  INDICATOR DESCRIPTION AND IMPLEMENTATION 

In this section, we present in more details the proposed indicator for CO2 emission savings, 
step by step, with proposals of datasets to use for the input data.  

3.1.  Description of the indicator implementation 

The proposed indicator is a two-steps indicator, similarly to the indicator currently used by 
ENTSOG:  

  CO2 emission savings assessment step: In this step we compute the reduction 
of CO2 emission enabled by the evolution of the gas infrastructure to support the 
growth of the gas demand, if this gas consumption increase can be associated to a 
fuel switch.  

  CO2 allocation step:  In this step, the CO2  emission savings computed in step 1 

are allocated to the different infrastructure projects. 

These  steps  are  performed  for  each  scenario  and  each  year  of  the  scenario,  for  each 
country.  

3.1.1.  CO2 emission savings assessment step 

3.1.1.1.  Phase 1: Fossil fuel consumption assumptions 

The first phase consists in gathering the consumption by fossil fuel in the different sectors 
for the different scenarios.  

The consumption is divided into 4 demand sectors: 

  Residential & Commercial demand 

 

Industrial demand 

  Transports 

  Power 

The fossil fuels taken into account are gas, coal and oil.  

Required inputs 

Gas,  coal  and  oil  consumption  in  each  sector  (Residential  &  Commercial,  Industrial,  Transports,  Power 
generation), at country level, for each time step. 

Possible sources: For two of TYNDP2020 scenarios, fuel mixes by sector will be available. For the third 
scenario, based on NECPs, using this approach will be less reliable given the fuel mixes are not available. 
A solution would be to use the fuel mixes of the closest scenario. 

3.1.1.2.  Phase 2: Assessment of the evolution of energy consumption. 

In  this  phase,  we  compute  the  variation  of  demand  by  sector  and  fuel  compared  to  a 
predefined reference year. For TYNDP 2020 this reference year could be 2020. 

For each scenario and year, the difference in consumption compared to the reference year 
is  computed.  For  non-gas  consumptions  (oil  and  coal),  we  only  compute  the  expected 
reductions in consumption since the objective is to identify years where gas increases and 
coal/oil decreases.  

20 

 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

3.1.1.3.  Phase 3: Assessment of the evolution of end-use consumption 

In  this  phase,  we  compute  the  corresponding  consumption  change  in  terms  of  end-use 
consumption. Converting primary energy consumption to end-use consumptions allows to 
compare the amount of fuels used in each sector when assessing if there has been a switch 
or not. 

For instance, for the electricity sector, a 150 TWh gas consumption increase will correspond 
to  an  increase  of  150*60%  =  90  TWh  of  electricity  produced  with  gas,  assuming  the 
electricity is produced with a CCGT.  

This  computation  requires  an  assumption  for  the  average  efficiency  of  technologies 
functioning  with  the  different  fuels  in  each  sector.  To  convert  the  previously  computed 
variation  of  primary  energy  consumption  into  variation  of  end-use  consumption,  we 
multiply the primary energy consumption by the corresponding average efficiency. 

For the indicator, we use one standard efficiency level15 per sector and per fuel for each 
year and scenario. 

ΔEndUseConsumption(cid:2929)(cid:2915)(cid:2913)

(cid:3177)(fuel(cid:2916)) = ΔPrimaryEnergyConsumption(cid:2929)(cid:2915)(cid:2913)(cid:2930)(cid:2925)(cid:2928) (fuel(cid:2916)) ∗ efficiency(fuel_f) 

Required inputs 

Average efficiencies for each fuel (gas, oil and solid fuels) and for the 4 sectors (Residential & Commercial, 
Industrial, Transports, Power generation), at country level, for each time step.  

Possible sources: Assumptions should be taken from the TYNDP2020 if available. If not, these might be 
completed with inputs from public sources (ASSET database, IEA, ETRI, cf. footnote). 

3.1.1.4.  Phase  4:  Computation  of  the  switches  in  terms  of  end-use 

consumption  

In this step, for each sector and each fuel, we allocate the increase of end-use consumption 
supplied with gas to either fuel switches (if there has been enough reduction of coal and 
oil) or to a pure increase of gas. 

A sectoral fuel switch potential is used to allocate the increase of end-use consumption 
supplied with gas. For each sector, this potential corresponds to the sum of the decreases 
of end-use consumption supplied with the other fuels (oil and solid fuels). This correspond 
to the maximum fuel switch potential. 

The assumption is made that the increase in gas consumption is made first to replace oil 
and gas technologies, filling the fuel switch potential. The excess gas increase (if there is 
any) is considered as a pure increase of gas. 

If the increase in end-use consumption supplied with gas is not sufficient to replace the 
whole  “sectoral  fuel switch  potential”, we assume  that  gas  replaces  coal  and  oil, with  a 
pro-rata decrease of oil and coal in the concerned sector. 

After this repartition of the sectoral gas demand increase resulting from a fuel switching 
or  from  other  developments,  the  end-use  consumption  is  converted  to  primary  energy 
consumption that is used to compute the CO2 emission savings (if any). 

15 Assumptions for technology parameters could rely for instance on the ASSET database (2018), the IEA-
ETSAP database, or the European Technology Reference Indicator (2014). 
https://ec.europa.eu/energy/sites/ener/files/documents/2018_06_27_technology_pathways_-
_finalreportmain2.pdf, https://iea-etsap.org/index.php/energy-technology-data, 
https://setis.ec.europa.eu/system/files/ETRI_2014.pdf 

21 

 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Outputs 

For each sector and each time step: the fuel corresponding to each fuel (coal and oil) and the pure gas 
increase. 

3.1.1.5.  Phase 5: Conversion into CO2 emissions 

The objective of this step is to compute CO2 emission savings that are expected in each 
concerned sector by the fuel switching from coal or oil to gas. For each fuel (coal, oil and 
gas), an emission factor EF is used, in kgCO2/kWh. 

The CO2 computation is performed as follows: 

  The increase of gas consumption which corresponds to a fuel switch from coal leads 
to a change in CO2 emissions of: IncreaseGasToReplaceCoal ∗   EF(cid:3034)(cid:3028)(cid:3046) − DecreaseCoal ∗ EF(cid:2913)(cid:2925)(cid:2911)(cid:2922)  

  The increase of gas consumption which corresponds to a fuel switch from oil leads 
to a change in CO2 emissions of: IncreaseGasToReplaceOil ∗   EF(cid:3034)(cid:3028)(cid:3046) − DecreaseOil ∗ EF(cid:2925)(cid:2919)(cid:2922)  

  The pure increase of gas leads to a pure increase of CO2 emissions of: 

RawIncrease ∗ EF(cid:2917)(cid:2911)(cid:2929) 

The total variation of CO2 emissions for each sector is thus:  

CO(cid:2870)Variation(cid:2929)(cid:2915)(cid:2913)(cid:2930)(cid:2925)(cid:2928)

= IncreaseGasToReplaceCoal ∗   EF(cid:3034)(cid:3028)(cid:3046) − DecreaseCoal ∗ EF(cid:2913)(cid:2925)(cid:2911)(cid:2922) 
+  IncreaseGasToReplaceOil ∗   EF(cid:3034)(cid:3028)(cid:3046) − DecreaseOil ∗ EF(cid:2925)(cid:2919)(cid:2922)    + RawIncrease ∗ EF(cid:2917)(cid:2911)(cid:2929) 

Required inputs 

CO2 emission factor (kgCO2/kWh) for each fuel (coal, oil, gas), each country. The gas emission factors 
should not include a potential reduction from RES gases as these impacts are handled separately. 

Possible sources: Assumptions for emission factors should be taken from TYNDP2020 if available. If not, 
CO2 contents from the IPCC database could be taken. 

Outputs 

For each time step, total CO2 emission savings per sector in ktCO2/y. 

3.1.1.6.  Phase  6:  Final  computation  of  the  CO2  emission  savings  to  be 

allocated to gas infrastructure 

The previous computations allow to compute the emission savings per sector linked to the 
increase  of gas consumption in each  sector.  In this step, we  compute the CO2  emission 
savings linked with the overall increase of gas demand, which is not necessarily the sum 
of the previous figures, e.g. if there is another sector where the gas demand decreases.  

For instance, we consider a case where 2 sectors have an increase and one has a decrease.  

22 

 
 
 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Sector 1  

Sector 2 

Sector 3 

Total 

Change between reference year 
and the considered scenario 

+10 TWh 

+20 TWh 

-15 TWh 

+15TWh 

CO2 savings per sector 

8 Mt 

10 Mt 

N/A 

N/A  

The CO2 benefits associated to the increase of 15 TWh are computed pro-rata the volume 
of increase in each sector: 

CO(cid:2870)Savings(cid:2930)(cid:2925)(cid:2930)(cid:2911)(cid:2922) =  GasIncrease(cid:2930)(cid:2925)(cid:2930)(cid:2911)(cid:2922) ∗

CO(cid:2870)Savings(cid:2929)(cid:2915)(cid:2913)(cid:2930)(cid:2925)(cid:2928)(cid:2869) +  CO(cid:2870)Savings(cid:2929)(cid:2915)(cid:2913)(cid:2930)(cid:2925)(cid:2928)(cid:2870)
GasIncrease(cid:2929)(cid:2915)(cid:2913)(cid:2930)(cid:2925)(cid:2928)(cid:2869) + Gas(cid:2919)(cid:2924)(cid:2913)(cid:2928)(cid:2915)(cid:2911)(cid:2929)(cid:2915)(cid:3177)(cid:3163)(cid:3161)(cid:3178)(cid:3173)(cid:3176)(cid:3118)

= 15 ∗

18
30

=  9 Mt 

The general formula is:  

CO(cid:2870)Savings(cid:2930)(cid:2925)(cid:2930)(cid:2911)(cid:2922) =  GasIncrease(cid:2930)(cid:2925)(cid:2930)(cid:2911)(cid:2922) ∗

3.1.2.  CO2 allocation step 

∑
∑

(cid:3020)(cid:3032)(cid:3030)(cid:3047)(cid:3042)(cid:3045)(cid:3046)(cid:3024)(cid:3036)(cid:3047)(cid:3035)(cid:3008)(cid:3028)(cid:3046)(cid:3036)(cid:3041)(cid:3030)(cid:3045)(cid:3032)(cid:3028)(cid:3046)(cid:3032)

(cid:3020)(cid:3032)(cid:3030)(cid:3047)(cid:3042)(cid:3045)(cid:3046)(cid:3024)(cid:3036)(cid:3047)(cid:3035)(cid:3008)(cid:3028)(cid:3046)(cid:3036)(cid:3041)(cid:3030)(cid:3045)(cid:3032)(cid:3028)(cid:3046)(cid:3032)

CO(cid:2870)Savings(cid:2929)(cid:2915)(cid:2913)(cid:2930)(cid:2925)(cid:2928)
GasIncrease(cid:2929)(cid:2915)(cid:2913)(cid:2930)(cid:2925)(cid:2928)

This second step of the indicator aims at allocating the previously calculated CO2 savings 
to the gas infrastructure (both existing infrastructure and projects). The allocation depends 
on flows in the existing infrastructure and on projects, as obtained in the simulations from 
ENTSOG.  We  also  propose  a  way  of  assessing  the  flows  in  the  case  simulations  are 
unavailable. 

3.1.2.1.  Description of the allocation method 

This method allocates the CO2 emission savings to projects pro rata the flows obtained in 
simulations of the scenario.  

In order to prioritise the use of existing infrastructure, simulations used should consider a 
high  tariff  for  the  studied  infrastructure  projects  and  a  lower  tariff  for  existing 
infrastructure. 

For the project p, the allocation factor is simply given by the formula: 

allocationFactor(cid:2926) =

ϕ(cid:2926)

∑

(cid:2919)(cid:2924)(cid:2916)(cid:2928)(cid:2911)(cid:2929)(cid:2930)(cid:2928)(cid:2931)(cid:2913)(cid:2930)(cid:2931)(cid:2928)(cid:2915)(cid:3167)((cid:2915)(cid:2934)(cid:2919)(cid:2929)(cid:2930)(cid:2919)(cid:2924)(cid:2917) (cid:2925)(cid:2928) (cid:2924)(cid:2915)(cid:2933))

ϕ(cid:2919)

where 𝝓𝒑 is the gas flow in MWh that passes through the infrastructure during the year.  

This allocation factor is then multiplied by the CO2 savings computed in the CO2 savings 
assessment step.  

Required inputs 

ENTSOG simulation results. Simulation of the scenario with the existing infra (low tariff) and infrastructure 
projects (high tariffs) 

3.1.2.2.  Alternative to flows from simulations 

If  the  simulations  are  not  available,  flows  could  be  approximated  using  the  following 
approach:  

23 

 
 
 
  
 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  We build a load duration curve for the country corresponding to the scenario. This 
can be done by using a historical gas demand curve for the country (obtainable on 
the ENTSOG website), and scaling it upwards or downwards to obtain the adequate 
yearly consumption. When possible, this scaling can be done with a different ratio 
for winter and summer as illustrated in Figure 3-1.  

Figure 3-1 Construction of an approximated demand curve 

  We compute the “Project Capacity Share” (PCS): the ratio between the capacity of 
projects and the total capacity of the infrastructure (existing and new). This has to 
be based on the capacities of projects and infrastructure from TYNDP.  

PCS =

∑

∑

(cid:2926)(cid:2928)(cid:2925)(cid:2920)(cid:2915)(cid:2913)(cid:2930)(cid:2929)

Capacity

(cid:2919)(cid:2924)(cid:2916)(cid:2928)(cid:2911)(cid:2929)(cid:2930)(cid:2928)(cid:2931)(cid:2913)(cid:2930)(cid:2931)(cid:2928)(cid:2915) ((cid:2926)(cid:2928)(cid:2925)(cid:2920)(cid:2915)(cid:2913)(cid:2930)(cid:2929)(cid:2878)(cid:2915)(cid:2934)(cid:2919)(cid:2929)(cid:2930)

)

Capacity

  We consider that without the new projects, the existing infrastructure covers only 
(1-PCS)*peakload. This means that the part of the curve below (1-PCS)*peakload 
can  be  covered  by  existing  infrastructure,  while  the  remainder  requires  the  new 
projects. We then compute the “Volume enabled by projects” (VEP): the volume of 
gas above (1-PCS)*peakload, which is call the “Volume enabled by projects” (VEP).  

Figure 3-2 Estimation of the volume of gas enabled by projects 

  CO2  emission  savings  for  the  country  are  allocated  to  new  projects  and  existing 

infrastructure pro rata these volumes of energy.  

CO2Savingsprojects =  CO2Savingstotal ∗

𝑉𝐸𝑃

𝑡𝑜𝑡𝑎𝑙𝐷𝑒𝑚𝑎𝑛𝑑

24 

 
 
 
 
 
 
 
 
 
  
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  Finally, this CO2 emission saving for all projects can be allocated to all projects (no 

existing infrastructure) pro rata their respective capacity.  

CO2Savingsproject p =   CO2Savingsprojects   ∗

Capacityproject p
∑
Capacity

projects

Required inputs 

A demand curve for the reference year.  

Gas consumption for the scenario (possibly with winter/summer). 

Possible source: the demand curve can be extracted from the ENTSOG Transparency platform. 

3.1.3.  CO2 emission savings resulting from RES gas projects 

The savings associated to RES gas projects (biogas, biomethane or P2G projects) can be 
divided in two parts: 

  Following the previously presented approach, these projects are contributors to fuel 
switches from more CO2-intensive fuels to gas, and can be allocated a CO2 emission 
saving. 

  Additionally,  these  projects  can  be  allocated  another  benefit  in  terms  of  CO2 

emissions since the RES-gas produced avoid consumption of non-RES gas.  

Both benefits can be accounted for in the indicator.  

The first part can be computed with a similar approach to what was proposed above, by 
considering the RES gas project as any other project (like a LNG terminal or gas production 
facility).  

The additional benefits can be computed with the following equation: 

AdditionalCO(cid:2870)Savings = V(cid:2902)(cid:2889)(cid:2903)(cid:2917)(cid:2911)(cid:2929) ∗ (EF(cid:2917)(cid:2911)(cid:2929) − EF(cid:2902)(cid:2889)(cid:2903)(cid:2917)(cid:2911)(cid:2929)) 

Where  EF is the emission factor and   𝑉𝑟𝑒𝑠𝑔𝑎𝑠 the volume  of RES gas that is produced per 
year by the project, based on the scenario assumption. 

3.1.4.  Accounting for benefits linked to the integration of RES gases 

In some cases, interconnection projects might allow to integrate more RES gases in the 
system.  This  can  be  the  case  when  the  local  generation  of  RES  gas  exceeds  the  local 
demand  and  the  existing  export  capacity,  which  is  expected  to  only  occur  rarely  in  the 
coming  years  but  might  occur  more  frequently  as  of  2040.  Except  for  this  case, 
interconnections should not be allocated CO2 benefits resulting from RES gas integration 
since these benefits are already counted for the RES gas projects themselves (see above).  

The benefits related to RES integration come in addition to the benefits from fuel switching 
and can be computed with the following equation: 

AdditionalCO(cid:2870)Savings(cid:2926)(cid:2928)(cid:2925)(cid:2920)(cid:2915)(cid:2913)(cid:2930)(cid:2929) = AdditionalVolume(cid:2902)(cid:2889)(cid:2903)(cid:2917)(cid:2911)(cid:2929) ∗ (EF(cid:2917)(cid:2911)(cid:2929) − EF(cid:2902)(cid:2889)(cid:2903)(cid:2917)(cid:2911)(cid:2929)) 

Where AdditionalVolumeRESgas is the additional volume of RES gas integrated in the system 
thanks to the considered projects, i.e. the sum of all flows in the projects.  

25 

 
 
  
 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  GAS-RELATED INFRASTRUCTURE PROJECTS AND THEIR 
SUSTAINABILITY CHARACTERISTICS 

The  key objective  of this  chapter  is to  identify different types  of  imaginable  gas-related 
infrastructure projects and assess their overall sustainability characteristics. For this the 
chapter is composed of two sub-sections: 

  Gas-related infrastructure projects 

  Overall sustainability characteristics of selected projects 

The main added-value of the chapter is to provide an overview of the sustainability aspects 
of a wider range of potential gas-related infrastructure projects than the range of projects 
eligible under the current TEN-E criteria, and to guarantee that the configurations that are 
being tested in the development of the sustainability indicator are relevant and likely to 
appear in projects promoters submit to ENTSOG for inclusion in the TYNDP. A number of 
technologies are becoming more widespread for the production, storage and transport of 
biomethane,  synthetic  methane  and  hydrogen,  but  may  not  yet  be  eligible  for  gas  PCI 
status. This despite potentially being able to contribute not only to the sustainability of the 
EU energy system but also to competition, market integration and/or security of supply. 
The chapter furthermore supports the definition of the fictional project configurations to be 
used for the testing of the new sustainability indicator. 

This chapter does not cover the following projects, which are addressed by the TYNDP or 
PCI selection processes but which are out of scope of the present analysis: 

  Conventional transport and storage of natural gas; 

  Conventional LNG terminals; 

  Biogas production; 

  Other networks, such as for CO2 and heat; 

  Vehicle conversion for the use of alternative fuels. 

4.1.  Gas-related infrastructure projects 

This sub-section first presents the long-list of individual gas-related infrastructure projects 
and categorizes them according to a customized typology. Next, individual projects in this 
long-list are grouped into the most likely cluster of projects, as some may be more sensible 
as a group of projects than as a stand-alone project. 

The  long-list  of  individual  gas-related  infrastructure  projects  was  developed  based  on 
existing literature related to the decarbonization of the gas sector as well as on existing 
projects  being  currently  developed  in  the  gas  sector.  Main  information  sources  for  the 
exercise comprised multiple recent studies, as well as the list of ETR projects of the 2020 
gas Ten-Year Network Development Plan.16 

The  long-list  of  gas-related  infrastructure  projects  (which  excludes  conventional  gas 
infrastructure projects) is divided according to the main project function as follows: 

16 Including Trinomics, LBST and E3-M (2019) Impact of the use of the biomethane and of the hydrogen 
potential on trans-European infrastructure; Trinomics, LBST et al. (2018) The role of Trans-European gas 
infrastructure in the light of the 2050 decarbonisation targets; Artelys - Investigation on the interlinkage 
between gas and electricity scenarios and infrastructure projects assessment (2019); DNV GL (2018) Hydrogen 
as an energy carrier – an evaluation of emerging hydrogen value chains; GIE and Marcogaz (2019) Potential 
ways the gas industry can contribute to the reduction of methane emissions; Frontier Economics et al. (2019) 
Potentials of sector coupling for decarbonisation – Assessing regulatory barriers in linking the gas and electricity 
sectors in the EU 

26 

 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  Transport 

o 

o 

o 

o 

o 

to allow reverse gas flows from the distribution to the transport network, to 
enable large-scale injection of biomethane at distribution level, where local 
injection might (mainly in the summer period) exceed local demand; 

to  adapt  existing  gas  transmission  or  distribution  grids,  to  make  them 
suitable for hydrogen admixtures up to a certain threshold (e.g. 10 vol%), 
both intra-EU and for import pipelines from foreign countries; 

to  adapt  existing  gas  transmission  or  distribution  grids,  to  make  them 
suitable for 100% hydrogen; 

to  build  new  transmission  or  distribution  grids  suitable  for  hydrogen 
transport; 

to  build  offshore  infrastructure  for  the  transport  of  renewable  hydrogen 
produced from offshore wind generation; 

  Storage 

o 

o 

o 

to adapt existing underground gas storage facilities, to make them suitable 
for hydrogen, pure or admixed with methane up to a certain threshold (e.g. 
10 vol%); 

to build new underground (admixed) hydrogen storage facilities; 

to  build  new  hydrogen  storage  facilities  in  cross-border  or  TSO-DSO 
connection  points  to  regulate  the  hydrogen  admixture  content  to  respect 
regulatory  limits,  technical  standards  and  the  tolerance  of  sensitive  end-
users; 

  Liquefied gas terminals 

o 

to  build  new  /  adapt  existing  LNG  terminals  to  make  them  suitable  for 
importing hydrogen (either renewable electricity based or fossil gas based 
via SMR with CCU/S); 

  Injection in gas networks 

o 

o 

build 

to 
injecting 
facilities 
transmission/distribution network; 

biomethane 

into 

the  methane 

to build terminals for injecting hydrogen into the transmission/distribution 
network; 

  Network interfacing 

o 

to  separate  hydrogen  from  methane  in  H2-admixed  methane  networks 
(deblending); 

  Hydrogen / methane production 

o 

o 

o 

o 

to  build  power-to-gas  installations  with  electrolysers  using  (renewable) 
electricity; 

to  build  new  methanation  facilities  for  the  conversion  of  hydrogen  into 
synthetic methane; 

to build new facilities for the production of methane by purifying biogas; 

to  build  new  facilities  for  the  production  of  hydrogen  by  gasification  of 
biomass; 

  Transversal projects 

o  To reduce methane emission in gas infrastructure (detailed below) 

  CCS/U 

27 

 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

o 

o 

to  capture,  transport,  store  and/or  utilize  carbon  (CCU/S)  from  the 
production of hydrogen through steam methane reforming; 

to  capture,  transport,  store  and/or  utilize  carbon  (CCU/S)  from  the 
upgrading of biogas into biomethane; 

  Secondary infrastructure 

o  To build infrastructure for utilization of methane / hydrogen in transport, in 
particular refuelling stations for compressed or liquefied methane / hydrogen 
(for the use in automotive, inland and maritime shipping). 

Methane emission reduction projects are transversal and may take place in any part of the 
methane  supply  chain  and  thus  all  infrastructure  components,  from  gas  production, 
liquefaction, regasification, storage, transmission & distribution, and secondary distribution 
(refuelling).  Methane  emissions  may  occur  due  to  fugitive  emissions  (in  the  various 
components  such  as  valves,  flanges,  connectors),  venting  (in  compressors,  due  to 
maintenance, failures or emergencies, and others) or incomplete combustion (e.g. in gas-
based  compressors  or  during  flaring).17  Methane  emissions  are  a  result  not  only  of  the 
specific  components  in  gas  infrastructures,  but  also  of  operation  practices  of  this 
infrastructure.  This  diversity  of  origins  for  methane  emissions  makes  it  diffuse  and  also 
complexifies its sustainability assessment. 

The projects in the long-list have been categorized according to the customized typology 
presented  in  Table  4-1  (with  a  short  project  name).  This  typology  of  projects  uses  the 
following parameters for categorization: 

  Facility type, that is, the main type of the project physical assets, i.e. 

  Main function of the project within the gas system; 

  Location of the project, either onshore or offshore; 

  Network  level  of  the  project,  namely  transmission  and/or  distribution,  or  the 

interface of the two levels; 

  Energy carriers at the entry and exit of the projects; 

  Asset type, whether the projects are new, adapted (slight modifications for  e.g. 
hydrogen  blending)  or  converted  for  the  entry/exit  of  a  new  energy  carrier  (e.g. 
from methane to hydrogen).

17 GIE and Marcogaz (2019) Potential ways the gas industry can contribute to the reduction of methane 
emissions. 

28 

 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Table 4-1 Individual gas-related infrastructure projects 

Short name 

Facility type 

Main function 

Location 

Network level 

Carrier - 
entry 

Carrier - 
exit 

Asset type 

Integrated network components  Transport 

Onshore 

Transm./dist. 

Hydrogen 

Hydrogen 

Converted 

Gas networks adaptation for H2 
admixture 

Gas networks adaptation for H2 
transport 

Reverse D-T methane compressors 

Reverse compression 

Transport 

Onshore 

Transm./dist. 
interface 

Integrated network components  Transport 

Onshore 

Transmission 

Natural gas 
+ hydrogen 

Natural gas 
+ hydrogen 

Adapted 

Natural gas  Natural gas  New 

Hydrogen injection 

Injection terminal 

Production 

Onshore 

Transm./dist. 

Hydrogen 

Natural gas 
+ hydrogen 

New 

Methane refuelling 

Hydrogen refuelling 

CNG terminal 

End-use supply 

Onshore 

Distribution 

Natural gas  Natural gas  New 

LNG supply facility 

End-use supply 

Onshore 

Distribution 

Hydrogen 

Hydrogen 

New 

LNG terminal adaptation to hydrogen  LNG terminal 

New liquefied hydrogen terminal 

LNG terminal 

Transport 

Transport 

Onshore 

Transmission 

Hydrogen 

Hydrogen 

Adapted 

Onshore 

Transmission 

Hydrogen 

Hydrogen 

Hydrogen from biomass gasification 

Biomass gasifier 

Production 

Onshore 

Distribution 

Biomass 

Hydrogen 

Biogas upgrading 

Biogas upgrader 

Conversion 

Onshore 

Transm./dist. 

Biogas 

Regulating hydrogen storage 

Storage 

Storage 

Onshore 

Transm./dist. 

Hydrogen 

Hydrogen methanation 

Methanation facility 

Conversion 

Onshore 

Transm./dist. 

Hydrogen 

Synthetic 
methane 

Natural gas 
+ hydrogen 

Synthetic 
methane 

Onshore hydrogen pipelines 

Integrated network components  Transport 

Onshore 

Transm./dist. 

Hydrogen 

Hydrogen 

Offshore hydrogen pipeline 

Integrated network components  Transport 

Offshore 

Transmission 

Hydrogen 

Hydrogen 

New 

New 

New 

New 

New 

New 

New 

Admixed hydrogen storage 

Hydrogen storage 

Metering 

Power-to-gas 

Biomethane injection 

Storage 

Storage 

Metering equipment 

Electrolyser 

Injection terminal 

Storage 

Onshore 

Transmission 

Natural gas 
+ hydrogen 

Natural gas 
+ hydrogen 

New/adapted 

Storage 

Transport 

Production 

Production 

Onshore 

Transmission 

Hydrogen 

Hydrogen 

New/converted 

Onshore 

Transm./dist. 

All gases 

All gases 

Onshore 

Transm./dist. 

Electricity 

Hydrogen 

New 

New 

Onshore 

Transm./dist. 

Biomethane  Biomethane  New 

Methane emission reduction 

Transversal 

Transversal 

Transversal   Transm./dist. 

Natural gas  Natural gas  New/adapted 

Hydrogen deblending 

Deblender 

End-use supply 

Onshore 

Transm./dist. 

Natural gas 
+ hydrogen 

Hydrogen 

New 

Note: integrated network components include pipelines, compressors, metering stations and other integrated components.

29 

 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

The individual gas-related infrastructure projects above may be combined to form coherent 
project clusters which serve a specific function within the gas system (e.g. the combination 
of projects to allow reverse flows from the distribution to the transmission grid and for the 
deblending  of  hydrogen  from  natural  gas  flows).  Frequently  gas-related  infrastructure 
projects will only be sensible (and hence potentially viable from an economic stand-point) 
if combined with others. Clusters  of gas-related infrastructure projects may also require 
conventional  infrastructure  projects  such  as  network  capacity  expansion  due  to  e.g. 
increased network demand at the transmission or distribution level. 

As discussed in the next section, the sustainability impact of certain projects will also be 
dependent  on  the  implementation  of  other  projects,  as  per  se  specific  gas-related 
infrastructure such as hydrogen storage is only able to reduce greenhouse gas emissions 
or increase the deployment of biomethane or hydrogen indirectly. 

Table 4-2 Illustrative project clusters identified 

Short cluster 
name 

Hydrogen 
electrolysis and 
injection 

Project 1 

Project 2 

Project 3 

Project 4 

Electrolyser 

Hydrogen 
pipeline(s) 

Hydrogen 
injection 
(blending) 
facility 

Biogas collection 
and upgrading  

Biogas 
production 

(biogas pipeline) 

(central) biogas 
upgrader 

Biomethane 
injection facility 

Liquid hydrogen 
refuelling 

Hydrogen 
pipeline 

Offshore 
hydrogen 
production 

Biogas 
methanation 
post-upgrading 

Offshore 
electrolyser 

Electrolyser 

Biogas production 
and reverse flow 

Biomethane 
production 

Hydrogen 
distribution 
network 

Hydrogen 
injection facility 

Hydrogen 
liquefaction 
facility 

Offshore 
hydrogen 
pipeline 

Biogas 
production 

Methane 
distribution 
pipeline(s) 

Hydrogen 
underground 
storage 

Hydrogen 
refuelling 
station 

Biogas CO2 
separation 

Hydrogen 
methanation 

Dist. transm. 
compressor 
station 

Hydrogen 
distribution 
pipeline(s) 

4.2.  Overall sustainability characteristics of the selected projects 

The  objective  of  this  section  is  to  present  an  overview  of  the  overall  sustainability 
characteristics  of  selected  gas-related  infrastructure  projects,  that  is,  the  project 
characteristics  which  may  potentially  contribute  (or  deter)  sustainability.  This  overview 
aims  at  providing  a  broader  perspective  than  the  sustainability  benefits  covered  in  the 
ENTSOG CBA 2.0, and even the proposed indicator of chapter 1. 

The sustainability characteristics assessed here indicate the potential contribution of each 
project  type,  rather  than  actual  sustainability  benefits,  which  will  vary  from  project  to 
project.  The  characteristics  of  specific  projects  (such  as  the  location  in  the  network)  or 
system  aspects  such  as  the  electricity  carbon  footprint  will  strongly  affect  the  exact 
sustainability characteristics of individual projects. 

4.2.1.  Structuring the sustainability analysis 

The analysis of the potential sustainability benefits focuses on the operational phase of the 
projects and applies the following methodology, summarized in the steps below: 

30 

 
 
 
 
 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

1.  Define  potential  sustainability  characteristics:  projects  may  contribute  to 
(climate)  sustainability  through  the  mitigation  of  greenhouse  gas  emissions  or 
through enabling the deployment of renewable energy (electricity or gas); 

2.  Define mechanisms  through  which projects  have a sustainability  impact: 
the  projects’  sustainability  contributions  may  occur  through  a  number  of 
mechanisms.  It  is  thus  necessary  to  identify  the  main  mechanisms  in  order  to 
provide the overview of the sustainability characteristics; 

3.  Assess  the  sustainability  impact  of  the  mechanisms  for  the  selected 
projects:  the  mechanisms  are  described  for  selected  gas-infrastructure  related 
projects, in order to assess their sustainability characteristics and mechanisms. 

Potential sustainability characteristics 
Sustainability impacts will depend on the horizon under consideration. In combination with 
the  selection  of  specific  scenarios,  the  horizon  will  affect  the  level  of  deployment  of 
renewable energy, the economy-wide and sector GHG emission reduction, and the level of 
gas  demand  in  the  EU  and  Member  States,  which  will  impact  the  sustainability 
characteristics  of  specific  projects.  The  potential  sustainability  contributions  of  the  gas-
related  infrastructure  surveyed  in  this  chapter  will  occur  only  in  certain  horizons  and 
scenarios.  

The potential sustainability contributions of the projects analysed here comprise the: 

  Reduction in emissions of greenhouse gases (CO2, methane, and other gases); 

  Reduction in emissions of local pollutants (NOx, SOx, particulate matter); 

  Facilitation of the integration of renewable electricity; 

  Facilitation of the integration of hydrogen and biomethane. 

Mechanisms of sustainability impacts 
The mechanisms through which these benefits may arise are indicated in Table 4-3. The 
potential  sustainability  benefits  of  the  selected  projects  may  arise  directly  from  the 
operation of the project (e.g. by reducing methane emissions or energy consumption of 
the facility) or indirectly from the investment and operation in other parts of the energy 
system.  

When effectively assessing the sustainability benefits of gas-related infrastructure projects, 
it is important to understand the various benefits and any overlaps which might exist, for 
example  between  the  reduction  of  greenhouse  gases  emissions  and  the  facilitation  of 
renewable energy deployment. Although any reduction in emissions should not be double 
counted, there is an argument for separately analysing how gas projects enable renewable 
energy, due to the specific EU renewable energy targets (complementary to the emissions 
reductions  target)  and  for  dynamic  efficiency  considerations,  as  the  deployment  of 
renewable energy technologies should lead to cost reductions which in turn will reduce the 
cost of the energy transition and thus the costs of future emission mitigation efforts. 

31 

 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Table 4-3 Main mechanisms affecting the sustainability characteristics of gas-related infrastructure projects 

CO2 
reduction 

CH4 
reduction 

Other GHG 
reduction 

Local 
pollutant 
reduction 

Renewable 
electricity 
integration 

Biomethane 
and 
hydrogen 
integration 

Substituting/ reducing natural gas consumption in transport / 
buildings / industry / power generation 

Substituting/ reducing coal consumption in transport / 
buildings / industry / power generation 

Substituting/reducing liquid fossil fuels consumption in 
transport / buildings / industry / power generation 

Reducing methane emissions in gas transmission/distribution 

Storing and/or utilizing CO2 

Enabling the deployment of renewable / decarbonized gases 
by increasing or adapting transport, conversion or storage 
capacity 

Increasing the flexibility of the energy system, thus 
facilitating RES-e deployment and/or reducing the need for 
fossil fuel-based dispatchable electricity generation capacity 





















































































32 

 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

4.2.2.  Sustainability characteristics summary 

Based  on  the  consideration  of  sustainability  aspects  summarised  in  this  chapter,  the 
sustainability  of  gas  infrastructure  projects  could  be  evaluated  to  cover  most  of  their 
sustainability  impacts.  Section  4.2.3  provides  a  detailed  discussion  of  the  sustainability 
characteristics, which are summarised here in tables 4-9 and 4-10. 

Summary of sustainability impact mechanisms per supply chain stage 
Table 4-4 summarizes the aspects that would need to be examined in order to assess the 
sustainability  impact  of  a  project.  It  covers  the  supply  chain  stages  (upstream, 
transport/storage  and  consumption),  as  well  as  the  three  categories  of  described 
sustainability impacts – substituting more carbon-intensive fuels usage (or reducing their 
consumption),  enabling  the  deployment  of  renewable  gases  and  enabling  the  uptake  of 
renewable electricity. 

The distinction per supply chain stages is mainly useful to analyse the sustainability impact 
of fuel substitution, to separate its emission impacts per stage. Assessing the impacts on 
renewable  gases  integration  and  renewable  electricity  production  separately  per  supply 
chain stage might pose a risk of double counting of benefits - for example energy storage 
might be beneficial from the perspective of avoiding RES-E curtailment, as well as enabling 
renewable  energy  consumption  in  time  of  insufficient  renewable  energy  supply  (even 
though  the  resulting  reduction  of  emissions  can  be  counted  only  once).  However,  this 
analysis  can  discover  additional  benefits,  such  as  the  fact  that  avoiding  curtailment  of 
renewable  electricity  sources  will  positively  influence  their  profitability,  making  further 
investments  in  the  sector  more  attractive.  Assessing  the  impacts  on  renewable  gases 
integration and renewable electricity production separately per supply chain stage might 
pose a risk of double counting of benefits - for example energy storage might be beneficial 
from the perspective of avoiding RES-E curtailment, as well as enabling renewable energy 
consumption  in  time  of  insufficient  renewable  energy  supply  (even  though  the  resulting 
reduction  of  emissions  can  be  counted  only  once).  However,  this  analysis  can  discover 
additional  benefits,  such  as  the  fact  that  avoiding  curtailment  of  renewable  electricity 
sources will positively influence their profitability, making further investments in the sector 
more attractive. 

Summary of sustainability impact due to due to fuel substitution, methane emission reduction 
and CCU/S 
The  sustainability  impacts  due  to  fuel  substitution  is  more  easily  quantifiable  than  the 
impacts  of  enabling  renewable  energy,  through  the  use  of  the  emission  factors  of  the 
substitute and substituted fuels. Methane emission reductions and CCU/S impacts can also 
be more readily quantified For the analysis of the sustainability impact of new infrastructure 
projects, a short list of gas-related infrastructure projects was selected from the long list 
based  on  their  likely  positive  sustainability  characteristics,  cross-border  relevance  and 
likely large-scale deployment in specific scenarios (e.g. scenarios with high hydrogen or 
biomethane development). 

The short-list of projects for the sustainability assessment comprise: 

  New or converted pure hydrogen onshore pipelines; 

  Onshore natural gas pipelines with hydrogen admixture 

  Pure hydrogen storage facilities; 

  Hydrogen electrolysis facilities; 

  Biomethane injection terminals; 

  Hydrogen methanation facilities 

  Methane emission reduction projects; 

33 

 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  Reverse distribution  transmission compressors. 

Table 4-5 presents the quantitative assessment of the impact due to the substitution (or 
consumption reduction) of fossil fuels of the selected gas-related infrastructure projects. 
The sustainability impact characteristics of projects due to the substitution of fossil fuels 
represent the maximum potential contribution of the projects to reducing GHG emissions, 
calculated as: 

𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛 𝑟𝑒𝑑𝑢𝑐𝑡𝑖𝑜𝑛 = 𝑒𝑚𝑖𝑠𝑠𝑖𝑜𝑛 𝑓𝑎𝑐𝑡𝑜𝑟(cid:3033)(cid:3042)(cid:3046)(cid:3046)(cid:3036)(cid:3039) (cid:3033)(cid:3048)(cid:3032)   − 𝑒𝑚𝑖𝑠𝑠𝑖𝑜𝑛 𝑓𝑎𝑐𝑡𝑜𝑟(cid:3029)(cid:3036)(cid:3042)(cid:3040)(cid:3032)(cid:3047)(cid:3035)(cid:3028)(cid:3041)(cid:3032)/(cid:3035)(cid:3052)(cid:3031)(cid:3045)(cid:3042)(cid:3034)(cid:3032)(cid:3041)  

The emission factor of fossil fuels is related to fuel combustion, whereas the emission factor 
of  substituting  fuels  is  related  to  emissions  in  the  “upstream”  production  phase,  as  the 
combustion  does  not  result  in  additional  GHG  emissions  (in  case  of  hydrogen),  or  has 
neutral GHG emission effect (in case of biomethane). Detailed calculation of these factors 
is presented in Annex B. 

Emissions in the upstream production of natural gas (or other fossil fuels) are not included 
for  as  the  available  data  lack  coherence  and  reliability.  These  could  improve  the 
sustainability characteristics of biomethane and hydrogen from electrolysis, while affecting 
that  of  hydrogen  from  SMR  or  coal  gasification  combined  with  CCS  either  negatively  or 
positively depending on specific system and project characteristics. 

Fossil fuel emission factors employ data by the IPCC, and biomethane emission factors are 
derived from the RED II.18 For example, the IPCC emission factor for natural gas is 56.15 
tCO2eq/TJ,  and  the  RED  II  emission  factor  for  biomethane  from  wet  manure  is  -100 
tCO2eq/TJ (with close digestate and off-gas combustion), leading to a emission reduction 
of 156.2 tCO2eq/TJ if natural gas is substituted for biomethane. 

The sustainability characteristics for reducing methane emissions in gas infrastructures are 
presented  as  the  maximum  reduction  possible  if  leakage,  venting  and  incomplete 
combustion  could  be  entirely  eliminated,  based  on  the  data  on  methane  emission 
reductions presented in the previous section.

18 IPCC Emission Factor Database. Available at https://www.ipcc-nggip.iges.or.jp/EFDB/find_ef.php 
Directive (EU) 2018/2001 on the promotion of the use of energy from renewable sources. 

34 

 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Table 4-4: Overview of sustainability impact mechanisms of gas-related infrastructure projects 

Upstream/Production 

Transport/storage 

Consumption 

Substituting/ 
reducing fossil 
fuel 
consumption 

  Emissions related to the energy required for the 

upstream process; 

  Emissions inherent to the upstream process 
(e.g. from chemical processes, flaring etc); 

  Emissions related to the fuel production process 

feedstocks: 

o  Can be negative, if CO2 feedstock is 

transformed in different chemical compound 

o  Can be neutral, if CO2 feedstock is equivalent 
to emissions released during fuel combustion 
o  Can be positive, if e.g. natural gas is used as 

feedstock 

CO2 storage or 
utilization 

  CO2 storage or utilization reduces the emission 

factor of the substitute fuel 

  Switching to gases with no greenhouse 

impact (e.g. hydrogen) reduces/eliminates 
emissions of e.g. CO2 or methane; 

  Alternative modes of transport to pipelines 

may cause additional emissions; 

  Distributed sources might require larger 

amounts of energy for transport. 

  Fuel switch has direct impact on end-

use GHG emissions; 

  Process switch accompanying fuel 
switch may increase efficiency of 
electricity production, waste heat 
recovery, energy end-use. 

Enabling 
biomethane 
and hydrogen 

  Biogas upgrading enables its injection in 

methane infrastructure; 

  Renewable gas production can employ 

renewable electricity which would be otherwise 
curtailed. 

  Gas infrastructure refurbishment/ 

conversion/ new investments enable the 
transport of admixed/pure hydrogen, 
directly or by eliminating network 
congestion/increasing overall transport 
capacity. 

  Distribution projects enable the end-
use of biomethane and hydrogen; 

  Specific projects may enable the 
end-use in hard-to-decarbonise / 
sensitive applications. 

  Facilitating renewable gases leads to learning effects and economies of scale across the supply chain. 

  Power-to-gas may reduce the curtailment of 

RES-E; 

  Power-to-gas may provide flexibility services to 

the electricity system. 

Enabling 
renewable 
electricity 

  Enable interlinked use of gas and 
renewable electricity (e.g. hybrid 
heating or transport) 

  Gas-infrastructure projects may increase the overall system flexibility through sector coupling, enabling RES-E integration and reducing 

flexibility needs from carbon-intensive providers 

35 

 
 
 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Table 4-5 Range of potential greenhouse gases emission reductions for selected project types 

Project 

Substituting / reducing 
natural gas use 

Substituting / reducing coal 
use 

Substituting / reducing 
liquid fossil fuels use 

Unit 

tCO2eq per TJ substituted (range or maximum) 

Reducing methane 
emissions 

tCO2eq/parameter 
(maximum) 

Storing and/or utilizing CO2 

tCO2eq/TJ of fuel 

Reducing greenhouse gases emissions 

  Electrolysis: 

  Electrolysis: 

  Electrolysis: 

o EU electricity mix: -72.2 
o RES: 56.2 

  SMR+CCS: 47.9 
  CG+CCS: 38.7 
  Methane pyrolysis: 38.4-

o EU electricity mix: -27 
o RES: 101.4 
  SMR+CCS: 93.1 
  CG+CCS: 83.9 
  Methane pyrolysis: 83.6-

o EU electricity mix: -54.1 
o RES: 74.3 
  SMR+CCS: 66 
  CG +CCS: 56.8 
  Methane pyrolysis: 56.5-

56.2 

101.4 

74.3 

  28 tCO2eq per tCH4 

substituted 

NA 

  -205.9 to 56.2 

  -160.7 to 101.4 

-187.8 to 74.3 

  -16.8 to 156.2 

  28.4 to 201.4  

  1.3 to 174.3 

New or converted pure 
hydrogen pipelines 

Pure hydrogen storage 
facilities 

Hydrogen electrolysis 
facilities 

Pipelines with hydrogen 
admixture 

Hydrogen methanation 
facility 

Biomethane injection 
terminals 

Reverse D->T methane 
compressors 

  10 tCO2eq/TJ  
(if coupled with biogas 
upgrade) 

NA 

No methane emission 
reductions 

  Transm. pipelines: 5.0 

tCO2eq/km. 
  Compressor:  

146.8 tCO2eq/MW 

  Pressure Regulating and 

Reduction stations: 
294.8 tCO2eq/station 

  Dist. mains:  

37.9 tCO2eq/km 

Methane emission reduction 
projects 

NA 

Notes: Positive values denote an emission reduction. Coal is equivalent here to lignite, and liquid fossil fuels to gasoline / diesel. 
NA: not applicable; CCS: Carbon capture and storage, CG: Coal gasification, SMR: Steam Methane Reforming.

36 

 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

4.2.3.  Detailed analysis of sustainability characteristics 

Substituting/reducing fossil fuel consumption  

One of the most direct paths for reducing greenhouse gas emissions is to switch from fossil 
fuels such as coal, gasoline or diesel to less  emission-intensive energy carriers, such as 
natural  gas,  hydrogen  or  biomethane.  Gas  infrastructure  projects  can  contribute  to  this 
fuel switch in various ways, in particular: 

  By building or upgrading projects that serve to substitute or reduce fossil fuel usage 
in  a  particular  end-use  sector  (for  example  converting  methane  distribution 
networks  to  hydrogen,  or  building  hydrogen  refuelling  stations  for  transport 
applications); 

  By  contributing  to  the  development  of  gas  markets,  and  thus  enabling  greater 
market  participation  and  increasing  the  market  efficiency,  resulting  in  increased 
competitiveness  of  methane  gases  or  hydrogen  against  more  emission-intensive 
fuel alternatives; 

  By supplying new consumers in areas with no or inadequate gas supply which force 
consumers  to  choose  other  more  emission-intensive  or  less  efficient  fuel 
alternatives; 

  By enabling the provision of flexibility resources to the energy system which allow 
the increased integration of intermittent renewable energy sources or which reduce 
the  need  for  flexibility  resources  using  fossil  fuels  (elaborated  in  more  detail  in 
following sections). 

However,  since  most  of  these  effects  bring  an  indirect  contribution  to  the  emissions 
reductions  and  act  more  as  an  enabler  for  the  actual  fuel  switches  taking  place  in 
intermediary and end-use applications, it is difficult to estimate their contribution ex-ante. 
Since  energy  supply  and  demand  is  subject  to  market  forces,  the  impact  of  any 
infrastructure  project  will  thus  be  influenced  by  external  factors  such  as  energy  and 
technology prices and availability, as well as the carbon price. 

For  the  same  reason  it  is  possible  that  a  new  gas  infrastructure  project  might  even 
contribute  to  increasing  the  emission  of  greenhouse  gases.  More  competitive  energy 
markets might lead to lower energy prices and thus increase the energy demand, resulting 
in more fossil fuels consumed (the rebound effect). Developing new infrastructure projects 
might  also  lock  in  the  economy  on  certain  energy  pathways  and  limit  (crowd-out)  the 
amount  of  resources  available  for  investment  in  assets  with  greater  emission  reduction 
potential (such as energy efficiency or renewable energy sources). 

In  particular  the  infrastructure  enabling  the  integration  of  biomethane  might  have  a 
significantly different sustainability impact depending on the  origin of the feedstock and 
the process used for the production of biogas. Apart from the different emissions factors 
of  different  biomass  feedstock  used,  a  significant  determinant  of  emissions  to  be 
considered is the potential land use change resulting from increased demand for biomass.  

Another  major  pathway  of  emission  reduction  is  increasing  the  efficiencies  in  energy 
production and end-use, which will directly result in lower consumption and thus emissions, 
as well as lower leakages and other emissions occurring along the fossil fuel supply chain. 
As an example of the effect the switch to a more efficient process can have, the Energy 
Efficiency  Directive  (EU)  2012/27  indicates  that  the  default  power-to-heat  ratio  of 
combined cycle gas turbines with heat recovery is 95%, against e.g. 55% for simple gas 
turbines with heat recovery. 

37 

 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

The  avoided  emissions  due  to  the  realization  of  a  gas  infrastructure  project  can  be 
estimated on the basis of fossil fuel emission factors and the estimate of the amount of 
avoided fossil fuel energy production. The emission factors due to the combustion of fossil 
fuels  for  the  main greenhouse gases (CO2,  CH4  and  N2O)  are  summarized  in  Table  4-6. 
Alternatives to fossil fuels such as biomethane, or renewable or low-carbon hydrogen, have 
the  potential  for  achieving  lower  emissions,  but  as  mentioned  this  will  depend  on  the 
biomass/electricity sources as well as the production process.  The net emissions factors 
for  the  production  of  hydrogen  and  biomethane  using  various  energy  sources  and 
processes are summarized in Table 4-7, based on current technology and inputs. 

For  the  purpose  of  comparison,  an  emission  factor  of  hydrogen  produced  via  water 
electrolysis using the 2017 EU27 electricity mix was included as well. This value is notably 
higher  than  the  emission  factors  of  fossil  fuels  combustion,  largely  due  to  high  energy 
losses of water electrolysis. It can be however presumed that the emission factor of the 
EU  electricity  mix  will  decrease  in  the  future  and  that  the  electrolysis  efficiency  will 
increase. Thus, this emission factor can be regarded as a maximum. It must be noted that 
while the  emission  factors from  the  combustion  of  fossil  fuels depend  on  their  chemical 
properties and will not change significantly in the future, there is still potential to reduce 
the net emissions resulting from the production of biomethane and hydrogen (as well as 
upstream emissions in the fossil fuel supply chain). 

For hydrogen methanation facilities, the emission factor of production has been calculated 
as 0 – 262.1 tCO2/TJ, depending on the carbon footprint of the hydrogen production inputs 
(0  tCO2/TJ  for  electrolysis  using  renewable  electricity,  262.1  tCO2/TJ  using  2017  EU27 
electricity generation mix). This value was derived from the assumptions used by IEA in 
the Future of Hydrogen19 project, taking into account the efficiency of methanation process 
and related own consumption of electricity. Additional emissions might arise in relation to 
the feedstock CO2 extraction – using CO2 arising from the upgrading of biogas would for 
example  not  require  additional  energy  input,  whereas  direct  air  capture  would  require 
additional electricity consumption that cannot be covered by e.g. using surplus heat from 
the methanation reaction20. These additional emissions are thus very variable and hard to 
quantify, and since their relative impact in comparison to the emissions related to hydrogen 
production is negligible, they are not taken into account. 

19 IEA (2019), IEA G20 Hydrogen report: Assumptions. Available at: 
https://iea.blob.core.windows.net/assets/a02a0c80-77b2-462e-a9d5-1099e0e572ce/IEA-The-Future-of-
Hydrogen-Assumptions-Annex.pdf 
20 Meylan et al (2017). Power-to-gas through CO2 methanation: Assessment of the carbon balance regarding EU 
directives. In: Journal of Energy Storage 11 (2017). Available at: https://doi.org/10.1016/j.est.2016.12.005. 

38 

 
 
                                                 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Table 4-6: GHG emissions from combustion of fossil fuels21 

Fuel 

tCO2/TJ  kgCH4/TJ  kgN2O/TJ 

tCO2eq/TJ 

Gaseous Fossil Fuels 

Natural gas 
Refinery gas 

Liquefied Petroleum Gases 
Blast furnace gas 
Coke oven gas 

56.1 
57.6 

63.1 
260.0 
44.4 

Liquid Fossil Fuels 

1 
1 

1 
1 
1 

3 
3 

3 
3 
3 
3 
3 
3 

3 
3 

1 
3 
1 

1 
1 
1 
10 
1 
3 

1 

74.1 
73.3 

73.3 
69.3 
70.0 
71.5 
73.3 
73.3 

77.4 
71.9 

Solid Fossil Fuels 

98.3 
80.7 
101.0 

94.6 
96.1 
97.5 
106.0 
94.6 
97.5 

107.0 

0.1 
0.1 

0.1 
0.1 
0.1 

0.6 
0.6 

0.6 
0.6 
0.6 
0.6 
0.6 
0.6 

0.6 
0.6 

1.5 
0.6 
1.5 

1.5 
1.5 
1.5 
1.4 
1.5 
0.6 

1.5 

56.2 
57.7 

63.2 
260.0 
44.5 

74.3 
73.5 

73.5 
69.5 
70.2 
71.7 
73.5 
73.5 

77.6 
72.1 

98.7 
80.9 
101.4 

95.0 
96.5 
97.9 
106.7 
95.0 
97.7 

107.4 

Gas/Diesel oil 
Crude oil 

Refinery feedstocks 
Motor gasoline 
Aviation/jet gasoline 
Jet kerosene 
Naphtha 
Shale oil 

Residual fuel oil / HFO 
Other kerosene 

Anthracite 
Bitumen 
Lignite 

Other bituminous coal 
Sub bituminous coal 
Brown coal briquettes 
Peat 
Coking coal 
Petroleum coke 

Coke oven coke 

Source: EIB (2018)22 

21 With a 100-year global warming potential for methane of 28 and for nitrous oxide of 265. TJ in lower heating 
values where applicable (i.e. net calorific content). 
See IPPC (2013) Fifth Assessment Report. Chapter 8 - Anthropogenic and Natural Radiative Forcing. 

22 EIB (2018). Methodologies for the Assessment of Project GHG Emissions and Emission Variations. Available 
at: https://www.eib.org/attachments/strategies/eib_project_carbon_footprint_methodologies_en.pdf 

39 

 
 
                                                 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Table 4-7 GHG emissions from hydrogen production, hydrogen methanation and 
biomethane production 

Fuel and process 

tCO2eq/TJLHV 

tCO2/TJLHV 

Hydrogen production 

Water electrolysis using renewable electricity a 
Water electrolysis using 2017 EU27 electricity 
mix23 
Natural gas reforming a 
Natural gas reforming with carbon capture a 
Coal gasification a 
Coal gasification with carbon capture a 
Biomass gasification (corn stover) b,24 
Methane pyrolysis using natural gas as process 
fuel d 
Methane pyrolysis using 30%-35% of output 
hydrogen as process fuel d 
Methane pyrolysis using 2017 EU27 electricity mix 
as process fuel e 

using renewable electricity as process fuel 
using 2017 EU27 electricity mix as process fuel 

Hydrogen methanation 

0 

NA 

74.2 
8.3 
168.4 

17.5 
16.8 

NA 

NA 

NA 

NA 
NA 

0 

128.4 

74.2 
8.3 
168.4 

17.5 
16.7 

9.2  

0 

17.8 

0 
262.1 

23 Based on emission factor of 295.74 g/kWhe and electrolysis efficiency of 64%.  
See: EEA (2020), CO2 Intensity of Electricity Generation. Available at: https://www.eea.europa.eu/data-and-
maps/data/co2-intensity-of-electricity-generation. and IEA (2019), IEA G20 Hydrogen report: Assumptions. 
Available at: https://iea.blob.core.windows.net/assets/a02a0c80-77b2-462e-a9d5-1099e0e572ce/IEA-The-
Future-of-Hydrogen-Assumptions-Annex.pdf 
24 CH4 emissions of 0.19 kgCH4/TJ and N2O emissions of 0.19 kgN2O/TJ 

40 

 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Fuel and process 

tCO2eq/TJLHV 

tCO2/TJLHV 

Biomethane production c 

Feedstock  Digestate  Off-gas combustion 

Wet 
manure 

Maize 
whole plant 

Biowaste 

Open 

Close 

Open 

Close 

Open 

Close 

None 
Yes 
None 
Yes 
None 

Yes 
None 
Yes 
None 
Yes 
None 

Yes 

tCO2/TJLHV 

tCO2eq/TJLHV 
22 
1 
-79 
-100 
73 

52 
51 
30 
71 
50 
35 

14 

Sources: a: adapted from IEA (2019)25; b: adapted from E4tech (2018)26; c: adapted from 
Directive  (EU)  2018/200127;  d:  adapted  from  Parkinson  et  al  (2019)28;  e:  based  on 
Machhammer et  al (2016)29. Negative  emissions are due to the  manure credits. For the 
breakdown of emissions by biogas production steps see Annex A. 

25 IEA (2019), IEA G20 Hydrogen report: Assumptions. Available at: 
https://iea.blob.core.windows.net/assets/a02a0c80-77b2-462e-a9d5-1099e0e572ce/IEA-The-Future-of-
Hydrogen-Assumptions-Annex.pdf 
26 E4tech (2018), H2 Emission Potential Literature Review. Available at: 
https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/798243/H2
_Emission_Potential_Report_BEIS_E4tech.pdf  
27 European Commission (2018), Directive (EU) 2018/2001 of the European Parliament and of the Council on 
the promotion and use of energy from renewable sources. Available at: https://eur-lex.europa.eu/legal-
content/EN/TXT/PDF/?uri=CELEX:32018L2001&from=EN 
28 Parkinson et al (2019), Levelized cost of CO2 mitigation from hydrogen production routes. In: Energy & 
Environmental Science 1/2019. Available at https://doi.org/10.1039/C8EE02079E. 

29 Machhammer et al (2016), Financial and Ecological Evaluation of Hydrogen Production Processes on Large 
Scale. In: Chemical Engineering & Technology 6/2016. Available at: https://doi.org/10.1002/ceat.201600023. 
41 

 
 
 
                                                 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Box 4-1 Emission of air pollutants due to fuel combustion 

Although  the  TEN-E  Regulation  is  focused  on  climate  sustainability,  the  specific 
sustainability criteria for gas projects set in article 4(2b) broadly refer to emissions, 
which may also include air pollutants such as particulate matter (PM), nitrous oxides 
(NOx) and sulphur dioxide (SO2). Moreover, the methodology for the energy system-
wide cost-benefit analysis of Annex V of the Regulation indicates that the ‘common 
electricity  and  gas  market  and  network  model’  should  allow  for  the  assessment  of 
external costs such as ‘conventional air pollutant emissions’. 

The substitution of coal or liquid fossil fuels (e.g. gasoline or diesel) by natural gas 
would bring the most significant benefits in the reduction of air pollutant emissions. 
Analysis of data from the fuel use and air pollutants emissions of large combustion 
plants  in  Europe  indicates  that  natural  gas  presents  the  lowest  emission  factor  for 
total  suspended  particles,  NOx  and  SO2,  as  indicated  below.  Moreover,  the  implied 
pollutants  emission  factor  from  the  combustion  of  fossil  fuels  has  generally  been 
falling continuously since 2007.30 

Direct  combustion  of  biogas  has  been  more  frequently  studied.31  However,  less 
attention has been given to the biomethane combustion and eventual differences to 
natural  gas  in  the  emission  of  air  pollutants.  The  air  pollutant  impact  of  hydrogen 
combustion (or oxidization in a fuel cell) is regarded as much more limited. 

The emissions of air pollutants from transport have fallen significantly in the 30 years 
in the EU but this decrease has decelerated significantly in the last few years, with 
SOx  emissions  even  increasing  from  2016 to 2017.32  Natural  gas, biomethane and 
hydrogen  use  in  transport  can  contribute  further  to  the  reduction  of  emission  of 
pollutants  from  transport.33  Section  2.3  further  discusses  of  the  use  of  emission 
factors for air pollutant (and the caveats). 

Implied emission factors for large combustion plants, 2017 

t/TJ 

Natural gas 
Liquid fuels 
Solid fuels 

Total 
suspended 
particles 

NOx 

SO2 

0.000  0.029  0.000 
0.008  0.268  0.188 
0.005  0.082  0.090 

Reducing methane emissions in gas transmission/distribution34 

Methane emissions from natural gas operations within the EU amounted to slightly under 
30  MtCO2eq,  equivalent  to  6%  of  the  total  EU  methane  emissions,  or  0.6%  of  total  EU 

30 EEA (2017) Evolution of the environmental performance of large combustion plants in the EU-28, expressed 
as implied emission factors for sulphur dioxide, nitrogen oxide and dust, by fuel type. 
31 See for example Paolini et al. (2018) Environmental impact of biogas: A short review of current knowledge. 
Journal of Environmental Science and Health, Part A, 53(10), and the DG Energy study ‘Study on energy costs, 
taxes and the impact of government interventions on investments in the energy sector’.  
32 EEA (2019) Emissions of air pollutants from transport - TERM 003. 
33 US Department of Energy (2019) Alternative Fuels Data Center. See 
https://afdc.energy.gov/vehicles/natural_gas_emissions.html 
https://afdc.energy.gov/fuels/hydrogen_benefits.html 

34 This section, unless specified, is based on GIE and Marcogaz (2019) Potential ways the gas industry can 
contribute to the reduction of methane emissions. 

42 

 
 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

greenhouse  gas  emissions  in  2016.35  The  IEA  on  its  turn  has  estimated  European36 
methane emissions from downstream gas operations (including refining) at 1.317 MtCH4 
in 2017, or 32.9 MtCO2eq, comparable to the GIE and Marcogaz estimations.37 The first EU 
strategy for reducing methane emission was published in 1996, and the EU is working on 
a 2nd strategy as required in the EU Governance Regulation,38 for publication in 2020. 

EU methane emissions in gas operations arose from production (16%), processing (2%), 
transmission  and  storage  (23%)  and  distribution  (59%).  Therefore,  although  methane 
emissions  are  spread  across  the  entire  gas  chain,  gas  transmission,  storage  and 
distribution was responsible for 82% of the EU methane gas operation-related emissions 
in that year. However, data must be considered with care due to the data gaps and quality. 
Complementary  data  from  Marcogaz  indicates  that  emissions  from  LNG  terminals,  gas 
storage, transmission and distribution amounted to 14.4 MtCO2eq in 2015. 

Gas methane emissions may be categorized as fugitive, due to venting or due to incomplete 
combustion. Table 4-8 presents the categorization used by GIE and Marcogaz to identify 
the  components  responsible  for  methane  emissions  arising  from  the  gas  supply  chain 
directly  related  to  the  gas  infrastructure  projects  addressed  in  this  chapter:  gas 
regasification,  transmission,  storage,  distribution  as  well  as  biomethane  and  biogas 
production. 

Table 4-8 Categories for identification of methane emissions across the gas 
chain 

Categories of methane emissions 

Fugitives 

Venting 

Incomplete 
combustion 

Biomethane/ 
biogas production 

Open digestate 
storage; Separator; 
Storage of solid 
fraction; Biofilter; 
Valves 

Flaring Closed 
digestate storage; 
Reactor Maintenance 

Flaring; CHP 

s
k
n

i
l

n
i
a
h
c

s
a
G

Transmission & 
storage39 

Components (valves, 
flanges, connectors, 
etc.) 

Regasification  

Components (valves, 
flanges, connectors, 
etc.) 

Distribution 

Components (valves, 
flanges, connectors, 
etc.); Permeability of 
materials 

Compressors; 
Maintenance; 
Failure/Emergency; 
Pneumatic 
controllers; Devices 
for on-line gas quality 
sampling 

Stationary 
combustion devices 
(e.g. engines, 
boilers) ; 
Engines/Turbines for 
gas compression ; 
Flaring 

Flaring; Vessels and 
truck loading; Vessels 
unloading; 
Maintenance; 
Failure/Emergency; 
Pneumatic controllers 

Stationary 
combustion devices 
(e.g. engines, 
boilers); Vaporisers; 
Flaring 

Maintenance; 
Failure/Emergency; 
Operational 

Stationary 
combustion devices 
(e.g. boilers) 

Source: GIE and Marcogaz (2019) Potential ways the gas industry can contribute to the 
reduction of methane emissions. 

35 Calculated using a 100-year global warming potential. 
36 Including non-EU countries 

37 IEA (2020) Methane tracker. Available at https://www.iea.org/reports/methane-tracker/country-and-
regional-estimates 
38 Regulation 2018/1999 on the Governance of the Energy Union and Climate Action 

39 Only above ground installations. Includes compressor stations, regulation and measurement stations, 
pipelines, underground storage. 

43 

 
 
 
 
 
 
 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Marcogaz  published  specific  studies  identifying  the  origin  of  emissions  in  the  various 
sections of the gas infrastructure using 2015 data. Fugitive emissions are identified as the 
main emission source for LNG terminals (83% of emissions) and for underground storage 
(57%).  For  transmission,  fugitive  and  venting  emissions  are  responsible  for  40%  each, 
followed by pneumatic gas use (20%). At the distribution level, steel pipes are responsible 
for  50%  of  total  methane  emissions,  followed  cast  iron  (23%)  and  polyethylene  pipes 
(17%). 

The Marcogaz calculated methane emissions scaled per the transmission network length 
was 0.57 tCH4/km. The emissions for the distribution level depend on the pipe material, 
varying from 1.39 tCH4/km for cast iron mains to 0.20 tCH4/km for steel and 0.03 tCH4/km 
for  PVC.  These  and  further  emissions  scaled  per  pipeline  length,  compressor  power  or 
number of pressure regulating and reduction stations are presented in Table 4-9. 

Table 4-9 GHG emissions from gas networks 

Infrastructure type 

Source 

Scaling 

tCH4 

tCO2 

tCO2eq 

Aggregated gas network 
emissions 

Pipelines 

Compressors 

Pressure regulating and 
reduction stations 

Pipelines (CH4 leaks) 

Pipelines (CO2 oxidation) 

Cast iron pipeline 

Steel pipeline 

Polyethylene pipeline 

PVC pipeline 

Transmission 

Marcogaz 

Per km 

Per MW 

0.57 

0.18 

5.24 

Per station 

10.53 

API 

Per km 

Distribution 

Marcogaz 

Per km 

15.9 

5.0 

146.8 

294.8 

62.58 

0.13 

38.9 

5.5 

1.7 

0.8 

28.1 

0.41 

- 

- 

- 

- 

0.13 

- 

- 

- 

- 

- 

0.41 

2.24 

- 

1.39 

0.20 

0.06 

0.03 

1.00 

- 

Pipelines (CH4 leaks) 

Pipelines (CO2 oxidation) 

API 

Source:  Marcogaz  (2018),  API  (2009)  in  EIB  (2018)40.  Marcogaz  data  refers  to  Europe, 
while API data is based on US and other data. 

Methane emissions are not covered under the Emission Trading System (ETS), but are part 
of  the  Effort  Sharing  Decision  (ESD).  The  ESD  covers  the  sectors  outside  of  the  ETS, 
including gas transport, which is not within the ETS scope. The current target for emissions 
reduction in the ESD is 30% by 2030, compared with 2005 levels. 

Mitigation  measures  to  address  the  identified  methane  emissions  vary  according  to  the 
emitting source. Fugitive emissions on the one hand are addressed by leak detection and 
repair  (LDAR).  Venting  and  incomplete  combustion  emissions  on  the  other  hand  are 
addressed  through  the  use  of  best  available  techniques  (BAT)  for  the  various gas  chain 
elements  and  processes.  It  must  also  be  noted  that  besides  emission  identification  and 
mitigation, a number of improvements should be made in the quantification and reporting 
of  these  emissions,  as  well  as  in  the  validation  of  methane  emission  reductions  due  to 
mitigation measures. 

40 Marcogaz (2018) Survey Methane Emissions for Gas Transmission in Europe. WG-ME-17-09. 
Marcogaz (2018) Survey Methane Emissions for Gas Distribution in Europe. WG-ME-17-25. 
API (2009) Compendium of Greenhouse Gas Emissions Methodologies for the oil and natural gas industry. 

44 

 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

The IEA has in 2017 estimated the methane emission abatement potential for the European 
downstream gas supply chain, already mentioned in sec.41 Available measures applicable 
to gas infrastructures are presented section 2.2.1, and are recapped in Table 4-10 along 
with their estimated abatement potential and cost. 

Table 4-10 Estimated EU gas supply chain abatement potential and weighed 
abatement cost in 2017 

Estimated abatement 
potential (ktCH4) 

Weighed abatement 
cost (EUR/TJ)42 

Blowdown capture 

Downstream LDAR 

Install flares 

Replace compressor seal or rod 

Replace with instrument air 
systems 

Vapour recovery units 

23.3 

831.1 

0.2 

59.5 

4.1 

1.3 

-4.13 

2.14 

1.48 

-0.33 

-4.23 

2.20 

Note: The downstream gas supply chain data includes refining. 
Source: IEA (2020) Methane tracker.  

Considerations on upstream emissions for natural gas imports 

Next  to  emission  of  greenhouse  gases  in  the  European  transmission  and  distribution 
infrastructure  and  upstream  activities,  the  emissions  arising  from  upstream  activities 
outside of the EU could be considered as well, since a substantial part of the EU natural 
gas demand is covered by imports from third countries. Not only are these emissions not 
considered in the existing EU regulatory framework, but the actual emissions arising from 
natural gas extraction and supply might vary across the exporting countries due to different 
technology performance and practices as well as environmental protection standards. 

Depending on the production location and method, the upstream methane emissions might 
range  from  0.2%  to  10%  of  the  produced  natural  gas.  The  majority  of  estimates  are 
however located within the range of 0.5% to 3%43. If the CO2 emissions in the supply chain 
are taken into account as well, the total GHG emissions range from 3 to 36.4 tCO2eq/TJ44, 
which equals to 5% - 65% of the  GHG  emission from the combustion of a TJ of natural 
gas.  The  GHG  emission  estimates  for  the  European  natural  gas  production  are  lower, 
ranging between 2.3 - 15.3 tCO2eq/TJ45 (due to, among others, shorter transport routes). 
Also, the LNG supply chain has a greater emission impact than gas pipeline supply46. 

Although the  emissions connected  to  the  supply  chain  can potentially have  a  significant 
effect on the overall environmental performance of natural gas, the literature suggest that 
a major part of these emissions is connected to only a small number of facilities. Therefore, 
the emission reduction efforts can be more focused and therefore more effective. Among 

41 IEA (2020) Methane tracker. Available at https://www.iea.org/reports/methane-tracker/country-and-
regional-estimates 

42 Using a 2019 exchange rate of 1.1195 USD/EUR 
43 Sustainable Gas Institute (2015). Methane and CO2 Emissions from the Natural Gas Supply Chain. Available 
at https://www.sustainablegasinstitute.org/wp-content/uploads/2015/09/SGI_White_Paper_methane-and-CO2-
emissions_WEB-FINAL.pdf?noredirect=1. 
44 Ibid (note that the values were converted to high heating values) 
45 E4tech (2018). H2 Emission Potential Literature Review. Study commissioned by the Department for Business 
Energy and Industrial Strategy (BEIS). Available at 
https://assets.publishing.service.gov.uk/government/uploads/system/uploads/attachment_data/file/798243/H2
_Emission_Potential_Report_BEIS_E4tech.pdf 
46 Stern (2019). Challenges to the Future of LNG: decarbonisation, affordability and profitability. 

45 

 
 
 
                                                 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

the  identified  key  “super  emitters”  are  for  example  well-completing  activities,  liquids 
unloading  (removal  of  liquids  in  well),  and  leaking  pipework,  pneumatic  devices  and 
compressors47. 

Further reasoning for how to best address this extra-EU methane emissions is presented 
in sections 2.3 and 5.2. 

Storing and/or utilizing CO2 

Gas-related infrastructure projects are not an essential part of carbon capture, storage and 
utilization projects (CCU/S), but may indirectly enable such projects. As such, gas-related 
 from fossil or biological 
infrastructure may indirectly lead to the storage or utilization of CO2
origin, and thus have a positive sustainability impact. 

The  influence  of  gas-related  infrastructure  occurs  because  CCU/S  technology  can  be 
combined with a number of gas production technologies, with the following being the focus 
of this section: 

  Biogas upgrading + CCS; 

  Hydrogen from methane reforming + CCU/S; 

  Hydrogen from coal gasification + CCU/S; 

  Biogas methanation with hydrogen. 

The impact on final CO2 emissions will depend on the source of carbon (fossil, biological, 
from  air  capture)  and the  carbon  capture  rate.  On  the  one  hand, the  capture  of  carbon 
originating  from  the  combustion or  gasification of  coal,  natural  gas  or  oil may  lead to  a 
strong  reduction  of  emissions,  although  the  final  emission  factor  of  the  combined  gas 
production and carbon CCU/S project will still be positive as technologies are not able to 
capture  all  carbon  emissions.  On  the  other  hand,  the  capture  of  carbon  from  biological 
origin (such as from the upgrading of biogas to biomethane) or from  air would allow to 
achieve net negative emissions. 

Biogas upgrading + CCS is a particular combination of bioenergy and CCS (BECCS), a lead 
candidate to achieving negative emissions, if the stored CO2  emissions are greater than 
those arising from biomass production, transport, conversion and utilization. Although the 
individual technologies for upgrading biogas and capturing CO2 are  mostly mature (with 
the exception of biomass gasification), only one out of 18 BECCS plants worldwide produce 
biogas  (the  Biorecro/EERC  project  in  the  US).  Moreover,  an  important  constraint  to  the 
large-scale development of BECCS in general is the availability of sustainable biomass.48 

CCS may be combined with hydrogen production from either natural gas through methane 
reforming (either steam methane reforming, SMR, or autothermal reforming, ATR) or from 
coal gasification. DNV GL estimates the emission factor of hydrogen production from SMR 
+ CCS at around 1.2 kgCO2eq/kgH2, and for hydrogen produced from coal gasification + 
CCS  at  1.3  kgCO2eq/kgH2.  With  a  carbon  capture  efficiency  of  87%  for  SMR  +  CCS, 
hydrogen production from electrolysis would have to use electricity with a carbon footprint 
of  75  kgCO2eq/MWh  or  lower  to  have  a  lower  emission  impact.  Thus,  only  hydrogen 
produced from hydrolysis with electricity from predominantly renewable or nuclear sources 
would have a lower emission impact. CE Delft estimates the emission factor of hydrogen 
production from SMR + CCS at 1.62 tCO2eq/tH2. All estimates are presented in Figure 4-1 
(with year of estimate when available, and with the carbon footprint of the natural gas or 

47 Sustainable Gas Institute (2015). Methane and CO2 Emissions from the Natural Gas Supply Chain. Available 
at https://www.sustainablegasinstitute.org/wp-content/uploads/2015/09/SGI_White_Paper_methane-and-CO2-
emissions_WEB-FINAL.pdf?noredirect=1. 

48 Global CCS Institute (2019) Bioenergy and Carbon Capture and Storage 

46 

 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

coal  supply  not  shown  for  comparability).  Here,  differences  on  emissions  between  the 
Netherlands and Norway are caused by the cleaner electricity carbon footprint in the latter. 

Figure 4-1 Greenhouse gas emissions in hydrogen production due to process 
emissions and electricity input carbon footprint 

25

20

15

10

5

0

V
H
L
J
T
/
q
e
2
O
C

t

2015

2030

2019

2030

2015

2030

2015

2030

2019

2030

2018

NL

NO

NL

NO

NO

CE Delft

IEA

DNV GL

SMR + CCS

CE Delft

ATR + CCS

CE Delft

Electrolysis

IEA

DNV GL

Coal gasification + CCS

Source: CE Delft (2018), DNV GL (2018), IEA (2019)49 

The production of biogas and hydrogen offers an additional synergy if the CO2 present in 
biogas is used in the methanation of renewable hydrogen. Methanation can be direct, with 
hydrogen mixed with the biogas, or  occur after the biogas upgrading (separation of the 
biomethane  and  the  CO2).  Methanation  can  be  biological  (using  microorganisms  called 
archea)  or  catalytic.  Biogas  methanation  with  hydrogen  can  achieve  negative  emission 
factors  depending  on  the  emissions  in  the  biogas  supply  chain  and  the  footprint  of  the 
electricity used in the hydrogen production. 

Different biogas methanation projects in Germany and Denmark in 2017 exhibited a CO2 
content  going  from  trace  amounts  up  to  6%  CO2.50  Moreover,  in  2019  as  part  of  the 
STORE&GO  project  a  methanation  plant  opened  in  Germany  using  CO2  from  bioethanol 
production, which is subsequently injected in the gas grid.51 Collet et al. indicate that the 
emission  factor  for  this  biogas  methanization  could  decrease  to  around  13  tCO2eq/TJ  in 
France  (excluding  the  electricity  carbon  footprint).  This  indicates  there  could  be  an 
additional reduction in emissions of over 10 tCO2eq/TJ compared to the simple upgrading 
of biogas, if the CO2 could be utilised for methanation of hydrogen produced exclusively 
with renewable electricity.52 However, further analysis of the impact of biogas methanation 
is necessary. 

Enabling  the  deployment  of  biomethane  and  hydrogen  by  increasing  or 
adapting transport, conversion or storage capacity 

Gas-related  infrastructures  can  increase  the  deployment  of  biomethane  and  hydrogen 
either directly or indirectly. Directly, some gas-related infrastructures may be themselves 
responsible for the production of biomethane or hydrogen, such as hydrogen electrolysers, 
or be responsible for the connection of gas production projects to the network and injection 
of  the  gases.  Indirectly,  the  capacity  to  deploy  and  connect  biomethane  or  hydrogen 
projects to the network may increase with gas transport, conversion or storage projects. 

Gas-related  infrastructures  thus  may  first  themselves  enable  the  connection  of 
renewable/decarbonized gas projects, either through the development of connectors 
and/or  injection  terminals  (possibly  collecting  gases  from  multiple  producers)  for  gas 
production projects. Here, the infrastructure projects are responsible for the full increase 
in deployment of renewable / decarbonized gases.  

49 CE Delft (2018) Feasibility study into blue hydrogen; DNV GL (2018) Hydrogen as an energy carrier; IEA 
(2019) The Future of Hydrogen. 
50 PlanEnergi (2017) FutureGas – D1.1.1 - Upgrading of Biogas to Biomethane with the Addition of Hydrogen 
from Electrolysis 
51 STORE&GO (2019) The German demonstration site at Falkenhagen 
52 Collet et al. (2017) Techno-economic and Life Cycle Assessment of methane production via biogas upgrading 
and power to gas technology. Applied Energy, 192. 

47 

 
 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Second,  gas-related  infrastructure  projects  may  develop  and  integrate  gas  markets 
which would be otherwise (partially) separated due to limited interconnection capacities or 
operational limitations (e.g. due to gas technical specifications), facilitating in this way the 
deployment of gases such as biomethane or hydrogen. 

Future large-scale production of renewable gases could take place either  close to  where 
the  renewable  energy  resources  are  located,  or  renewable  energy  could  be  transported 
closer  to  consumption  centres  before  being  converted  to  gas.  Biogas  production  from 
biomass would logically be located close to biomass sources, while power-to-gas capacity 
could be located close to either renewable electricity sources or demand centres. 

However,  regardless  of  the  location  of  the  gas  production  facilities,  the  location  of 
renewable energy sources (and carbon sources for e.g. methanation) will be an important 
determinant to the EU gas infrastructure needs per transmission corridor and consequent 
cross-border  gas  flows  in  the  long-term.53  Therefore,  cross-border  methane  or 
hydrogen transmission capacity in specific corridors (e.g. from solar, wind or biomass-
rich regions to large energy demand centres) will play an important role in facilitating the 
deployment of renewable gases. 

One  option  for  deploying  decarbonized/renewable  gases  is  admixing  hydrogen  to 
methane networks. The biomethane and hydrogen study54 indicates that this question 
has  to  be  analysed  separately  for  the  transmission  and  distribution  levels.  Hydrogen 
admixture at the transmission level carries considerably greater challenges due to the need 
to  avoid  temporal  and  regional  variations  in  the  hydrogen  content  and  due  to  the 
requirement  that  the  entire  gas  system  be  compatible  with  such  admixture,  unless 
(de)blending  capacities  are  set  at  the  cross-border  and  transmission-distribution 
interfaces. However, deblending capacity at cross-border points could lead to considerable 
additional  investment  costs,  and  is  unlikely  to  be  deployed  at  large  scale.  Hydrogen 
admixture  at  the  distribution  level  is  comparatively  less  challenging,  as  it  is  possible  to 
maintain any hydrogen admixture within a specific distribution system (in the absence of 
reverse flows from distribution to transmission). Hence, for 2030 the study assumes there 
may be hydrogen admixture (up to 10%) in certain distribution networks, while for 2050 
hydrogen admixture will not be relevant in any scenario due to several arguments, such 
as the limited interest compared to the alternatives of dedicated (bio)methane/hydrogen 
networks and the limited contribution to emission reduction targets. 

Therefore,  in  the  short-term  the  deployment  of  hydrogen  may  be  facilitated  by  the 
admixture  in  specific  methane  distribution  networks,  and  in  the  long-term  by  the 
development of dedicated hydrogen networks. Such scenario could change if (de)blending 
technologies advance significantly, which would make possible varying levels of hydrogen 
admixture in different network sections (such as distribution networks  with reverse-flow 
capabilities),  but  this  would  not  change  many  of  the  arguments  in  favour  of  the 
development  of  dedicated  hydrogen  networks,  as  opposed  to  admixing  hydrogen  in 
methane networks. 

There are few technical limitations for the injection of biomethane in methane networks, 
in  comparison  to  hydrogen.55  The  European  Gas  Research  Group  (GERG)  is  nonetheless 
conducting  a  project  assessing  the  impact  of  trace  compounds  of  biomethane  (such  as 
siloxanes  and  H2S)  when  injected  in  methane  networks,  with  the  aim  of  reviewing  the 
biomethane European standards.56  

53 Trinomics, LBST and E3M (2019) Impact of the use of the biomethane and hydrogen potential on trans-
European infrastructure 
54 Ibid. 

55 Ibid. 

56 Standards EN 16723-2 and EN 16723-2 

48 

 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Gas-related  infrastructure  projects  for  methane  networks  may  thus  enable  the 
deployment of biomethane projects by increasing the network capacity in specific 
sections of the network. Analysis has shown that the need for reverse flow projects from 
distribution  to  transmission  networks will  be  restricted  even  in the long-term  to  specific 
network  sections.  Nonetheless,  reverse  flow  projects  in  the  short-term  (to  2022)  are 
highlighted in multiple initiatives by methane network operators.57 Dedicated biomethane 
pipelines could be developed in specific sections of the gas network, and although forming 
part  of  the  transmission  or  distribution  network  (that  is,  forming  part  of  the  regulatory 
asset  base  of  network  operators)  still  having  as  main  purpose  connecting  biomethane 
projects.58 

Many of the gas-related infrastructure projects are associated with the deployment of new 
gas networks  (either  methane or  hydrogen  ones)  and the  connection  of new  gas  users. 
New hydrogen infrastructure (through new investments or the conversion of methane 
infrastructure)  would  clearly  enable  the  production  and  consumption  of  hydrogen. 
Moreover,  the  first  such  networks  would  provide  significant  experience  and  potentially 
learning effects, thus resulting in benefits to hydrogen deployment which would go beyond 
the specific sustainability impacts of one specific hydrogen network. For example, there is 
still significant uncertainty on the operation & maintenance costs of hydrogen networks,59 
which have a relevant effect  on the total costs and which could be reduced with further 
experience in hydrogen networks. 

There is still significant uncertainty on the future deployment levels of dedicated hydrogen 
infrastructure. In case hydrogen becomes an important energy carrier, dedicated hydrogen 
infrastructure should be developed,60 by the conversion of natural gas infrastructure and/or 
through new investments. Increasingly, there is an agreement that the gradual increase 
of  hydrogen  admixture  levels  in  natural  gas  networks  beyond  e.g.  20%  would  be 
impractical, and that conversion to dedicated hydrogen networks is more likely in a high 
hydrogen deployment scenario. In this case, important cross-border EU hydrogen transport 
could develop. Cross-border transport would be necessary to move hydrogen to demand 
centres, if it is produced for example in Southern and Northern European countries with a 
large renewable energy potentials.61 Also, initially localised networks could develop, and 
as a sufficient density of local or regional networks is reached, these could be connected 
by a transmission network. 

Transport by pipelines, ships and trains are the main options for long-distance cross-border 
hydrogen transport. Trains would be an inland option for some regions, and still most likely 
more expensive than pipeline transport. Likewise, transport by ships (maritime or fluvial) 
would be constrained by geography, and still often require pipelines for inland transport. 
Moreover, considering the conversion and eventual reconversion costs of liquid hydrogen, 
liquid  organic  hydrogen  carriers  (LHOCs)  and  ammonia,  long-distance  transport  by 
pipelines  is  competitive  vis-à-vis  the  alternatives  up  to  at  least  1000  km  (especially 
considering the lower costs of converting natural gas pipelines versus new investments). 
Transport  of  liquid  hydrogen,  liquid  organic  hydrogen  carriers  (LHOCs)  and  ammonia 
become increasingly competitive with hydrogen pipeline transport as distance increases. 
However, as generally, for all options, the cost of hydrogen transport increases, the share 

Juge (2019) GERG Biomethane project – Biomethane trace components and their potential impact on European 
gas industry 
57 See Gas for Climate (2019) Action Plan 2050 (update 2019) and Green Gas Initiative (2017) Biomethane – 
Naturally Green Gas. 
58 Already in 2017 the Ontras TSO (DE) indicated two of its pipelines were dedicated to biomethane transport. 
See Green Gas Initiative (2017) Biomethane – Naturally Green Gas. 
59 Trinomics, LBST and E3M (2019) Impact of the use of the biomethane and hydrogen potential on trans-
European infrastructure 

60  European  Commission  (2018)  A  Clean  Planet  for  All.  In-Depth  Analysis  in  Support  of  the  Commission 
Communication COM(2018) 713 
61  Trinomics,  LBST  and  E3M  (2019)  Impact  of  the  use  of  the  biomethane  and  hydrogen  potential  on  trans-
European infrastructure 

49 

 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

of  hydrogen  transport  and  distribution  costs  to  the  final  hydrogen  cost  may  become 
significant and affect the overall competitivity of hydrogen against other energy carriers.62 

Hence,  there  is  still  much  uncertainty  on  the  future  need  for  cross-border  hydrogen 
transport and its competitivity versus other energy carriers. It is out of the scope of this 
study to assess the likelihood of the development of hydrogen infrastructure in general and 
cross-border  transport  pipelines  in  particular,  but  they  should  not  be  excluded  at  the 
moment.  

Potential adaptation / conversion of infrastructure and end-use appliances will be 
necessary in the case of either pure or admixed hydrogen. Figure 4-2 presents a Marcogaz 
summary  of  test  results  on  the  tolerance  for  hydrogen  admixture  in  natural  gas 
infrastructure and end-use applications. At relatively low concentration levels (from 5 to 
10%), investments may be needed for the adaptation of gas storage (porous storage and 
well  completion),  gas  turbines,  chemical  industry  equipment  using  natural  gas  as 
feedstock,  and  reservoirs  for  CNG  vehicles.  Concentrations  above  10%  require  further 
investigations  among  others  in  transmission  and  distribution,  including  for  pressure 
regulation and metering, as well as the adaptation of end-use equipment and appliances.

62 IEA (2019) The future of hydrogen. 

50 

 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Figure 4-2 Test results and regulatory limits for hydrogen tolerance of natural gas infrastructure and end-use 

No significant 
issues in available 
studies 

Mostly positive 
results. 
Modifications/ other 
measures may be 
needed. 

Technically feasible, 
significant 
modifications/ 
other measures or 
replacement 
expected. 

Currently not 
technically feasible. 

Insufficient 
information. 

Conflicting 
information, R&D/ 
clarification 
required. 

Source: Marcogaz (2019) Overview of available test results and regulatory limits for hydrogen admission into existing natural gas 
infrastructure and end use 

51 

 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Enabling  the  deployment  of  renewable  electricity  by  increasing  the 
flexibility of the energy system 

In  order  for  the  EU  to  achieve  full  net  decarbonization  by  2050,  electricity  demand  is 
forecasted  to  grow  in  all  scenarios  of  the  2050  Long-Term  Strategy  (LTS),63  along  with 
renewable  electricity  production,  which  would  represent  in  2050  about  80%  of  the 
electricity supply in all scenarios. 

This  electrification  of  the  EU  energy  system  is  seen  across  most  sectors,  while  in 
comparison  consumption  of  natural  gas  is  poised  to  decrease  in  all  LTS  scenarios. 
Nonetheless  the  Long-Term  Strategy  acknowledges  that  despite  the  uncertainty 
surrounding the role of natural gas in the long-term, the use of renewable/decarbonized 
hydrogen and (bio)methane could support the decarbonization of the energy system and 
make  best  use  of  the  existing  gas  infrastructure.  Multiple  other  studies  do  indicate 
scenarios  combining  the  use  of  the gas  and  electricity systems allow  to  achieve  full  net 
decarbonization at least cost.64 

Besides  gas  serving  to  satisfy  specific  end-uses  which  may  be  hard  to  electrify  due  to 
technology  limitations  or  the  required  level  of  investments  in  electricity  generation  and 
transport/distribution  (especially space heating with its high  peak  winter  demand), gas-
related infrastructures can facilitate the deployment of renewable electricity by increasing 
the  overall  flexibility  of  the  energy  system,  which  enables  a  higher  penetration  of 
intermittent renewable electricity sources while maintaining the security of supply. 

The  interlinkages  study  for  the  ENTSOs65  mapped  both  direct  and  indirect  potential 
interactions between the electricity and gas systems. Direct interactions are those where 
gas and  electricity are  involved for  the  same  technological  application, as  either  energy 
inputs or outputs. Indirect interaction are those where gas and electricity are in competition 
as alternative energy sources for a specific use, such as transportation or heating. More 
specifically, these potential interactions concern: 

  Energy conversion 

o  Gas-to-power 

  Open and combined-cycle gas turbines (OCGT and CCGT) 

  Gas combined heat and power (CHP) 

o  Power-to-gas 

  Power-to-hydrogen 

  Power-to-gas (hydrogen or methane injection into gas network) 

 

Interlinked use 

o  Electricity-driven gas compressors 

o  Hybrid heating technologies 

 

Industrial gas furnaces with electric boilers 

  Hybrid heating (residential & tertiary sector, district heating) 

63 European Commission (2018) A Clean Planet for All. In-Depth Analysis in Support of the Commission 
Communication COM(2018) 713 
64 For example Trinomics, LBST and E3M (2019) Impact of the use of the biomethane and hydrogen potential 
on trans-European infrastructure; Trinomics, LBST et al. (2018) The role of Trans-European gas infrastructure 
in the light of the 2050 decarbonisation targets; Frontier Economics (2019) The Value of Gas Infrastructure in a 
climate-neutral Europe; Navigant (2019). Gas for Climate - The optimal role gas in a net-zero emissions energy 
system.; European Climate Foundation (2019). Towards fossil-free energy in 2050; ICCT (2018). The potential 
for low-carbon renewable methane in heating, power, and transport in the European Union. 
65 Artelys (2019) Investigation on the interlinkage between gas and electricity scenarios and infrastructure 
projects assessment 

52 

 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  Hybrid transport technologies (if any) 

  Competition for energy uses (indirect interaction) 

o  Mobility 

o  Heating 

o  Biogas use (for electricity production or as end-use gas) 

Therefore, a number of interactions are possible, although they do not all have the same 
importance to interlinking the electricity and gas systems. Moreover, increased gas use in 
competitive  applications  (mobility,  heating,  biogas  as  end-use  gas)  will  likely  reduce 
electricity demand (and thus not positively enable the deployment of renewable electricity 
sources). Moreover, some of the gas-electricity system interactions involve infrastructure 
elements themselves (such as gas compressors), although most do not. However, whether 
gas  infrastructure  elements  are  responsible  or  not  for  such  interactions,  they  may  add 
flexibility to the gas system, which in its turn may support the deployment of renewable 
electricity. 

In  summary,  gas-related  infrastructures  which increase  the  flexibility  of the  gas  system 
may further enable the deployment of renewable electricity due to the direct interaction 
between  the  gas  and  electricity  system  (power-to-gas,  gas-to-power  and  interlinked 
electricity/gas  use),  as  indicated  in  Figure  4-3.  In  contrast,  indirect,  competitive 
interactions between electricity and gas such as hybrid heating devices will not act as a 
channel for the gas system flexibility to facilitate RES-e deployment. 

Figure 4-3 Flexibility provision from the gas to the electricity system 

Gas system 
flexibility 
provision
• Gas transmission
• Gas storage

Gas-electricity 
interactions

• Power-to-gas
• Gas-to-power
• Interlinked 

gas/electricity use

Electricity 
system 
flexibility needs
• Due to intermittent 
RES-e penetration

Therefore,  the  main  gas-related  infrastructures  which  may  provide  flexibility  to  the 
electricity system include gas transmission, storage and conversion to/from electricity. The 
exact flexibility contributions of the gas system (and of specific gas-related infrastructure 
projects) will vary per system and depend on the other existing flexibility resources, which 
may  be  complementary  (to  varying  degrees),  as  e.g.  gas  transmission  and  storage 
projects. 

53 

 
 
 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

  PCI ELIGIBILITY AND TEN-E SUSTAINABILITY OF GAS-RELATED 
INFRASTRUCTURE PROJECTS 

The key objective of chapter 5 is to analyse which of the gas-related infrastructure projects 
discussed in chapter 4 could potentially meet the PCI eligibility criteria (section 5.1), and 
which of the sustainability aspects foreseen in TEN-E would be addressed by these projects 
(section  5.2).  By  conducting  this  assessment,  the  chapter  makes  recommendations  for 
possible improvements in the TEN-E Regulation and the associated gas CBA methodology 
for the assessment of gas-related infrastructure projects. 

5.1.  PCI eligibility of gas-related infrastructure projects 

As  indicated  in  Figure  5-1,  the  TEN-E  Regulation  specifies  both  general  and  specific 
eligibility  criteria,  while  its  Annex  II  determines  the  categories  of  gas  projects  that  are 
eligible  for PCI  status.  While  all  general  criteria  need  to  be  met,  only  one Annex  II and 
specific criteria each need to be satisfied for eligibility. 

Figure 5-1 Eligibility criteria structure of gas PCI projects 

General criteria

(all required)

Annex II criteria

(one required)

Specific criteria

(one required)

The provisions determined in Article 4 “Criteria for PCIs” of the TEN-E Regulation define 
the following general criteria:  

a)  The project is necessary for at least one of the gas infrastructure priority corridors 

and areas listed in Annex I;  

b)  The  potential  overall  benefits  of  the  project  outweigh  its  costs,  including  in  the 

longer term; and 

c)  The project meets any of the following criteria: 

i. 

ii. 

iii. 

involves at least two Member States by directly crossing the border of two 
or more Member States 
is located on the territory of one Member State and has a significant cross-
border impact 
crosses the border of at least one Member State and a European Economic 
Area country.  

Annex II of the TEN-E Regulation determines the eligible categories for gas projects: 

a)  Transmission pipelines for the transport of natural gas and biogas that form part of 
a network which mainly contains high-pressure pipelines, excluding high-pressure 
pipelines used for upstream or local distribution of natural gas;  

b)  Underground  storage  facilities  connected  to  the  above-mentioned  high-pressure 

gas pipelines;  

c)  Reception,  storage  and  regasification  or  decompression  facilities  for  liquefied 

natural gas (LNG) or compressed natural gas (CNG);  

d)  Any equipment or installation essential for the system to operate safely, securely 
and efficiently or to enable bi-directional capacity, including compressor stations. 

Article  4  of  the  TEN-E  Regulation  furthermore  defines  the  specific  eligibility  criteria 
(detailed in Annex IV): 

54 

 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

ii) 

i)  Market  integration,  inter  alia  through  lifting  the  isolation  of  at  least  one  Member 
State and reducing energy infrastructure bottlenecks; interoperability and system 
flexibility; 
security of supply, inter alia through appropriate connections and diversification of 
supply sources, supplying counterparts and routes; 
competition,  inter  alia  through  diversification  of  supply  sources,  supplying 
counterparts and routes; 
sustainability,  inter  alia  through  reducing  emissions,  supporting  intermittent 
renewable generation and enhancing deployment of renewable gas. 

iii) 

iv) 

It is considered that all gas-related infrastructure projects have the potential to satisfy the 
following eligibility general criteria, which are not further analysed in this section: 

1.  Necessity  for  at  least  one  gas  infrastructure  priority  corridors  and  areas  (article 

4(a)); 

2.  Benefits outweighing costs (article 4(b)). 

For the remaining eligibility criteria, the analysis on whether the projects could potentially 
satisfy  them  is  indicated  in  Table  5-1,  and  discussed  next.  There  could  be  very  specific 
projects which whose eligibility would differ from the one shown above, as the objective 
here is to assess the eligibility of the project types, rather than address exceptions. 

55 

 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability 

Table 5-1 PCI eligibility of gas-related infrastructure projects 

General 
criteria 

Eligible 
categories 
(Annex II) 

Specific criteria (Annex IV) 

PCI 
eligibility 

Cross-border 
relevance 

Applicability to 
one gas category 

Market 
integration 

Security of 
supply 

Competition  Sustainability 







 

 

 

 

 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

No 

Yes 

No 

No 

Yes 

No 

Yes 

Yes 

Project type 

New or converted 
pure hydrogen 
pipelines 

Pipelines with 
hydrogen 
admixture 

Pure hydrogen 
storage facilities 

Hydrogen 
electrolysis 
facilities 

Biomethane 
injection terminals 

Hydrogen 
methanation facility 

Reverse D->T 
methane 
compressors 

Methane emission 
reduction projects 

: Meets the criteria in most cases; : Potentially meets the criteria for some cases; : Does not meet the criteria.

56 

 
 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability  

Eligible infrastructure categories 

The list of PCI eligible infrastructure projects in the Annex II of the TEN-E Regulation state 
clearly that only natural gas (or biogas) pipelines on the transmission level are allowed to 
become  a  PCI.  Similarly,  the  facilities  for  reception,  storage  and  decompression  or 
regasification  of  liquefied  and  compressed  gases  are  limited  to  natural  gas.  The 
underground  storage  facilities  are  not  limited  with  regards  to  the  type  of  gas  used,  but 
they have to be connected to the natural gas transmission network. 

All facilities dealing purely with hydrogen are thus not allowed in the current framework, 
although a combination in a cluster could be possible – e.g. hydrogen underground storage 
combined  with  a  methanation  facility  that  is  connected  to  the  natural  gas  transmission 
system. Natural gas pipelines with hydrogen admixture might be eligible according to this 
criteria since they still transport natural gas, but infrastructure conversion to enable higher 
level of hydrogen admixture are not eligible, since they effectively do not add new transport 
capacity (according to Annex IV, see paragraphs on cross-border impact below). 

With  regards  to  biogas,  the  high-pressure  transport  pipelines  on  transmission  level  are 
explicitly allowed. Since biomethane is similar to natural gas from a technical perspective, 
a  biomethane  injection  facility  (on  the  transmission  system  level)  could  potentially  be 
included in the category of reception facilities of liquefied or compressed natural gas. 

The  types  of  facilities  falling  under  the  article  2(d)  of  the  Annex  II  are  defined  very 
generally,  but  could  include  methane  emission  reduction  projects,  as  they  improve  the 
efficient  operation  of  networks.  It  could  also  include  the  reverse  compressors  on  the 
transmission/distribution interface. 

The Annex II does not differentiate between onshore and offshore infrastructure. However, 
the article 2(a) excludes upstream pipelines. 

The criteria in Annex II also do not explicitly cover facilities for conversion between energy 
carriers (electrolysers, methanation facilities). Since they can be hardly included in any of 
the defined categories, they are not eligible for the PCI status. 

Cross-border impact 

From all the analysed infrastructure types, only the transmission pipelines can cross the 
border of at least two Member States (or a Member State and a European Economic Area 
country). All the other projects can only be located on a territory of one MS and thus need 
to have significant cross-border impact according to paragraph (1) of Annex IV: 

(1) 

A project with significant cross-border impact is a project on the territory of a 
Member State, which fulfils the following conditions: 

(c)  for  gas  transmission,  the  project  concerns  investment  in  reverse  flow 
capacities or changes the capability to transmit gas across the borders of the 
Member States concerned by at least 10%  compared to the situation prior to 
the commissioning of the project; 

(d)  for  gas  storage  or  liquefied/compressed  natural  gas,  the  project  aims  at 
supplying  directly  or  indirectly  at  least  two  Member  States  or  at  fulfilling  the 
infrastructure  standard  (N-1  rule)  at  regional  level  in  accordance  with  Article 
6(3)  of  Regulation  (EU)  No  994/2010  of  the  European  Parliament  and  of  the 
Council 

This  criterium  is  thus  foremost  a  question  of  the  scale  of  the  project.  The  considered 
facilities  would  have  to  be  large  enough  to  either  increase  the  cross-border  capacity by 
10% (in case of transport projects) or supply at least two countries (in case of storage and 
liquefied/compressed gas infrastructure). This criterium might effectively exclude projects 

57 

 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability  

that aim to refurbish or upgrade natural gas infrastructure to enable hydrogen admixture, 
since they would most likely not be coupled with an increase of transport capacity. 

Given  the  fact  that  most  of  the  considered  gas-related  infrastructure  projects  are 
innovative and did not yet reach market-ready level of development, it is questionable that 
they could be implemented on such a scale in the foreseeable future. This criterium would 
thus  exclude  many  projects,  such  as  biomethane  injection,  reverse  flow  on  the 
distribution/transmission interface, or the methane emission reduction projects. However, 
these types of infrastructure could be included in wider project clusters that could together 
achieve the required cross-border impact. 

Specific criteria 

Market integration 

Since  many  of  the  analysed  infrastructure  categories  aim  at  integrating  indigenous 
production of alternative gases, it is not possible to argue that they could contribute to the 
market integration through lifting the energy isolation of a Member State (notwithstanding 
the  fact  that  the  problem  of  single-supplier  dependency  has  been  largely  solved  in  the 
EU).66 However, enabling decentralised domestic production of gases could relieve cross-
border infrastructure bottlenecks by supplying part of the domestic demand. 

Some  of  the  analysed  projects  can  clearly  contribute  to  the  system  flexibility,  such  as 
enabling reverse flow of gases. Other projects, such as hydrogen electrolysis facilities, have 
however  flexibility  benefits  that  are  apparent  only  when  analysing  electricity  and  gas 
infrastructure in combination, since they provide flexibility by coupling those two systems, 
albeit they do not bring any direct flexibility benefits to the gas system alone. 

It is also questionable if building hydrogen infrastructure can be considered as enhancing 
the natural gas market integration. Moreover, there is currently no regulatory framework 
for hydrogen markets on the European level and it is thus not clearly defined what form of 
hydrogen markets integration is desired. 

Competition 

It  can  be  argued  that  the  analysed  types  of  infrastructure  aim  at  integrating  either 
indigenous  sources of gas,  or  enabling import of  gases  from  alternative  supply sources. 
Because of the lack of integration of hydrogen and natural gas markets, it is questionable 
if pure hydrogen infrastructure can contribute to the increase of market diversification and 
supply  source  access  indicators  used  in  the  current  gas  CBA  methodology67.  However, 
hydrogen  can  directly  substitute  part  of  the  natural  gas  demand  and  can  therefore 
contribute to lowering the single supplier dependency. 

Security of supply 

The  infrastructure  projects  aimed  at  integrating  domestic  gas  production  have  clear 
benefits for enhancing the security of supply and also contribute to the long-term resilience 
of the European gas system, since they aim at developing modern infrastructure that can 
be part of a low-emission energy system. It is however questionable if the new types of 
infrastructure can have a significant impact in the short-  and medium-term future – for 
example, their contribution to fulfilling the N-1 criterion can be limited by their scope and 
scale. 

66 EC (2019). Fourth report on the State of the Energy Union. Available at 
https://ec.europa.eu/commission/sites/beta-political/files/fourth-report-state-of-energy-union-
april2019_en_0.pdf 
67 ENTSOG (2018): 2nd CBA Methodology. Avaliable at: https://www.entsog.eu/methodologies-and-
modelling#2nd-cba-methodology. 

58 

 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability  

Discussion of potential changes in the TEN-E Regulation 

The clarification of which infrastructure projects are eligible for PCI status is a no-regret 
option. The Regulation currently includes explicitly only natural gas and “biogas”. Biogas 
is  however  not  defined  in  the  Regulation  and  the  definition  section  refers  to  outdated 
European legislation, such as the 2009 Renewable Energy Directive. Similarly, “power-to-
gas” is mentioned in the article 3(d) of Annex IV, potentially excluding other forms of low-
carbon hydrogen (such as production via steam-methane reforming combined with CCS). 
An  updated  definition  of  eligible  infrastructure  is  thus,  at  least,  necessary  to  ensure 
coherence with the Clean Energy Package and future gas decarbonisation package. 

Dedicated (100%) hydrogen infrastructure is expected to function in the future in parallel 
with the natural gas infrastructure. This raises a question whether the TEN-E Regulation 
should address hydrogen infrastructure as a separate category. Natural gas markets and 
infrastructure  in  the  EU  are  well  developed,  while  hydrogen  markets  and  dedicated 
infrastructure  are  still  very  limited  and  largely  inexistent  in  most  EU  Member  States. 
Furthermore,  natural  gas  infrastructure  projects  are  also  currently  divided  into  four 
regional groups with different regional needs that do not necessary apply to hydrogen as 
well.  

Forming a special priority thematic group that would take into account the present phase 
of  incipient  renewable  and  low-carbon  hydrogen  market  and  specific  infrastructure 
development  (similar  to  CO2  transport  networks  and  smart  grids)  could  be  a  simpler 
solution than setting a set of eligibility criteria that would treat all types of gases equally. 
This solution has however the negative effect of not directly comparing the benefits of all 
gas projects and consequently obscuring the holistic perspective that takes into account 
(including  electricity 
the  complex 
infrastructure). 

interdependence  of  energy 

infrastructures 

The  acceleration  of  cross-border  infrastructure  build-up  and  refurbishment  in  order  to 
ensure  functioning  of the  internal  energy  market  is  one  of  the  main  goals  of  the  TEN-E 
Regulation. For that reason, the Regulation is aimed at supporting the selection of the most 
important projects while the number of PCIs should remain “manageable”. The article 23 
of the preamble states that the number of projects should not significantly exceed 220, 50 
of them for gas projects. 

Even with the current number of projects, significant delays in their implementation are 
occurring and the efficient oversight and regulatory support based on the TEN-E Regulation 
is in question68. The possible broadening of the scope of the Regulation should thus also 
be  considered  taken  into  account  its  contribution  and  efficacy  to  achieve  its  objectives. 
However,  a  more  detailed  analysis  of  the  desirability  to  include  hydrogen  infrastructure 
within the TEN-E Regulation is out of the scope of this study. 

5.2.  TEN-E sustainability of gas-related infrastructure projects 

In  order  to  complement  the  analysis  of  sustainability  characteristics  conducted  for  Task 
4.2, the sustainability aspects specific to TEN-E of the gas-related infrastructure projects 
are assessed, considering the possibilities defined by the gas CBA methodology and the 
new  sustainability  indicator  developed  in  chapter  2.  The  aim  is  to  understand  to  which 
extent  the  gas-related  infrastructure  projects  could  contribute  to  present  TEN-E 
sustainability aspects, and how future contributions could be considered beyond what can 
be captured by the new indicator. 

Combined  with  the  eligibility  analysis  of  section  5.1,  this  may  support  long-term 
improvements  to  the  sustainability  indicator,  the  gas  CBA  methodology  and  the  TEN-E 

68 ACER (2019). Consolidated Report on the Progress of Electricity and Gas Projects of Common Interest. 
Available at 
https://www.acer.europa.eu/Official_documents/Acts_of_the_Agency/Publication/CONSOLIDATED%20REPORT
%20ON%20THE%20PROGRESS%20OF%20ELECTRICITY%20AND%20GAS%20%20PROJECTS%20OF%20COM
MON%20INTEREST%20-%202019.pdf. 

59 

 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability  

Regulation in general. Additional considerations are discussed for this purpose, such as the 
complementarity and substitutability of gas-related infrastructure projects. 

Contributions 
infrastructure projects 

to  TEN-E 

sustainability  aspects  by  gas-related 

Table 5-2 summarizes which of the sustainability characteristics of the selected projects in 
section  4.2  could  contribute  to  the  TEN-E  sustainability  aspects.  The  contributions  are 
detailed  on  whether  it  would  be  possible  to  consider  those  contributions  with  the  new 
sustainability  indicator  developed  in  chapter  2,  or  whether  further  changes  to  the  CBA 
methodology or sustainability indicator would be necessary. There are discussed in detail 
next. 

Regarding the substitution of fossil fuels, it can be considered for most selected project 
types, employing the specific emission factors of the gases and the displaced consumption 
volumes of natural gas, coal and liquid fossil fuels. This is detailed in section 3.1. In the 
case of hydrogen projects, considering the benefits of the substitutions of fossil fuels would 
be possible for the share of hydrogen which is admixed in the gas system. Considering the 
benefits  of  projects  within  a  hydrogen  system  would  require  a  hydrogen-methane 
interlinked model. In other words, the impact of hydrogen projects on the substitution of 
fossil fuels can presently be considered only if they are located within the methane system 
or  at  most  at  the  interfaces  with  electricity  and  methane  systems.  Likewise,  for  the 
reduction in greenhouse gases due to the storage and/or utilisation of CO2 the same 
possibilities and limitations apply. 

The reduction of methane emissions by projects targeting specifically this aspect can 
be accounted through verified project-specific data. Other projects which lead to hydrogen 
admixture in the methane  system can also lead to the  reduction in methane  emissions. 
This could be accounted for by considering the specific volumetric gas  emissions due to 
leakage,  venting  and  incomplete  combustion  and  the  admixture  rate.  However,  at  low 
admixture rates the benefits are likely to be marginal. It must be noted that an increase 
in  methane  gases  consumption  could  lead  to  increased  methane  emissions  and  thus  a 
negative sustainability impact, as indicated in section 2.3. 

The enabling of admixed hydrogen for projects directly contributing to the production 
and/or  injection  in  the  methane  system  can  be  assessed  by  verified  project-specific 
information. The inclusion of hydrogen networks within the scope of TEN-E would allow to 
consider  the  benefits  of  enabling  pure  hydrogen  due  to  infrastructure  projects  in  the 
hydrogen system (pipelines, regasification terminals, storage). This should be combined 
with a modelling of hydrogen systems, and of the interfaces with electricity and methane 
systems  (as  indicated  above),  in  order  to  allocate  sustainability  benefits  to  specific 
projects. Otherwise, the impact of the development of hydrogen supply and demand which 
remains outside of the methane system can be considered through reduced demand for 
other energy carriers in joint scenarios, but the sustainability benefits cannot be allocated 
to specific projects. 

The enabling of biomethane is comparatively more straightforward than for hydrogen, 
and could be assessed by verified project-specific information. For example, a biomethane 
injection  terminal  promoter  could  corroborate  its  planned  capacity  and  expected  yearly 
utilisation rate. 

The  benefits  of  enabling  renewable  electricity  requires  the  development  of  an 
integrated  gas-electricity  systems  model,  or  at  least  of  strongly  interlinked  gas  and 
electricity models. Defining the impacts to enabling renewable electricity is arguably easier 
for  hydrogen  electrolysis  projects  (and  injection  terminals  for  electrolytic  hydrogen),  as 
promoters can more easily provide direct evidence of the project’s impact on the flexibility 
of  the  energy  system  and  consequently  on  the  enabling  of  electricity  from  renewable 
sources. 

60 

 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability  

Table 5-2 Consideration of the TEN-E sustainability contributions of selected projects  

Project 

Substituting natural 
gas 

Substituting coal 

Substituting liquid 
fossil fuels 

Reducing methane 
emissions 

Storing and/or 
utilizing CO2 

Enabling 
hydrogen and biomethane 

Enabling 
RES-E 

Reducing greenhouse gases emissions 

Enabling renewable/decarbonized energy 

Pure hydrogen 
pipelines 

Hydrogen storage 
facilities 

Admixed hydrogen 
pipelines 

Hydrogen 
electrolysis 
facilities 

Hydrogen injection 
terminal  

Biomethane 
injection terminals 

Reverse D->T 
methane 
compressors 

Methane emission 
reduction projects 

Possible, specific emission factor of admixed gas and 
displacement of coal and liquid fossil fuels. Only for gas system 
impact of admixed hydrogen, not for pure H2 remaining in 
hydrogen system, unless a hydrogen-methane interlinked model 
is developed. 

NA 

NA 

NA 

Possible, with 
calculation based on 
admixture %. 

Possible, with 
calculation based on 
admixture % (for 
admixed hydrogen 
only) 

Possible, through 
specific emission 
factor for injected 
gas. 

Only for gas system impact 
of admixed hydrogen. 

Requires a hydrogen-
methane-electricity 
model. 

Possible, using verified 
project-specific data / 
calculation based on 
admixture %. 

Possible, using verified 
project-specific data. 

Requires a methane-
electricity model. 

Using verified project-
specific data 

Requires a 
methane/hydrogen-
electricity model. 

NA 

NA 

Possible, using 
verified project-
specific data 

Using verified project-
specific data. 

NA 

NA 

NA 

61 

 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability  

Complementarity  of  the  sustainability  impacts  of  different  project 
categories 

Section 5.1 indicates that many gas-related infrastructure projects would not be eligible 
for PCI status at the moment. Nonetheless, if new project categories eventually become 
eligible for PCI status, the complementarity or substitutability of gas-related infrastructure 
projects regarding the sustainability characteristics will be a central aspect, as e.g. power-
to-gas and hydrogen pipelines may need to be assessed side-by-side to currently eligible 
gas transmission, storage and LNG projects. 

Under the TEN-E regulation, gas projects of different categories (e.g. a gas pipeline and 
an  LNG  terminal)  do  not  compete  in  the  same  ranking.  However,  in  the  sustainability 
 emissions savings per scenario are 
indicator of the current gas CBA methodology, total CO2
divided among all considered projects, according to their capacities (in MW). Hence, a gas 
pipeline and an LNG terminal would compete to some extent under the current indicator, 
in the allocation of the CO2 emissions savings. 

However, this does not reflect that projects of different categories such as a pipeline and 
an  LNG  terminal  may  be  complementary,  rather  than  substitutes,  regarding  their 
contributions  to  sustainability.  In  another  example,  a  hydrogen  injection  facility  and  a 
methane  pipeline  adapted  admitting  admixed  hydrogen  both  contribute  to  enable  the 
consumption of hydrogen, even in the case of independent projects which cannot be clearly 
grouped into a project cluster. 

Figure 5-2 presents the different options for the allocation of sustainability impacts such 
as emission savings among projects of the same or different categories. Overlaps should 
be avoided within each project category, but for some sustainability benefits there could 
be  an  overlap  in  allocation  between  different  project  categories.  Independently  of  the 
approach  selected,  the  (eventual)  inclusion  of  further  gas-related  infrastructure  project 
categories  in  the  TEN-E  scope  would  require  the  consideration  of  how  to  allocate  the 
different sustainability benefits between projects. 

Option  1  represents  the  approach  for  allocating  emission  savings  of  the  current 
sustainability indicator in the gas CBA methodology, and of the new indicator when using 
a flow-based allocation without an interlinked model. Option 2 allocates the full scenario 
benefits to each category, and thus has a full overlap of benefits, while option 4 has no 
overlap. Either  option 2 or 4 could potentially not reflect the  fact infrastructure projects 
can  be  complementary  or  substitutes.  A  partial  overlap  of  the  sustainability  impacts  of 
different project categories as in option 3 could better reflect the partial complementarity 
of  some  projects,  but  would  increase  the  complexity  of  the  allocation  step.  As,  in  the 
framework  of  the  TEN-E  regulation,  the  objective  is  to  rank  the  projects  within  a  same 
category, option 1 may still achieve that with greater simplicity. 

62 

 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability  

Figure 5-2 Options for the allocation of emission savings among project 
categories 

Option 1

Option 2

Option 3

Option 4

Allocate total emissions savings 
among all projects

Allocate total emissions savings 
to each project category.
Full overlap.

Allocate part of the emissions 
savings to each project category.
Partial overlap.

Allocate part of the emissions 
savings to each project category. 
No overlap.

Allocate emission in each category savings among projects

Allocation of emission savings

Savings 
allocated to 
all projects

Category A
savings

=
Category B 
savings

Category A 
savings

Category B 
savings

Category A 
savings

Category B 
savings

It can nonetheless be worthwhile to adopt different approaches to allocate the benefits to 
the TEN-E sustainability aspects due to the substitution of fossil fuel use, the reduction of 
methane emissions and the enabling of renewable energy. For example: 

  Allocation of benefits due to the fossil fuel substitution: use option 1, with 
the  partition  of  the  benefits  based  on  a  clear  criteria  (such  as  additional  utilised 
capacity), avoiding double-counting, may be adequate for a group of projects of the 
same  type.  This  as  long  as  the  criteria  considers  the  actual  contribution  of  the 
project  to  the  substitution  of  fuels,  by  allocating  benefits  based  on  e.g.  the  load 
curve or flow-based modelling as presented in chapter 3. 

  Direct  benefits  of  enabling  biomethane,  hydrogen  and  renewable 
electricity: use  option 3, using specific project characteristics, based on verified 
data from promoters and agreed procedures for accounting for these benefits. Due 
to  the  project  complementarity  and  the  qualitative  nature  of  the  benefit,  double 
counting  may  be  accepted,  as  the  objective  is  to  define  the  sustainability 
characteristics  to  rank  the  candidate  PCIs,  rather  than  accounting  for  the 
achievement of targets such as for GHG emission reduction or RES – these can be 
tracked at the scenario level. 

  Indirect  benefits  of  enabling  biomethane,  hydrogen  and  renewable 
electricity:  use  option  3.  Due  to  the  coupling  of  the  methane  and  electricity 
systems:  may  be  calculated  using  an  integrated  energy  systems  model,  and 
allocated similarly as for fossil fuel substitution benefits, avoiding double-counting. 
Alternatively, due to the partially qualitative nature of the benefit, double counting 
may be accepted. 

The use of PINT (put in one at a time) or TOOT (take out one at a time) approaches could 
better reflect the complementarity and substitutability of (a cluster of) gas projects to a 
reference gas grid. The use of a robust CBA methodology (i.e. a min-max regret approach 
selecting the projects which show the highest minimum benefits across all scenarios) could 
represent a further step and better reflect the impacts of the projects considering future 
uncertainty. 

63 

 
 
 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability  

Box 5-1 Linking sustainability benefits to specific projects 

As discussed in this study, while the sustainability benefits of a certain scenario can 
be allocated to a pool of projects, others could be directly (and exclusively) assigned 
to  a  specific  project.  This  could  be  the  case  of  e.g.  a  new  transmission  pipeline 
connecting  a  biomethane  producer  to  the  natural  gas system,  which  could be  thus 
assigned the full emissions saving arising from the biomethane consumption as well 
as  the  benefits  from  enabling  biomethane.  However,  the  issue  of  accepting  or  not 
overlap with the benefits allocated to other projects would need to be addressed per 
sustainability benefit type. 

Potentially,  sustainability  benefits  could  be  linked  to  a  specific  project  only  for  the 
benefits where overlap between project categories is acceptable. The impacts could 
be directly assigned to a specific project if, in the absence of the project, they would 
not  occur  or  be  significantly  reduced.  For  example,  if  a  gas-related  infrastructure 
project was essential for the injection of biomethane or hydrogen from a production 
facility. Generally, projects within a meshed, interconnected gas system could not be 
directly linked to specific sustainability impacts.  

Direct sustainability impacts of specific projects would also have to be defined based 
on  project  characteristics  and  supported  by  verifiable  project  data  from  the 
promoters.  A  parallel  can  be  made  to  the  3rd  electricity  CBA  methodology  recently 
submitted by ENTSO-E to ACER. The ENTSO-E draft includes project-level indicators, 
“designed  to  address  the  instances  where  it  is  not  possible  for  ENTSO-E  to  assess 
certain benefits at a pan-European level within the TYNDP process.”69 

No sustainability benefit is considered at the project level for the  ENTSO-E 3rd CBA 
methodology,  but  it  provides  a  potential  approach  for  considering  the  direct 
sustainability impact of gas-related infrastructure projects. Promoters are required to 
provide  a  copy  of  a  study  supporting  the  project-level  benefit(s),  along  with  the 
assumptions, data sources, tools used and demonstration of the alignment of the used 
methodology to the electricity CBA. 

In the case of direct sustainability benefits of gas-related infrastructure projects, other 
supporting  evidence  could  include  project  plans  or  letters  of  intent  from  e.g. 
biomethane  producers  demonstrating  the  contribution  to  a  TEN-E  sustainability 
aspect. These would need to demonstrate the alignment with the TEN-E gas-related 
infrastructure  eligibility  requirements  as  well  as  the  sustainability  indicator  scope 
(regarding, for example, eventual maximum carbon footprints of low-carbon gases). 

Further  issues  concerning  the  TEN-E  sustainability  of  gas-related 
infrastructure projects 

End-users take their equipment and appliances investment decisions based on comparative 
prices  and  availability  of  different  energy  carriers,  and  (potentially)  the  sustainability 
characteristics of e.g. natural gas, heat, biomethane, hydrogen and electricity. While the 
configuration  of  energy  systems  plays  a  direct  role  in  determining  those  factors,  it  is 
unlikely  that  (most)  individual  projects  will  alter  decisions  of  end-users  significantly,  as 
these decisions are influenced by a multitude of factors. 

Therefore,  these  investment  decisions  of  end-users  and  their  impact  on  the  TEN-E 
sustainability aspects can be addressed in project-specific CBAs through scenarios, and if 
needed  additional  considerations  for  specific  projects.  Thus,  investment  decisions  most 

69 ENTSO-E (2020). 3rd ENTSO-E Guideline for Cost Benefit Analysis of Grid Development Projects. Draft Version, 
January 28. 

64 

 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability  

likely do not need to be modelled in project-specific CBAs. If a project directly affects an 
investment  decision  (e.g.  an  injection  terminal  for  collection  of  hydrogen  produced  in  a 
specific region), this can be adequately measured from (verified) project data. Likewise, 
peripheral regions with poor gas supply may benefit from specific projects, which may also 
be measured through project-specific considerations. 

Another issue is that of infrastructure lock-in. Logically, the award of PCI status to projects 
which  contribute  to  lock-in  in  unsustainable  pathways  should  be  avoided.  An  eventual 
provision in the TEN-E Regulation could consider as an example the provisions for transition 
activities  in  the  Taxonomy  Regulation.  The  political  agreement  of  the  Taxonomy 
Regulation70 defines near-zero and transition activities in article 6(1a) as: 

an economic activity for which there is no technologically and economically feasible low 
carbon  alternative,  shall  be  considered  to  contribute  substantially  to  climate  change 
mitigation as it supports the transition to a climate-neutral economy consistent with a 
pathway to limit the temperature increase to 1.5 degrees Celsius above pre-industrial 
levels including by phasing out greenhouse gas emissions, in particular from solid fossil 
fuels, where that activity: 

 

 

 

I. has greenhouse gas emission levels that correspond to the best performance in 
the sector or industry; 

II. does not hamper the development and deployment of low-carbon alternatives; 
and 

III. does not lead to a lock-in in carbon-intensive assets considering the economic 
lifetime of those assets. 

The Taxonomy Expert Group71 considers furthermore that “activities related to dedicated 
storage and/or transportation of any fossil fuels, including gaseous or liquid fossil fuels, 
should not be considered as making a substantial contribution to climate change mitigation, 
as  this  risks  leading  to  lock-in  which  would  undermine  Article  6(1a)”  and  that  “energy 
generation  from  gaseous  or  liquid  fossil  fuels  should  only  be  considered  to  make  a 
substantial  contribution  to  climate  change  mitigation  where  it  meets  the  technical 
screening criteria, which we recommend be set at <100 gCO2e/kWh reducing in five-year 
increments to 0 g CO2e/kWh by 2050.” 

A  final  issue  to  consider  is  the  greenhouse  gases  footprint  of  extra-EU  gas  imports. 
Upstream emissions exist not only for imported gas but also other imported fossil fuels, 
imported biomethane/hydrogen/synthetic hydrogen.  

Member States may import renewable fuels which do not comply with the  sustainability 
criteria  of  the  recast  Renewable  Energy  Directive,  but  are  not  allowed  to  count  those 
towards  their  renewable  energy  targets  -  a  similar  approach  could  be  applied  to  the 
assessment of PCI candidates. The GHG footprint of energy imports could be addressed by 
a  separate  measure  such  as  a  carbon  border  tax.  Nonetheless  the  TEN-E  sustainability 
assessment  could  consider  the  GHG  footprint  to  some  extent.  The  Regulation  could 
establish  minimum  eligibility  criteria  for  gases  in  the  quantification  of  the  sustainability 
benefits of the gas-related infrastructure projects, possibly in alignment with the RED II 
criteria for biogas and renewable fuels of non-biological origin. 

70 European Council (2019) Proposal for a Regulation on the establishment of a framework to facilitate 
sustainable investment - Approval of the final compromise text. COM (2018) 353 final. 
71 Technical Expert Group (2020) Taxonomy: Final report on Sustainable Finance. Available at 
https://ec.europa.eu/info/sites/info/files/business_economy_euro/banking_and_finance/documents/200309-
sustainable-finance-teg-final-report-taxonomy_en.pdf 

65 

 
 
                                                 
Measuring the contribution of gas infrastructure projects to TEN-E sustainability  

Options for possible improvements 

In June 2020 European energy regulators have published a position paper on the revision 
of the TEN-E Regulation.72 Concerning aspects affecting gas-related infrastructure projects, 
the following proposals are of note: 

  Sustainability criteria need to be strengthened so gas projects need to demonstrate 

positive benefits in terms of sustainability of the energy system; 

  To create a carbon dioxide and hydrogen networks group; 

  Maintain the cross-border impact requirement for PCI status, and the list of PCIs at 

a manageable number; 

Our analysis supports especially the first and last recommendations of ACER and CEER. We 
propose  that  the  following  options  for  improvement  should  be  considered  in  the  TEN-E 
Regulation, gas CBA methodology and the sustainability indicator, but should be weighed 
against practical considerations, such as the modelling requirements: 

  Asses the sustainability characteristics of PCI candidates preferably with 
an integrated electricity-gas model in order to fully account for the benefits of 
projects  to  enable  the  integration  of  both  renewable  gas  and  electricity  into  the 
system as well as to consider the electricity-gas systems interlinkages. 

o  This  should  be  preceded  by  short-term  improvements  in  the  CBA 
methodology,  including  by  implementing  the  improved  sustainability 
indicator developed in chapter 2; 

  Consider minimum sustainability criteria for gases in the calculation of the 
projects’ sustainability benefits, using RED II criteria, while also including gases 
with  comparable  carbon  footprints  to  renewable  gases,  such  as  low-carbon 
hydrogen; 

  Use  eligibility  and  assessment  criteria  for  PCIs  to  avoid  a  lock-in  in 
unsustainable  pathways,  considering  the  greenhouse  gases  footprint  of  the 
various gases facilitated by gas-related infrastructure; 

  Consider  developing  an  integrated  hydrogen-electricity-gas  model  if  and 
when  the  scope  of  the  TEN-E  Regulation  is  expanded,  to  include  hydrogen 
systems  when  these  reach  significant  scale  and  interaction  with  other  energy 
infrastructure. Meanwhile, consider hydrogen projects: 

o  Through scenarios; 

o  With verified project-specific data; and/or 

o  At the interface of methane and of electricity systems. 

72  ACER-CEER  (2020).  Position  on  revision  of  the  Trans-European  Energy  Networks  Regulation  (TEN-E)  and 
Infrastructure Governance 

66 

 
 
 
 
 
                                                 
Getting in touch with the EU 

In person 

All over the European Union there are hundreds of Europe Direct information centres. You can find the address 
of the centre nearest you at: https://europa.eu/european-union/contact_en 

On the phone or by email 

Europe Direct is a service that answers your questions about the European Union. You can contact this service: 

– by freephone: 00 800 6 7 8 9 10 11 (certain operators may charge for these calls), 

– at the following standard number: +32 22999696 or  

– by email via: https://europa.eu/european-union/contact_en 

Finding information about the EU 

Online 

Information about the European Union in all the official languages of the EU is available on the Europa website 
at: https://europa.eu/european-union/index_en 

EU publications 

You  can  download  or  order  free  and  priced  EU  publications  at:  https://publications.europa.eu/en/publications. 
Multiple copies of free publications may be obtained by contacting Europe Direct or your local information centre 
(see https://europa.eu/european-union/contact_en). 

EU law and related documents 

For access to legal information from the EU, including all EU law since 1952 in all the official language versions, 
go to EUR-Lex at: http://eur-lex.europa.eu 

Open data from the EU 

The EU Open Data Portal (http://data.europa.eu/euodp/en) provides access to datasets from the EU. Data can be 
downloaded and reused for free, for both commercial and non-commercial purposes. 

 
 
 
 
 
 
 
M

J
-
0
4
-
2
0
-
6
0
4
-
E
N
N

-

doi: 10.2833/395467