Renewable gas - deployment,
markets and sustainable trade
Summary Report of the IEA Bioenergy Intertask project
Renewable Gas: Deployment, markets and sustainable trade

March 2022

Renewable gas - deployment, markets and sustainable trade
Summary Report of the IEA Bioenergy Intertask project“Renewable Gas: Deployment, markets and sustainable trade”

Authors:
Uwe R. Fritsche & Hans Werner Gress, IEA Bioenergy Task 40
with inputs from Christiane Hennig (IEA Bioenergy Tasks 40 & 44), Jan Liebetrau (IEA
Bioenergy Task 37), Rory Monaghan & Stefan Majer (IEA Bioenergy Task 45), Olle Olson (IEA
Bioenergy Task 40)

IEA Bioenergy: Task 40
March 2022
Copyright © 2022 IEA Bioenergy. All rights Reserved

Published by IEA Bioenergy

The IEA Bioenergy Technology Collaboration Programme (TCP) is organised under the auspices of the International Energy Agency (IEA) but is functionally and legally autonomous.
Views, findings and publications of the IEA Bioenergy TCP do not necessarily represent the views or policies of the IEA Secretariat or its individual member countries

CONTENTS

Objectives of the IEA Bioenergy Strategic Intertask Project "Renewable gases - deployment,
markets and sustainable trade" .............................................................................. 4
Overall summary of key findings ............................................................................. 4
Biogas and biomethane ...................................................................................... 4
Non-biogenic renewable gases ............................................................................. 5
Sustainable trade of renewable gases .................................................................... 6

Introduction ..................................................................................................... 7
1. Biomethane .................................................................................................. 8
1.1

Technologies for the production of biomethane ................................................ 9

1.3

Support mechanisms ............................................................................... 10

1.4

Strategies and actions for biomethane development ......................................... 11

1.5

Biogas, biomethane, and CCU ....................................................................11

2. Non-biogenic renewable gases ...........................................................................12
2.1

National strategies for NBRG ............................................................................... 12

2.2

Assessing the State of the Art .............................................................................. 13

2.3

Production costs and commercial readiness ............................................................. 14

2.4

Sustainability aspects of NBRG ............................................................................. 14

2.5

Regulatory barriers .......................................................................................... 15

2.6

NBRG in specific regional contexts ........................................................................ 16

3. Renewable gas trade options and potentials...........................................................17
3.1

Potentials for renewable gas trade ........................................................................ 18

3.2

Regulatory issues of RG trade .............................................................................. 20

References ..................................................................................................... 21

LIST OF FIGURES
Figure 1
Figure 2
Figure 3
Figure 4
Figure 5
Figure 6
Figure 7

Global natural gas production in the IEA Net Zero Emission Scenario .................... 7
Simplified overview of renewable gases production pathways ............................ 7
Gas grid shares of renewable gases in the IEA NZE Scenario ............................... 8
Biogenic gas production by feedstock type, 2018 ............................................ 8
Production potential for biogenic gases by feedstock source, 2018 ...................... 9
Estimated scale of H2 production for selected countries by 2030 ........................12
Shifts in the value of trade in energy commodities, 2020 to 2050 .......................17

LIST OF TABLES
Table 1
Table 2
Table 3Major obstacles for further biomethane market development ...........................10
Different carbon sources’ carbon capture energy requirements. ........................14
Overview of national H2 targets and trade perspectives ...................................192

Abbreviations and Acronyms
BCMbillion cubic meters

BECCS

bioenergy with carbon capture and sequestration

BECCU

bioenergy carbon capture and utilization

Bio-SNG

Synthetic Natural Gas from biomass

BY

Belarus

CCS

carbon capture and sequestration

CCU

carbon capture and utilization

CH4

methaneCO2

carbon dioxide

DNV-GL

Det Norske Veritas group - German Lloyd

EBA

European Biogas Association

EC

European Commission

ERGaR

European Renewable Gas Registry

ERIG

European Research Institute for Gas and Energy Innovation

EU

European Union

GfC

Gas for Climate

GHG

greenhouse gas(es)GOGuarantee of Origin

H2(molecular) hydrogen

ICCTInternational Council on Clean Transportation

IEA

International Energy Agency

IEA BioInternational Energy Agency Bioenergy Technology Collaboration Programme

IEA H2

International Energy Agency Hydrogen Technology Collaboration Programme

IPCC

Intergovernmental Panel on Climate Change

IPHE

International Partnership for Hydrogen and Fuel Cells in the Economy

IRENA

International Renewable Energy Agency

ISO

International Standardization Organization

JRC

European Commission Joint Research Centre

LH2liquefied hydrogen

LHV

lower heating value

LNG

liquefied natural gas

Mt

million tons

NZE

net zero emission

PtG

power-to-gas

REGATRACE

Renewable Gas Trade Centre in Europe

RG

renewable gas(es)RU

Russian FederationSMsynthetic renewable methane

SNG

Synthetic Natural Gas

TRL

Technology Readiness Levelvol%per cent by volume

UA

UkraineUK

United Kingdom

US

United States of America

3

Objectives of the IEA Bioenergy Strategic Intertask Project"Renewable gases - deployment, markets and sustainable trade"
The IEA Intertask project concerns the prospects of implementing renewable gases (RG) in theenergy markets of IEA countries, and beyond. The aims of the RG project are to••provide state-of-the-art overviews on prospects, opportunities and challenges for various
mechanisms that could help deploying biogas, biomethane and other renewable gases inenergy markets in IEA countries (e.g., green gas certificates), and beyond
discuss technological and sustainability issues of RG from a deployment perspective andderive respective recommendations for policymakers.

The project aims to provide decision makers and the research community with a comprehensive
overview of what is currently known regarding renewable gases, considering both technology
development/infrastructure and which mechanisms exist and are considered to fulfil theimportant role of renewables gases in global climate scenarios for a well-below 2°C world.

Overall summary of key findings
This summary report compiles the key findings from the RG Intertask project 1.

Biogas and biomethane
Renewable gases (RG) will be key components of a global energy system aiming at net zero
greenhouse gas emissions by 2050 (IEA 2021a). IEA’s World Energy Outlook (WEO) indicatesthat global gas demand will be decreasing in emission reduction scenarios. There is agreementthat among renewable gases, biomethane and hydrogen (H2) will be most critical. Biomethane
is the largest contributor to low-carbon gas supply in the WEO scenarios. As biomethane isnearly pure methane, it can be used without any change in natural gas transmission anddistribution infrastructure or end user equipment.
Regarding biomethane feedstocks, a survey within selected countries revealed that almost all
countries which support anaerobic digestion (AD) incentivise the use of manure and wastematerials. The use of energy crops is not as much common and even when eligible for incentives they are not utilized everywhere due to conditions of the incentive system. Energy crops
are costly and discussed controversially, with sustainability aspects and land use being themain issues. Intercropping avoids some of the issues, and the trend is away from energy crops.
Biomethane provision based on AD processes is a proven technology with numerous
applications worldwide – with a variety of substrates used and technologies for gas
production, upgrading and utilization. In recent years major progress has been accomplishedin the reliability and efficiency of the upgrading technologies. When looking at technology
used for upgrading, an increasing market share of membrane separation technology in regardsof number of plants is apparent.
With cost reduction achieved by wind and photovoltaics, the gap to electricity costs frombiogas is getting bigger. As an effect, biogas-based electricity is more expensive and only1

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economic with higher feed-in tariffs than for wind and solar. Currently, biogas use is dominated by combined heat and power units. Since upgrading and grid injection is costly forsmaller-scale sites, CHP will remain the technology of choice for those aiming at high heatutilization and flexible electricity provision to balance market prices.
Under current market conditions, biomethane is not cost-competitive to most fossil energy
carriers, e.g., natural gas. However, the basis of comparison for renewable energy carriers in
the future needs to consider the necessary reduction of CO2 emissions, and therefore, thelong-term transition to a decarbonized economy requires CO2 pricing. The transition process
will change the overall demand in energy forms and carriers as e.g., electricity, gaseous andliquid fuels. Up to 2050, competition of technologies for producing gaseous energy carriers
will be driven by overall demand, production costs (including CO2 price), and availability oftechnical alternatives. Any support should consider the availability of necessary infrastructure
and technology options for gas utilization.
Due to the current lack of a comprehensive and cross-sectoral CO2 pricing, support fordeveloping renewable gas needs to balance the shortfall between the revenues for the
product and the financial effort for the production. There are numerous systems andapproaches to incentivise the production or the utilization of biomethane. With an obligatory
development target for renewable fraction of the market, set e.g., by a quota, a definedmarket share for renewables can force a development. Yet, a proper timing of the shift fromprotected technology development phase to competition is crucial to avoid “lock in” effects.
In the long-term, any support mechanism shall be replaced by a competitive market scheme.
Strategies and incentives to develop the sector need to reflect the available substrates forbiomethane production, the specific costs for the improved access of substrates and gas
provision. Since the investment has usually long amortisation periods, the duration of
temporal guarantee of the incentive is highly important. Biomethane can contribute but notsatisfy the demand for renewable gas completely. Therefore, the interaction and compatibility with other renewable gases such as H2 is highly recommended. Technologies which can be
combined with biomethane plants as Power-to-gas need to be included in the strategy tocapitalize on synergies and enable most benefit in regards of greenhouse gas abatement,
considering existing and needed infrastructure (e.g., natural gas grids).
Biogas upgrading to biomethane is also a valid source of CO2 for bioenergy with carbon
capture and sequestration (BECCS) which achieves negative CO2 balances, and for bioenergy
with carbon capture and utilization (BECCU) which delivers CO2-neutral products.

Non-biogenic renewable gases
Non-biogenic renewable gas (NBRG), encompassing hydrogen (H2) produced by electrolysis
powered by renewable electricity and potential subsequent methanation with capture of CO2,
are potential routes to decarbonize energy and chemical feedstock use, especially in hard-toabate sectors. A growing number of countries developed national H2 strategies to position H2 intheir decarbonization plans, some include non-biogenic renewable methane (RM). Most strategies focused on green H2 expect that its first deployment will be in industries that alreadyconsume fossil-derived H2 such as oil refining, and fertilizer and chemicals production; a focus
on aviation, shipping, and long-range heavy duty trucks; a focus on the co-benefits of H2 use
including reduced GHG emissions, improved air quality, reduced reliance on fossil fuel imports.
The analysis conducted in this report considers regional case examples in the North Sea, Texas,
and Brazil to illustrate how local factors such as renewable electricity resource, electricity grid
GHG intensity, potential CO2 source type, and other factors affect NBRG economic feasibility(measured by levelized cost of gas), environmental sustainability (measured by GHG intensity of5gas), and the cost of abating CO2 emissions using NBRG. The use of excess electricity to powerelectrolysis is cost-ineffective due to low electrolyser capacity factors caused by the infrequent
availability of excess electricity. On the other hand, the economic and environmental feasibilityof using grid electricity to maintain high electrolyser capacity factor show strong dependences
on regional factors including the price of grid electricity and its GHG intensity.
In the North Sea, H2 produced from grid electricity has the lowest carbon abatement cost in 2030
(170 $/t CO2), but by 2050 is overtaken by H2 produced by dedicated offshore wind (140 $/t
CO2). This is mostly due to the expected decrease in offshore wind electricity price andsimultaneous increase in grid electricity price. In Texas, which possesses abundant wind andsolar resources with high combined capacity factor, H2 produced from dedicated renewables
achieves abatement costs of 180 $/t CO2 in 2030 and 110 $/t CO2 in 2050. Similar trends are seenin Brazil, with H2 produced from dedicated biomass electricity achieving abatement costs of 130$/tCO2 in 2030 and 100 $/t CO2 in 2050. Expected ranges of levelized costs of H2 by region are:
4-7 $/kg in 2030 and 3-6 $/kg in 2050 for the North Sea; 4-10 $/kg in 2030 and 3-8 $/kg in 2050
for Texas; and 8-12 $/kg in 2030 and 6-12 $/kg in 2050 for Brazil.
In all cases, methanation of H2 using captured CO2 to renewable methane (RM) significantly
increases abatement costs, but this must be balanced against the benefits of being able to use
existing natural gas infrastructure and appliances. For methanation using CO2 sourced fromdirect air carbon capture (DACC), high capital and operating costs of DACC lead to high CO2
prices and, thus, to high abatement costs for RM. The lowest abatement costs for RM are seen
for CO2 captured from biomethane and bioethanol plants, which combine CO2 of renewable
origin with relatively low CO2 capture price due to high CO2 concentration in off-gases.
Another finding is that situating electrolysers close to renewable electricity sources is more costeffective than situating them close to H2 demand centres since it is cheaper to move energy via
new H2 transmission pipelines than via electricity transmission lines. Finally, the analysis showsthat the lower ends of carbon abatement cost ranges are similar to carbon tax proposals inseveral of countries, indicating the feasibility of NBRG in national decarbonisation strategies.

Sustainable trade of renewable gases
Renewable gases will be key components of a global energy system aiming at net zero greenhouse gas emissions by 2050. RG will have to strongly increase, and international trade may
become an important component of decarbonizing the global energy system. International tradeof RG can be either physical through gas pipelines (or as liquefied gases in ships), or virtual
through the exchange of certificates such as Guarantees of Origin.
In the short- and medium term, biomethane is the major RG being traded internationally, andprospects for further growth are significant in Europe but also in Latin and North America andSouth-East Asia, where current trading is rather low.
In the longer-term, “green” H2 has a high potential for international RG trade. The 2050 potential green H2 exporting countries are seen as those offering low-cost renewable electricity for H2
production, i.e., wind- and sun-rich regions with access to international pipelines and/or ports in
Africa (e.g., Morocco), Europe (Portugal, Spain), Latin America (e.g., Chile), Middle East (e.g.,
Saudi-Arabia), and Oceania (Australia and New Zealand). H2 trade will rely on existing gas pipelines and new dedicated H2 pipelines, or transport with ships (ammonia, LH2). Up to 1/3 of green
H2 will be traded internationally by 2050, a share slightly higher than the current share ofnatural gas traded globally.
For trade of green H2 and its derivatives, regulatory hurdles remain, especially the definition of“greenness” and respective GHG emission thresholds, but ongoing work in the EU and internationally aims to address these issues.
6

Introduction
Renewable gases (RG) will be key components of a global energy system aiming at net zero
greenhouse gas emissions by 2050 (IEA 2021a). With fossil gas supply peaking in the mid-2020ies
and shrinking fast up to 2050 (Figure 1), RG will have to strongly increase, and international
trade may become an important component of decarbonizing the global energy system (Daioglou
et al. 2020).

Figure 1

Global natural gas production in the IEA Net Zero Emission Scenario

Source: IEA (2021a); bcm = billion cubic meters (approx. 40 PJ)

Several pathways exist to provide renewable gases, as depicted in Figure 2.

Figure 2

Simplified overview of renewable gases production pathways

Source: Fritsche (2022); renewable synthetic methane (SM) is also referred to as renewable methane (RM)

7

The IEA NZE scenario assumes a major role for renewable gases, especially for biomethane, butalso for H2, and H2-based synthetic methane (Figure 3).

Figure 3

Gas grid shares of renewable gases in the IEA NZE Scenario

Source: IEA (2021a)1.

Biomethane

Biomethane is the largest contributor to low-carbon gas supply in IEA’s World Energy Outlook
Scenarios (IEA 2020a) and a key component of future energy technology developments (IEA
2020b + 2021).
Currently, biogenic gases only play a small role in the global system, with Europe and China
being the largest suppliers, followed by the US (Figure 4).

Figure 4

Biogenic gas production by feedstock type, 2018

Source: IEA (2020b); Mtoe = million tons of oil equivalent (41.9 PJ); * = Crops include energy crops, crop
residues and sequential crops

The potential for biogenic gases, excluding dedicated annual crops, is shown in Figure 5 – Asianand American countries dominate, followed by Europe and Africa. More regionalized analysis on
biogas is available (Dale et al. 2020; GBEP 2020).

8

Figure 5

Production potential for biogenic gases by feedstock source, 2018

Source: IEA (2020c); Mtoe = million tons of oil equivalent (41.9 PJ); C&S America = Central and SouthAmerica. Woody biomass feedstocks are available only for biomethane production (throughgasification or pyrolysis). Note that the potentials do not reflect mobilization restrictions, norcost issues

Biomethane is nearly pure methane and can be used without needing any changes intransmission and distribution infrastructure or end user equipment (FE & IAEW 2019; Fritsche
2022; IEA 2020b).

1.1

Technologies for the production of biomethaneTechnologies for production of biomethane as a renewable gas are anaerobic digestion (AD) andgasification processes. Biomethane provision based on anaerobic digestion processes is a proventechnology with numerous applications worldwide – with a variety of substrates used andtechnologies for gas production, upgrading and utilization. In recent years, major progress has
been accomplished in the reliability and efficiency of the upgrading technologies. Increasingly,
membrane separation is applied in EU countries.
Since biogas plants are highly individual and represent many components and contractors, and as
they are limited in size due to substrate supply and digestate logistics, the future overall cost
reduction potential based on higher efficiency of components is limited.
With cost reduction achieved by wind and photovoltaics, the gap to electricity production costs
from biogas is getting bigger. As an effect, biogas-based electricity is more expensive and only
economic with higher feed-in tariffs than for wind and solar. Within the renewable gas sector,
the situation is different, currently available alternatives are not necessarily cheaper andconsequently the trend of biogas utilization is moving towards renewable gas applications.
Due to different and in the course of time changing incentive systems, the development of thesector has been neither temporal steady nor evenly spread in the regions of the world. However,9whenever conditions are in favour for biogas or biomethane sector, plants have been quickly
built and the sector has been developing since experience and knowledge for reliable technology
with a predictable constructions and operational costs are available.

1.3

Support mechanisms

Under the current market conditions the provision of renewable biomethane is not costcompetitive to the provision of e.g., natural gas. However, the basis of comparison for renewable energy carriers in the future needs to be different than sole production costs. The
necessary reduction of CO2 emissions requires additional instruments and therefore in the longterm the transition to a decarbonized economy requires a pricing of CO2 of any kind.
Many countries apply several mechanisms – either specific to a region or an energy sector – yet,developing successful biomethane applications is independent from the specific support
mechanism. The support mechanism or incentive come into action at different points of the
productions process – starting with the support of specific substrate utilization (e.g., incentives
for manure utilization), the production process itself (investment support, feed-in tariff for thegas, quota systems for gas in the grid) and/or the final gas utilization (quota systems in specificsectors for gas utilization as transport, feed-in tariffs for electricity, tax exemption for target
sector etc.). The support systems differ additionally in the resulting financial compensation, theone-time (mostly investment support) or operation related grant and in the latter case very
important- the guaranteed period of the grant.
The decision for or against the investment are made by weighing potential financial profit,
positive co-benefits, legislative hurdles, and technical risks. Major driver for the success of a
support scheme is the chance for the entrepreneur to make a profitable business case. Technicalrisk and legislative hurdles might have a certain impact but are usually to be overcome ifinterest of stakeholders to build plants is given.
Most participants of a survey vote for economics when asked what hinders the market
development most. Combining this statement with the abovementioned incentive systems, it
becomes obvious that for the development of a national industry the type of mechanism is notdecisive, it is the fact if an economic business case is possible or not. In countries where thesupport for the installation is based on a realistic cost assessment and the legislative conditions
do not represent a unbreachable obstacle, the sector develops.

x

SwedenSwitzerland

UKx

NorwayxLegislative (framework conditions other than financial
and technological)

India

Legislative (regulations regarding technology andplant operation)

GermanyxFinlandx

Estonia

Financial

China

CanadaMajor obstacles for further biomethane market development

Australia

Table 1

x

x

x

x

x

x

x

x

x

x

x

x

x
x

x
x

Source: own compilation: x = agreed

Some countries decide to target - based on national, sectoral abatement targets - a specific gas
utilization sector (e.g., transportation or electricity). The gas is directed with the incentive
system and technical requirements to the desired sector. One aspect of the implementation isthe certification or proof of eligibility measures specific to the target sector. Due to the specific10arrangement of these systems and a certain complexity, a quick redirection of produced
biomethane to other sectors requires new procedures and conditions for eligibility – althoughtechnically the gas can be applied in many sectors. In order to avoid “lock in” effects, any
certification system shall be compatible to other sectors of use.

1.4

Strategies and actions for biomethane development

Many countries recognize the need for renewable gas as a major energy carrier for future energy
systems, often with a focus on H2, although many countries update their incentive systems forbiomethane as well. In all countries, the potential of available biomass (excluding energy crops)
exceeds currently used sustainable substrates by far, i.e., biomethane production can increase.
Yet, biomethane cannot satisfy the demand for renewable gas completely. Therefore, theinteraction and compatibility with the development of hydrogen is highly recommended. Last
but not least, existing and new infrastructure (e.g., gas grids) shall be part of the strategies.
The main fields of action for the development of biomethane as a renewable gas are:
•
•
•
•
•

Create strategies for biomethane sector development, including the consideration ofavailable substrates and development costs, defined development targets andconsideration of needed infrastructure
Obligatory market implementation by means of a quota is the most effective way of
introducing renewable gas under the current conditions
Incentives which reflect costs and long-term operation (amortisation) conditions andprovide a secure market environment for the run up of technologies
Dismantling of inhibiting regulations on technical and regulatory level
Compatibility with other measures to develop renewable gas sector and downstream
technologies (e.g., PtG)

In the long-term, the technology and sector specific support schemes need to be transferred into
an overall market scheme resp. an economy where CO2 emissions have a monetary value.
According to reduction targets and technology development the price for CO2 will develop anddrive the transformation.
Such a system will include competition of technologies and shifts between energy sectors andconsequently the phase out of specific incentives. Any incentive system set today shall be
scrutinized for transferability into such a future economy.

1.5

Biogas, biomethane, and CCU

Building renewable fuels, chemicals and materials based on CO2 and H2 is a rapidly expanding
field. One of the basic carbon capture and utilization (CCU) products is also one with the largest
current market, namely methane (CH4) which is the main component in natural gas and a widelyused feedstock in the chemical industry.
There are some volumes of renewable methane being produced already today, although notprimarily via the CCU route but as a key component of different renewable gases produced frombiomass.
Biogas upgrading to biomethane and syngas from biomass gasification are valid sources of CO2 forbioenergy with carbon capture and sequestration (BECCS) which achieves negative CO2 balances,and for bioenergy with carbon capture and utilization (BECCU) which delivers CO2-neutral
products.

11

2.

Non-biogenic renewable gases

Non-biogenic renewable gases (NBRGs) encompass hydrogen produced from electrolysis poweredby renewable electricity, or from direct solar water-splitting, or methane produced by
combining H2 with CO2.
If this NBRG incorporates H2 produced by electrolysis powered by renewable energy (green H2),
it can enable sector integration, and enable indirect electrification of hard-to-abate sectors.
Sector integration is key to decarbonising energy use beyond the electricity sector. The potential
of NBRG to meet decarbonisation objectives has been recognised in the EU’s Hydrogen Strategy
for a Climate Neutral Europe, which envisions 40 GW of green H2 production in the EU by 2030,
with a further 40 GW in neighbouring countries supplying the EU (EC 2020). Methane produced
from CO2 captured from the atmosphere or a biogenic process is renewable methane (RM).
Demand for hydrogen in 2020 was approximately 90 Mt, of which roughly 5% was produced byelectrolysis. Of the electrolytic share, only a small portion was green hydrogen (IEA 2021b). The
IEA projects that global consumption of hydrogen could exceed 200 Mt in 2030 and 500 Mt by
2050, in a zero-emissions scenario.

2.1

National strategies for NBRG

No country or region has an explicit strategy for NBRG, but many have developed, or aredeveloping, hydrogen strategies. The planned estimated scale of H2 production for selected
countries is shown in Figure 6. Countries that have large scale hydrogen production for export
plans in their strategies and roadmaps are Australia, Canada, Chile, Portugal and Spain.

Figure 6

Estimated scale of H2 production for selected countries by 2030

Source: adapted from Fritsche et al. (2022)

Most H2 strategies focus on zero- or low-carbon, with green H2 from water electrolysis poweredby renewable electricity, and blue H2 from natural gas reforming with CO2 capture and storage,as the main technologies. Only Canada explicitly references biomass gasification as a H2 route.
Most of the strategies/roadmaps except for Russia show H2 use in the transport sector. Other
uses are industry (including chemicals and steel for some countries), electricity, refining andbuildings. A few strategies consider aviation and shipping, with only 2 strategies (Canada andChile) mentioning the use of H2 in mining.
It is estimated that by 2030, about USD 50 billion of global investment and 65 GW of electrolyser
capacity will be required to bridge the cost gap between grey and green H2, equivalent to 6.6 Mt
of H2 (WEC 2021).

12

2.2

Assessing the State of the Art

H2 and methane are two common compounds used in many industrial sectors around the world.
They can be produced in different ways and the pathway selected for their production determines if they are considered renewable or not. For H2, it will be renewable if it is produced fromwater by means of electrolysis driven by renewable electricity, or from biomass. H2 end uses
include combustion or electrochemical conversion in a fuel cell, or conversion to a chemical
product. In the case of non-biogenic methane, it can be generated by the Sabatier methanation
reaction, which combines H2 and CO2. If the H2 is renewable and the CO2 originates from arenewable, non-fossil source, e.g., direct air capture (powered by renewables) or biogenic CO2,
the resulting methane can also be considered renewable.
To better identify the most relevant topics related to NBRG, a survey and a workshop werecarried out to summarize the technological, environmental, social, and political issues that
NBRG chains entail. The key environmental sustainability issues raised by respondents that are
relevant for the assessment of H2 pathways are: the additionality and certification of renewableelectricity for green H2 and the climate effects of CO2 used for PtX production. Freshwater
availability, land-use concerns for greater renewable electricity requirements, and the global
warming potential of H2 itself were also raised.
2.2.1 Renewable hydrogen from electrolysis and photocatalysis
The two most commercialised electrolyser technologies that are projected to dominate thefuture of this hydrogen production route are alkaline and polymer electrolyte membrane (PEM).
Direct H2 production from solar irradiation has a TRL of 7, which is lower than electrolysis (FSR
2021), and has lower efficiencies than PV generation and electrolysis of water (Nishiyama et al.
2021). On the other side, it presents promising characteristics for scaling up, being potentiallycheaper and simpler than other H2 production systems (Nishiyama et al. 2021).
2.2.3 Methanation in Renewable Methane production
Methanation is the process of producing methane using carbon dioxide and hydrogen as
feedstocks. The process can be driven by biological or chemical systems, but since the biologicalprocess is slower and less developed, this report is focused on the chemical route.
The origin of CO2 is an important parameter for assessing the GHG intensity of RM. The carbon
source can be classified as renewable if it is biogenic CO2 or from direct air capture, while nonrenewable CO2 comes from fossil sources such as powerplants or steel works fuelled by fossil
energy, and cement production flue gases. The origin of CO2 will also influence the cost of the
carbon capture process. The use of renewable energies in the carbon capture process is crucial
to ensure a low carbon footprint of the CO2 used as feedstock for methanation.
Some studies indicate that RM Methane can be economically competitive in 2030 if electricity
prices are low enough (30 EUR/MWh), and if CAPEX and OPEX decrease due to technology
development (Gorre et al. 2019). Thus, the methanation field is expanding with several projects
planning to be in operation by the end of this decade (Thema et al. 2019).
2.2.4 Renewable hydrogen and methane end-use
Currently, H2 is mainly used in the chemical industry and refineries (IEA 2021b). This means, thatthe first sector in which green hydrogen can help to abate GHG emissions. In parallel, H2 can beused to store renewable electricity and reduce curtailment (IEA 2021b). Long range heavy-dutytransport, including trucking, shipping, and aviation, are hard-to-abate sectors with highoperating costs that represent major opportunities for H2. Supply of high-temperature heat andfeedstock to industry represents a further route to market. There is also a potential role for H2
to supply heat to the built environment, although in this sector, it faces very stiff competition
from other decarbonisation options, especially heat pumps.
13

2.3

Production costs and commercial readiness

The levelized costs of production of renewable H2 and RM depend strongly on location and time
factors. Electricity is a significant portion of the cost of NBRG, accounting for 50-90% of the total
production costs (IEA 2021b). Projections for the future cost of methanation are not widespread,since this will depend directly on the hydrogen production costs. For example, Gorre et al.
(2019), calculated the production cost of Renewable Methane in 2030 and 2050 for different
scenarios at 20-200 EUR/MWh of methane. This illustrates that the production cost of NBRG is an
open issue.
The main electrolysis technologies of alkaline and PEM have TRLs of 9, meaning that they arecommercially deployed. Other technologies, such as Solid Oxide Electrolyser Cells, have TRLs of
6-7. The power-to-gas process is also in a lower commercial readiness with a TRL of ~6.

2.4

Sustainability aspects of NBRG

NBRG can contribute to abate GHG, however, the actual GHG mitigation effects depend on the
GHG intensity of the inputs of the system. As for the production of NBRG, the electricity used in
the production processes and the carbon source for the methanation are the two main sourcesthat are key for abating carbon emissions with NBRG.
The production of NBRG can be driven mainly by two types of systems, 100% renewableelectricity (dedicated or curtailed), or connected to the electricity grid. For the latter case, theenergy mix of the grid varies with place and time, which means that the carbon intensity of theelectricity is not necessarily constant and difficult to predict.
The various certification schemes have suggested limits or thresholds for GHG emissions of NBRG
production to declare those gases “low carbon” products (Fritsche 2022).
In the case of methane produced from CO2 and H2, the CO2 used will carry emissions by itself asa potential direct emission after the burning of the produced methane, and due to the processof capture and purification. The direct emissions can be considered as net-zero if the CO2 comesfrom a renewable source. In addition to the emissions from the production and the conversion of
NBRGs, incomplete conversion processes (e.g., combustion) or leakage from infrastructure orslip in conversion processes can lead to direct emissions of NBRGs. Depending on the type of the
NBRG, this can result in direct or indirect climate effects.

Table 2Different carbon sources’ carbon capture energy requirements.
Carbon source

Energy required (kJ/kgCO2)

Direct air carbon capture

3500–9900

Biomethanol upgrading

288–432

Bioethanol production

432

Natural gas power plant flue gas

288–432

Cement plant

288–432

Source: own compilation

14

References and notes
Value depends on the type oftechnology (Chatterjee & Huang
2020)
Assuming post-combustion carbon
capture technologies (Jackson &Brodal 2019)(Moreira et al. 2016; Pace &Sheehan 2021)
Assuming post-combustion carbon
capture technologies (Jackson &Brodal 2019)
Assuming post-combustion carbon
capture technologies (Jackson &Brodal 2019)

Since methane is a potent greenhouse gas and methane emissions are a key contributor toclimate change, aspects of direct emissions from methane slip or leakage are of high relevancefor the development of future NBRG capacities and infrastructure. Furthermore, besides theidentification and quantification of direct methane emissions, the selection of the time frame
and the climate metrics can have a strong impact on assessment results.
Contrary to methane, hydrogen is not a direct greenhouse gas. Besides emissions related to the
production of hydrogen as an energy carrier, a complete conversion of hydrogen to energy would
result only in water vapour. However, incomplete hydrogen combustion as well as hydrogen
emissions from distribution infrastructure and throughout the value chain can potentially cause
climate impacts (Bond et al. 2011; Weger et al. 2021). Hydrogen is considered an indirect
greenhouse gas. (Derwent et al. 2006 + 2020; IPCC 2007; Schultz et al. 2003). Furthermore,hydrogen emissions can influence O3 concentrations, leading to additional potential impacts on
air pollution and a potential contribution to the depletion of the O3 layer in the stratosphere(Sand et al. 2020)
Electrolysis, consumes 9 kg of water per kg of H2 versus 13-18 kg of water per kg of ”blue” H2 for
SMR with CCS (IEA 2021b). Nevertheless, availability of freshwater for electrolysis is a concern inseveral places that are rich in renewable sources but suffer from water scarcity or stress, suchas Northwest Texas, the Atacama and Sahara Deserts, or Australia. In regions that are near thesea, reverse osmosis seawater is a non-expensive option, because it affects the levelized cost of
H2 by less than 1% (Gallardo et al. 2021; IEA 2021b).
The land footprint of NBRG production will depend on the electricity source and the electrolysis
and methanation installation. The land use of the renewable electricity used for the NBRG
production varies according to the source, wind being the least intensive in land-use terms witharound 1 m2/MWh delivered, followed by geothermal with 2.5, solar PV and hydropower with
10.15 for concentrated solar power, and 500 m2/MWh for biomass (Fritsche et al. 2017).
With H2 production driven mainly by onshore and off-shore wind farms, the respective land
footprint is not a main issue to be considered. Even if the projected global H2 production of 530
Mt were driven by onshore wind, a surface of just 25.000 km² would be needed.

2.5

Regulatory barriers

Certification
Ensuring that NBRG are low in emissions is one of the key points of the production and trade ofthese goods. A standardized methodology that allows entities to certify low GHG emissions of
NBRG is crucial for the development of the market. Some countries, such as Australia, the UK,
and the EU, are working on certification schemes for H2 (Bermudez et al. 2020), and IPHE works
on methodology for determining the GHG emissions of H2 production. An important element of
the certification for NBRGs is to establish coherent instruments that allow traceability of
product information (e.g., the guarantee of origin of the electricity used, the origin and climate
effects of CO2) throughout the value chain elements.
Additionality
Achieving ambitious targets for renewable gases will require a significant amount of renewableelectricity, which is also needed for the decarbonization of several other industrial sectors. So,
in order to avoid that the electricity demand for hydrogen becoming a drain on existing
renewables in the energy system, the growing demand needs to be matched with new capacities
of renewable electricity (Fritsche 2022). Thus, the EU framework for the support of renewableenergy (EU Renewable Energy Directive) requires that to be accounted as renewable, electricity
used for the production of renewable energy carriers has to be “additional”. In that sense,
Pototschnig (2021) defines the concept of additionality as “the requirement that renewablesbased electricity used in electrolysers for the production of renewable hydrogen is additional to15

the renewables-based electricity which is used to meet the renewable penetration target withrespect to final electricity consumption”.
In practice, the proof of compliance with the additionality concept, which is an important factor
for the GHG mitigation potential of the energy carrier and thus, the respective sustainability
criterion of the RED, is verified by means of a certification process. Fritsche (2022) argues forthe need of additional delegated regulations under the RED II which shall provide stakeholders
more clearance on how to understand which scenarios for electricity supply (direct connection
to an installation producing renewable electricity, grid connection, etc.) can be consideredadditional and thus, be accounted as renewable electricity in the calculation of the GHG
intensity of the Hydrogen produced from it.

2.6

NBRG in specific regional contexts

All cases are selected so that NBRG is produced and used in the same country, or within the EU.
We are therefore omitting international trade of NBRG, which, as stated above, is covered in
Section 3. The cases consider renewable electricity generation, water electrolysis, H2 storage,
possible CO2 capture and methanation, electricity/ H2/methane transmission and delivery to
end-users. Three possible classifications of electricity source are considered in the analysis:
1.

Excess renewables: In this classification, only renewable electricity that would otherwise be wasted
or curtailed is used to power the electrolyser.
Dedicated renewables: In this classification, the sole purpose of a renewable energy generator isto supply hydrogen as opposed to electricity.
Grid electricity: In this classification, the capacity of the electrolyser is maximized by connecting
it directly to the electricity grid.

2.
3.

The key findings can be summarized as:
•

•

•
•
•

•

•

Use of dedicated offshore wind in the North Sea and an onshore wind-solar mix in Texas results inhigh electrolyser capacity factors and delivered hydrogen costs of 4-6 USD/kg in 2030, which ishighly dependent on the cost trajectory of wind. By 2050 in the North Sea and Texas, dedicatedrenewable hydrogen production is the cheapest option studied.
For the Brazil case example, the lowest delivered cost hydrogen production route was for biomassgenerated electricity, which has lower electricity price and decent capacity factors, resulting in agreater dependency on electrolyser cost reductions. By 2050, biomass-generated electricityhydrogen in this case study is the most competitive option.
Use of excess electricity alone results in high levelized costs and abatement costs, despite having avery favorable GHG intensity.
Renewable H2 GHG abatement costs in some scenarios are comparable to proposed carbon taxes insome countries.
Renewable methane produced using CO2 from DACC results in unfeasibly high levelized carbon
abatement costs. Renewable methane produced using non-renewable CO2 has greater GHG intensity
than fossil natural gas, but this finding depends strongly on the method of GHG emissions accounting
employed.
Using existing natural gas pipelines could decrease the levelized cost of renewable methane, but it
remains significantly more expensive than hydrogen for all scenarios and case examples studied.
Situating electroIysers close to renewable electricity generation sites is desirable since it is morecost effective to transmit hydrogen in pipelines that it is to transmit electricity in high voltage
cables.

16

3. Renewable gas trade options and potentials
The two main RG options for trade are biomethane and “green” hydrogen 2. Trade is a vital
component of the current global energy system, and the transformation towards a renewable,
zero-carbon system will affect future trade patterns drastically, yet with only a small change inoverall amount, as shown in Figure 7.

Figure 7

Shifts in the value of trade in energy commodities, 2020 to 2050

Source: IRENA (2022)

Trading of RG between countries or regions requires the physical movement of the respective
gases, or the virtual transfer of RG quantities from one country to its trade partner country
through certificates, either per “book & claim”, or mass balancing approaches.
The physical trade of RG can have two modes:
Domestic RG is injected into gas pipeline within the exporting country, and transport between
countries is carried out through high-pressure pipelines, or in liquefied form through shipping(Bio-LNG or LH2). In the latter case, the liquefied RG is regasified in the receiving port andinjected into the national gas grid of the importing country 3. Biomethane and SM can be usedwithout limitation in natural gas infrastructure, including liquefaction plants (IEA 2020).
In contrast, there is currently not much infrastructure for H2 transport, but when blending H2
with natural gas, existing systems could be used, within a limit of max. 20 vol% (Fritsche 2022).
The virtual trade of RG through certificates is not hindered by infrastructure constrains but bylacking agreements on requirements and governance of systems used to certify RG. Several
systems not fully compatible nor being agreed internationally were developed, but standardization bodies such as CEN and ISO are working on it (Fritsche 2022). For the sustainable RG tradepotentials, the mode of trade is not relevant, though.

2
3

Either as gaseous or liquefied H2 resp. synthetic renewable methane.
Note that for small quantities and distances, liquefied RG can also be transported in specialized trucks.

17

3.1

Potentials for renewable gas trade

Trading of RG is still in an early stage – yet, as Thrän et al. (2014) indicated and Junginger et al.
(2019) confirmed, there is growing trade in biomethane especially in Europe 4, and much interestin that in other parts of the world (see Section 3.1.1).
For hydrogen and derived products, IRENA (2022) discusses global and Wang et al. (2021)
European perspectives for respective trade in the 2050 timeframe (see Section 3.1.2). The
analysis of H2 strategies and roadmaps given by Fritsche (2022) provides perspectives ofcountries’ ambitions. The 2050 potential green H2 exporting countries are seen as those offering
low-cost renewable electricity for green H2 production via electrolysis, i.e., wind- and sun-richregions with access to international pipelines and/or ports in Africa (e.g., Morocco), Europe(Portugal, Spain), Latin America (e.g., Chile), Middle East (e.g., Saudi-Arabia), and Oceania(Australia and New Zealand). Yet, the quantification of future H2 trade potentials is still at the
beginning.
3.1.1 Biomethane
Today, Europe is the main producer of biomethane (IGU 2021; Liebetrau, Fritsche & Gress 2021).
Europe also holds significant biomethane domestic potential (Birman et al. 2021). Several studies
calculated the biomethane potential in the European Union (EU27) for 2030 and 2050 and estimated the potential to be around 350 TWh by 2030, and up to nearly 1,000 TWh in 2050 (Birman
2021; GfC 2021). These figures show the total methane potential from anaerobic digestion andgasification without considering whether the gas is used domestically as biogas for on-site
electricity production, or whether it is upgraded to biomethane and injected into the gas grid. In
2020, biomethane production (32 TWh) accounted for only 17% of total biogas production (191TWh) in the EU (EBA 2021).
So far, the volumes of biomethane traded among EU countries are rather small - about 3 TWh in
2020 (dena 2021), corresponding to 0.06 % of natural gas consumption in the EU. Given theextensive natural gas infrastructure existing in Europe, the ambition of the EU to increase its
renewable energy share and decrease GHG emissions on the one hand, and the significant
agricultural and forest resources of Eastern European countries and Russia on the other hand,several studies tried to identify the export potential for biomethane from this region (Angelova
2012; Angelova et al. 2012; Fritsche & Iriarte 2016; GfC 2021).
Recent work for the German National Energy and Climate Plan estimated global export potentials for biomethane (Kemmler et al. 2020), building on earlier work (Fritsche & Iriarte 2016),
and identified biomethane export potentials for 2030 from (Western) Russia of about 1250 PJ,
and for UA of 500 PJ. In a projection towards 2050, these export potentials were reduced due torising domestic demands to about 950 PJ (RU), and 400 PJ (UA). These potentials considered only
biomethane from abandoned/marginal land, and future domestic uses were subtracted from theexport potential. For the Ukraine, BAU (2021) expects biomethane exports as an option, but thecurrent political situation in this country and in Russia does not allow to assume much by 2030.
In a post-war long-term perspective, economic cooperation of the EU with Russia and the
Ukraine may include biomethane trade to avoid “stranded assets” in the gas transmission
infrastructure.
Outside Europe, grid-based international biomethane trade has not started yet 5, but interest ine.g., Africa (for city grids), and Latin America as well as parts of Asia is rising (Junginger et al.

4

5

The EU is supporting the Renewable Gas Trade Centre in Europe (REGATRACE) to foster such developments, see
https://www.regatrace.eu/
There is some inter-state trade within Canada and the US, though.

18

2019). The state of biomethane development in selected IEA member countries is reported
regularly 6, and an overview of biomethane potentials from manure are available in Liebetrau etal. (2021) for Austria, Australia, Canada, Germany, Ireland, Norway, and the UK.
3.1.2
Trade of H2 and RM
Currently, H2 production and use are quite localized – some 85% of H2 is produced and consumed
on-site than bought and sold on the wider market (IEA 2019). H2 is already in use but is predominantly produced from fossil fuels. As of now, the sustainable trade potential of H2 and RM cannot
be quantified due to the early development of the technologies and logistics.
Yet, several countries have ambitions to ex- or import significant amounts of H2 in the future(see Table 3).

Table 3

Overview of national H2 targets and trade perspectives
H2 targets [TWhLHV]Country/Region
Austria
Australia
CanadaChile
Colombia
China
Czech Republic
European Union
FinlandFranceGermany
Hungary
Italy

2030
4-8
133
125
5
297
3
200
3
33
14
2
25

667

Japan

10 - 100

667

Korea
Netherlands
NorwayNew Zealand
PolandPortugal
RussiaSpain

88
15 - 20

United Kingdom

25

total

2050

H2 tradeexportimport
x

x
x
x
x
n/a
n/a
x
x
x
x
x
x

5

x
x
x
x
x

10
10 - 13
67
20

n/a
25

x
x
x
x

1088 - 1192

1363

Source: own compilation based on Fritsche (2022) and IEA (2021b); n/a = information not available

6

https://task37.ieabioenergy.com/country-reports.html

19

IRENA (2022) estimates that roughly 1/3 of green H2 will be traded internationally by 2050, ashare slightly higher than the current share of natural gas traded globally.
Several countries are very active in creating bi- and multilateral agreements on H2 trade, asreported in IEA (2021b). The potential export “clusters” identified by IRENA are in Africa 7, Latin
America, the Middle East, and Australia, Canada, New Zealand, Russia, and Southern European
countries. This fits rather well with the country trade ambitions given in Table 2.
For the EU27 + UK, Wang et al. (2021) estimated a domestic green H2 supply potential of 4,000
TWh by 2050, and green H2 import potentials from Northern Africa and the Ukraine of 1,700 TWh
by 2050. Imports would be transported mainly through pipelines.
Given the very early stage of H2 trade on the one hand and the rather large potentials on theother hand, the future dynamics of H2 ex- and imports will depend on realizing cost reductions
for electrolysers, investments in renewable electricity and H2 transport infrastructure as well as
success in market introduction schemes which factor in (rising) CO2 prices.
The lead time of respective policies and market developments imply that substantial “green” H2trade cannot be expected before 2030 – yet there will be some forerunner countries such ase.g., Australia, Chile, the EU, Japan, Saudi Arabia, the UK, and the US.
In that context, several countries such as Norway and Russia see a role of low-carbon H2 fromnatural gas (“blue” or “turquoise”) as a means to start investments and bring down cost oftransport infrastructure, as indicated in IEA (2019), Fritsche (2022), and IRENA (2022).

3.2

Regulatory issues of RG trade

Trade in biomethane passed various regulatory hurdles in the last years so that further growthand market development using existing natural gas infrastructure can be expected (IEA 2020).
For “green” H2 and its derivatives, though, trade hurdles remain. Besides the challenge ofreducing production cost, international trade faces unresolved regulatory issues, especially inthe definition of “greenness” and respective GHG emission thresholds, and the so-called
additionality requirements for green H2 (Fritsche 2022; Heinemann et al. 2021).
The EC proposal for a Directive on common rules for the internal markets in renewable andnatural gases and in hydrogen (EC 2021a+b) includes the mandatory certification of H2 todemonstrate a GHG emission reduction of at least 70%, compared to fossil gas. This obligation
would apply also for H2 imports to the EU. Given the importance of the issue for international
trade, several countries agreed on a Hydrogen Production Analysis Task Force to reach consensus
on a methodology and analytical framework for determining H2-related GHG emissions (IEA
2021b). This group operates under the International Partnership for Hydrogen and Fuel Cells in
the Economy (IPHE) and is expected to deliver a proposal in 2022.
The work of the IPHE Task Force and the negotiations on the EU proposal for renewable gases
will determine if the regulatory trade barriers for “green” H2 can be overcome in the next years.

7

The project H2ATLAS-AFRICA - a joint initiative of Germany and African partners – explores H2 production potentials
from renewable energy sources in the Sub-Saharan region (SADC and ECOWAS countries), see
https://www.h2atlas.de/en/.

20

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