Unlike fossil fuels, for which large reserves are concentrated in certain countries and regions, renewable energy resources (solar, wind, geothermal, etc.) are available at a viable scale in every country. The geographical concentration of fossil fuel reserves has made some countries into major producers, while most countries are predominantly importers. Renewable energy, in contrast, can be produced everywhere (although the cost-effectiveness varies by location) and therefore has the potential to dramatically change how and between whom energy is traded. However, until recently
there has been no cost-effective way to transport renewable electricity over long distances to link low-cost production sites with demand centres. Suitable transmission lines are rare and costly to construct. The use of hydrogen as an energy carrier could be an answer, enabling renewable energy to be traded across borders in the form of molecules or commodities (such as ammonia).

The conversion of hydrogen to ammonia is already commercially viable and applied at large scale; ammonia is widely traded today (about 10% of the global production) and has a developed transportation infrastructure (ports, vessels, storage). Ammonia can also be directly used as feedstock and fuels and does not necessarily need to be reconverted to hydrogen. However, the existing, growing market for ammonia needs to be decarbonised to reach the 1.5°C scenario. By 2050, global ammonia demand could reach 690 Mt/year [IRENA & AEA, 2022]). Almost 80% of this (561 Mt/year) would be used as chemical feedstock and as fuel for shipping and power, and only 20% would be used as a hydrogen carrier. As the operating costs of renewables are very low, having a low weighted average cost of capital (WACC) is critical to the cost-effectiveness of trade. Absolute levels and country differences in WACC both significantly affect the trade outlook and determine whether a country becomes an exporter or an importer. If WACC remains roughly as it is today, countries that have good-quality resources and low WACC would become the largest green hydrogen exporters and would be collectively responsible for almost 40% of the global trade.


This report is part of a series of three reports focusing on the Global Hydrogen Trade to Meet the 1.5°C Climate Goal (see Figure 0.1). The first one (this report) integrates all the components – supply and infrastructure from the other two reports in the series, together with demand from IRENA’s World Energy Transitions Outlook 2022 1.5°C scenario (IRENA, 2022a) – to assess the outlook of global hydrogen trade by 2050, looking at the cost and technical production potential of green hydrogen for the world in 2030 and 2050 under different scenarios and assumptions. The second report looks at the state-of-the-art from the literature about hydrogen infrastructure under four technology pathways
(IRENA, 2022b). The third report covers the cost and technical potential of green hydrogen supply for various regions and time horizons under different scenarios and assumptions (IRENA, 2022c).

The Global Hydrogen Trade to Meet the 1.5°C Climate Goal report series is closely related to some recent IRENA publications. The World Energy Transitions Outlook 2022 (IRENA, 2022a) provides a perspective on the role of hydrogen within the wider energy transition in a scenario in line with a 1.5°C pathway. This outlook includes all the energy sectors as well as the trade-off between hydrogen and other technology pathways (e.g. electrification, carbon capture and storage, bioenergy). The short-term actions required to enable global trade identified in the Global Hydrogen Trade to Meet the 1.5°C Climate Goal report series are only the beginning. While there are measures that are applicable at the global level (e.g. certification), some measures will be specific to a country, being dependent on local conditions such as energy mix, natural resources and level of mitigation ambition.



In the World Energy Transitions Outlook 1.5°C scenario, 70% of the carbon dioxide emission reductions towards a net-zero system can be achieved through electrification, energy efficiency and renewables. Hydrogen will be needed to achieve full decarbonisation. It is a complement to electrification, offering
a solution for heavy industry, long-haul transport and seasonal storage, which are applications where molecules will be needed. In this 1.5°C scenario, the global hydrogen production would need to expand by almost five times, to 614 megatonnes of hydrogen per year, to reach 12% of final energy demand by 2050, also shifting from a major source of greenhouse gas emissions to a low-emission energy carrier. Green hydrogen, produced from renewables, is expected to represent the bulk of the production. Not all countries are equally endowed with renewable resources. Hydrogen and its derivatives can provide a cost-effective means to transport energy over long distances and store it for long periods of time. This opens a new opportunity for producing renewable energy, transforming it to hydrogen and transporting
it to large demand centres far away. Transporting renewable energy in the form of hydrogen and derivatives effectively increases the distance that renewable energy can travel in a costeffective way. This will be economically attractive if the transport cost is lower than the production cost differential between two regions.

The role of hydrogen in a 1.5°C scenario
The bulk of the decarbonisation of the energy system is expected to come from a combination of renewables in the electricity system, electrification of end-use sectors (especially road transport
and low-temperature heating) and energy efficiency. In the 1.5°C scenario of the World Energy
Transitions Outlook (WETO) from IRENA, these three strategies are expected to achieve 70% of
the carbon dioxide (CO2) reduction towards 2050 (see Figure 1.1).

Not all applications can be electrified, or at least not in the short term (e.g. international shipping and aviation), and a denser form of energy is needed. Furthermore, there are applications where molecules
are needed as a feedstock rather than an energy carrier, and electricity does not represent a feasible
substitute. Gaseous and liquid carriers are easier to store in large quantities and transport over long distances than electricity, resulting in a lower cost. Considering these factors, hydrogen is expected to
satisfy 12% of final energy demand3 and contribute to a reduction of 10% of the total CO2 emissions
in this 1.5°C scenario, which together with carbon capture and storage (CCS) and negative emission
technologies paves the way for achieving a net-zero emissions energy system (IRENA, 2022a).

Hydrogen can be used across the entire energy system. However, any green hydrogen use beyond the industrial sector translates into larger (renewable) capacities needing to be deployed, larger investments, and a higher hurdle to overcome. For some applications, like low- and mid-temperature heating or road transport, electrification is not only more efficient but more costeffective and can lead to decarbonisation today with available technologies (Knobloch et al., 2020). Hydrogen is then left for applications that have limited choices or in which electrification is difficult, such as international shipping and aviation, chemicals, steel and seasonal storage (see Figure 1.2). For most of these applications, hydrogen itself is not the most attractive form of energy from a cost perspective; a hydrogen derivative (i.e. ammonia, synthetic fuels, reduced iron) is more attractive. Industrial and power applications have the advantage that the typical demand size can enable economies of scale for production and infrastructure, as opposed to transport applications, which need to aggregate large numbers of end users.

Going forward, only low-carbon hydrogen facilities should be constructed. This means unabated production from gas and coal is not an option, which leaves only green and blue hydrogen. One
of the challenges green hydrogen faces is the production cost differential compared with fossil-based routes. In the coming years, the gap between blue and green hydrogen can be closed by
the ongoing decline in the cost of renewable electricity (which is the main cost driver), strategies
to reduce the cost of the electrolyser (IRENA, 2020b), and policy support (IRENA, 2021c). These
fundamental drivers will lead green hydrogen to outcompete blue hydrogen in the coming five
to ten years, similar to what has already happened today with renewables in the electricity
system (IRENA, 2021b). However, a key advantage for green hydrogen is that a large share could
come from off-grid dedicated plants, with long-term purchase agreements that fix the hydrogen
production cost. In contrast, the main cost contributor to blue hydrogen is the natural gas input;
this price is subject to sudden fluctuations such as the ones experienced in Asian markets, and
particularly in Europe, in late 2021. This can make green hydrogen attractive in a much shorter
time frame, especially when combined with CO2 prices above USD 90 (US dollars) per tonne of
CO2 (tCO2), which were already reached in the European Union (EU) in early 2022. countries (see Figure 1.3). The opportunity that hydrogen provides in this context is that, by using electrolysis, it transforms the renewable electricity into an energy form more suitable for long-distance transport, decreasing the transport cost per kilometre (km). This effectively extends the distance that the energy can be transported for the same cost. The competitiveness is, then, weighted on the production cost differential between regions versus the additional cost of transport. The choice is further complicated by the possibility of transforming hydrogen into derivatives before shipment. Hence, hydrogen can be transported in the form a carrier from which pure hydrogen is obtained at the end or in the form of a commodity or material that would not be reconverted back to hydrogen (e.g. direct reduced iron [DRI], steel, ammonia, synthetic fuels).

One of the main parameters defining the economic benefit of relocating production of hydrogen-based commodities is the difference in renewable electricity cost. In 2020, based on actual projects, the difference in the weighted average levelised cost of electricity for solar PV between the cheapest and most expensive regions was almost a factor of four, with the 5th percentile of costs at USD 39 per megawatt-hour (MWh) and the 95th percentile at USD 163/MWh. This was less pronounced for onshore wind, with a factor of 2.4, from USD 29/MWh to USD 70/MWh (IRENA, 2021b). In the future, this cost differential is expected to go down due to two factors: (1) the capital cost gap between regions closing as more countries develop domestic experience and exchange lessons learned, and the entire supply chain is scaled up, and (2) the cost of capital and the risk associated with building these facilities decreasing. Thus, the future cost differential will be mostly driven by the difference in resource quality and by the cost of capital differential due to the economic conditions of each country (i.e. country risk). A conservative resource quality differential of a factor of two can translate into an electricity cost difference of USD 30/MWh.6 This can be higher if hybrid PV-wind-battery plants are used, but this level would already be enough to justify the relocation of the production of various commodities (see Figure 1.4).

At the other extreme, there is cement, which can have a higher transport cost than production
cost, and that is usually why the production is located close to the demand. Between these two
extremes, the economic impact of relocating the production of other commodities is largely
positive. From a purely cost perspective, it makes the most sense to produce them in places
with good renewable resources and transport the commodity rather than transporting the
renewable energy or the hydrogen (Philibert, 2021). Studies for steel production in Australia
and Europe have found this to be the case (Devlin and Yang, 2022; Toktarova et al., 2022). From
these commodities, ammonia is the only one that could be reconverted to pure hydrogen at the
importing side, if required, and without any carbon emissions.

The port already has agreements in multiple countries to develop potential hydrogen trading routes, including agreements with Australia, Brazil, Canada, Chile, Colombia, Iceland, Morocco, Namibia, Oman, Portugal, Spain, South Africa, United Arab Emirates and Uruguay. The port is also collaborating with parties in Oman for research into green hydrogen.

Soft factors influencing global trade
This report mainly focuses on the technical aspects (e.g. green hydrogen potential based on
land eligibility) and economic aspects (e.g. conversion and transport costs) of hydrogen trade.
However, other aspects will also influence the technology choice, the development timeline, and
the trading partners (IRENA, 2022d). As such, this report is the first step of a two-step approach.
First, it is necessary to determine the share of imports by comparing domestic production
cost with transport cost, including reconversion. Then, the landed costs from different trading
partners are compared to determine the cost-optimal mix for a specific importer. This is, however,
only the starting point based on quantitative aspects; there is a wide range of factors that are
more difficult to quantify but that potentially have a larger effect on defining the trading pairs in
the second step of the process (Figure 1.8). For instance, there is a trade-off between different
factors such as the existence of well-established trade and diplomatic relationships, the level of
development of the renewable and hydrogen industry, the stability of the political system, and
the distance of production and shipping sites, that might justify paying a cost premium for the
imported hydrogen. In general, these soft factors effectively alter the output of the economic
analysis by shifting the supply and demand curves, resulting in a different trading quantity and
different prices (Fraunhofer ISI, 2020).

be incentives for market creation – these could be in the form of quotas across different end uses, public procurement, or capacity targets (e.g. for electrolysis) – to overcome the barrier of current limited trading, since most of the hydrogen produced has long-term contracts, hindering competition and cost decrease. There should also be incentives to overcome the higher production and transport costs of hydrogen compared with fossil fuels. These could be in the form of grants, fiscal support, premiums, or carbon contracts for difference (CCfD). An incentive could also be the government acting as guarantor, giving long-term certainty on revenues and reducing the project risk (see Box 1.3). There should be a clear regulation of infrastructure, including uniform gas quality standards, clear tariff structure, third-party access, unbundling of the market, financing mechanisms, and free and fair competition among suppliers (Gas for Climate, 2021a). Lastly, permitting and approval processes should be simple so as to
facilitate project execution and avoid delays. Aspects to include here would be the cost of the administrative process, and its duration, complexity and integration with the existing process
for renewable power.


Pure hydrogen production grows by a factor of more than six from 2020 to 2050 (see Figure 2.1). Today, hydrogen is mostly used for industrial purposes, namely oil refining, chemicals, and steel production. Of these, oil refining could experience the largest decrease due to a shift towards synthetic fuels and biofuels. Ammonia and methanol demand are expected to grow three to four times, driven by growth in developing economies and use as fuels (especially for ammonia in the shipping sector). In steel, hydrogen can be a reducing agent for producing iron. Currently, about 7% of primary steel production uses this route, although using natural gas as the energy source. In the future, this could change towards pure hydrogen being used to produce reduced iron. Towards 2050, the largest area of growth will be the transport sector. Uses for pure hydrogen to complement electricity arise in the road and rail sectors, in which use of ammonia for international shipping and synthetic fuels for international aviation are among the largest uses. The rest of the demand for 614 MtH2/year would come from the power sector to meet the need for flexibility and thermal generation to compensate for fluctuations in variable renewable energy and complement other flexibility measures. The hydrogen consumption for the power sector (as seasonal storage) will be updated by IRENA in future modelling exercises, coming from integrated gas and power modelling. Thus, for this report, the share of consumption for power has been excluded

China is today the largest hydrogen consumer in the world, at about 24 MtH2/year in 2020 (IEA,
2021b). It produces about a quarter of the global hydrogen used for refining and is home to
about a quarter of the global ammonia production and over half the global methanol and steel
production. By 2050, in a 1.5°C scenario, China is expected to remain a leading industrial country,
and even considering the new hydrogen applications, China could retain about a quarter of the
global hydrogen demand, driven by the industrial sector (70% of its demand). A distant second,
with almost a third of China’s demand would be India. India’s steel production is expected to
quadruple by 2050, which combined with one of the largest iron ore reserves in the world and
low-cost renewable electricity opens up the opportunity to use electrolytic hydrogen for direct
reduction of iron. One barrier for this potential match is the difference between the time when
new steel production is needed and the time needed to develop the DRI technology, since
DRI might still need 8-13 years to reach the commercial stage (Draxler et al., 2021; IEA, 2021c).
The country with the third largest demand would be the United States of America, going from
about 10 MtH2/year today to over 30 MtH2/year in 2050, with most of the growth driven by the
transport sector. Hydrogen demand by 2050 is expected to be relatively concentrated, with the
top ten countries in the world representing about two-thirds of the global consumption (see
Figure 2.2).


The other factor that defines the attractiveness of domestic production is the technical potential
of renewable energy, which is fundamentally driven by land eligibility constraints (IRENA,
2022c). Aspects such as social acceptance, visual and noise issues for wind turbines, effect
on bird migration, and land cost escalation with higher utilisation have not been considered
in this study. Some countries might have limited potential overall or just enough to cover their
domestic electricity demand, which will also grow significantly due to electrification of transport
and residential demand. In most countries, the renewable potential is multiple times (in many
countries more than 100 times) the potential electricity demand. However, for some countries
this potential is either not enough to fully cover electricity demand or only enough if low-quality
resources are included, which would lead to comparatively high electricity cost due to low
generation per unit of capacity (see Figure 3.3).

For Germany, about 30% of the total renewable technical potential is PV. The combined onshore
wind and solar potential is more than 67% higher than the 2050 demand (including domestic
production of hydrogen and ammonia). Therefore, in theory, the country could satisfy all its
demand with domestic supply (see Figure 3.3). However, all the PV potential is relatively poor
quality, with an annual average capacity factor of 11-14%, which makes the generated electricity
more expensive (USD 18/MWh) than other countries with better solar resource quality. Similarly,
the offshore wind technical potential of 1 000 TWh is an upper bound. This does not consider that
as wind farms are installed, the effective full-load hours of the subsequent farms are reduced.
This can happen already for relatively small capacities of 50-70 GW of offshore wind that various
scenarios estimate for 2050 (Agora Energiewende, 2020). At the same time, Germany (like
Italy) has an existing gas infrastructure interconnected with the rest of Europe, which could be
repurposed to hydrogen. This decreases the transport cost, especially for large volumes, to less
than USD 0.1 per kilogramme of hydrogen (kgH2), making imports attractive.

Introduction to modelling results
The analysis was conducted using a global optimisation model that covers both power and gas
systems and co-optimises the investments, the gas shipping and the dispatch of the combined
power and gas system. The scope of the model13 goes from renewable generation to hydrogen,
transport and end use (see Figure 3.6). Resource data for PV, onshore wind and offshore wind
(from the analysis described in IRENA [2022c]) is split into five resource classes for each region,
with a maximum potential and a representative hourly profile. Given that the methodology is
based on least-cost optimisation, trade flows are driven purely by delivered cost. In the future,
hydrogen trade flows will also be largely shaped by geopolitical factors, especially if the
production cost differentials between regions are small and geopolitical preferences would result
in only small cost penalties, in exchange for lower risk of supply disruptions (IRENA, 2022d).

In this analysis, the model is considered as greenfield. This means there is no installed capacity
for any of the components and all the hydrogen production requires new facilities. For
regions that have natural gas pipelines today, a lower cost has been considered equivalent to
repurposing them to hydrogen. The model is not bound only by the existing pipelines; new
hydrogen pipelines are possible for new routes. The model optimises investment and operation
of the combined power and gas system, but only to feed hydrogen and ammonia demand (this
excludes electricity demand beyond electrolysers and gas processing plants). This means only
off-grid electrolysers are included. On-grid electrolysers can have other challenges such as the
continuous tracking the emissions of the electricity input and additional costs from connection
to the grid, taxes and levies in the wholesale price. The objective function is thus to minimise
total cost, and the routes are compared based on this criterion and not others (e.g. efficiency,
which is indirectly reflected in cost).

The time horizon is 2050, and demand and CAPEX are those assumed for that year (see Chapter
2 and IRENA [2022c]). To make both the calculation of the flows and the interpretation of the
results easier, the model is divided in 34 regions (see Figure 3.7): each G20 country, selected
regions that could play a significant role in hydrogen trade (Chile, Colombia, North Africa,
Portugal, Spain and Ukraine), and the rest of the countries aggregated by geographical location
(e.g. East Asia, Latin America).

Green hydrogen production
The potential for green hydrogen production at costs lower than USD 2/kgH2 is almost
10 000 EJ/year by 2050 (over 24 times the global final energy demand in 2020) (IRENA, 2022c).
However, several factors could constrain this very large potential. First, the potential is not
equally distributed across countries, and some (e.g. Germany, Japan, Republic of Korea) have
much lower potential than the expected future needs. Second, the low-cost supply locations
can be in remote places with limited infrastructure (e.g. roads, grid, pipelines), which would
increase the costs due to the facilities and additional transport infrastructure needed. Third,
the additional transport cost to the importing markets may reduce attractiveness by increasing
overall cost significantly.

These costs are in line with previous IRENA analysis (IRENA, 2020b) on the relative importance
of electricity and electrolysis as the cost of electrolysers decreases (see Figure 3.11). Based on
the current analysis, dedicated, large-scale solar and wind facilities for hydrogen generation
will be able to supply electricity to electrolysers at a cost of USD 10-20/MWh in all countries
and regions by 2050, with many regions expected to reach costs of green hydrogen well below
USD 1/kg for the optimistic scenario and USD 1.5/kg for the pessimistic scenario.

Regional perspective
While the global outlook remains roughly stable across scenarios, the outcome for specific
regions can drastically change depending on the scenario. Figure 3.24 shows the renewable
hydrogen production for each region across the different scenarios evaluated. Values are
expressed relative to the scenarios with the highest production (i.e. a value of 1 represents the
scenario with the highest production, and an intermediate value between 0 and 1 means that the
region has a reduced production for that scenario).

One of the largest uncertainties is how the WACC for different countries will evolve over time.
For instance, from the early days of PV in the 2000s in Germany, the costs of equity and
debt (before tax) were 9.3% and 5.5%, respectively, decreasing to 4.8% and 1.5% in 2017 (Egli,
Steffen and Schmidt, 2018). Towards 2050, there will be trends of industrial development, which
means that several countries will have a renewable industry established, and a trend towards
urbanisation, democracy and digitalisation, which may affect the risk profile of a specific
country and therefore the WACC. The two extremes are tested in this study: one where the risk
profiles and WACC remain the same as they are today (Egli, Steffen and Schmidt, 2019) and
one where all the countries have the same WACC (Bogdanov et al., 2019) and the production
cost differentials are driven by the quality of the resource and the capital cost. Some of the
factors that can contribute to equalisation of WACC, specifically for hydrogen, are technology
transfer through joint projects or co-operation agreements, capacity building, and the use of
international financing instruments. However, WACC is largely dependent on factors beyond
hydrogen, such as industrial development, experience of financial institutions and status of the
renewable energy industry, which ultimately affect the risk perception and cost of debt and
equity used for the WACC calculation.

Oil-exporting countries can be major players in green hydrogen, provided they get access to
abundant low-cost capital for investments in renewables, electrolysis and hydrogen infrastructure,
which today is the case for only a few of them. In this case, the Middle East and Latin America can
compete on hydrogen exports with leading renewable electricity producers that are considering
exporting hydrogen as a means to further monetise their renewable potential. For some of the
incumbent oil exporters, green hydrogen represents an opportunity to offset some of the fossil
fuel export losses. For others, it is an opportunity to export renewable electricity by converting
it to green molecules. Both the Middle East and Latin America have excellent renewable energy
potential. The crucial factor will be access to large volumes of low-cost capital and the speed of
execution of gigawatt-scale projects. Some countries in these regions like Israel, Kuwait, Jordan
and the United Arab Emirates combine a low WACC today with an accelerated deployment of
renewables in the last couple of years, putting them in a good place to develop a competitive
hydrogen industry.


Once enough suppliers and users are connected, there will be more competition, leading to
lower pricing. This in turn can lead to the use of traded hubs to satisfy the risk management
requirements of portfolios and the market participants interacting in the traded market via hubs.
By this point, the trade contracts are standardised, facilitating transactions and an increase
in volume traded (Heather, 2016). The transition to a market can start with over-the-counter
trading (still bilateral but with standard amounts and terms) before moving to an exchange
(with a clearing house). Figure 4.2 shows this market evolution across different dimensions,
focusing on the developments needed in the coming decade.

In the case of ships, the development could be similar to LNG. The first LNG contracts were
bilateral and long term. There were take-or-pay clauses, which guaranteed a minimum volume
that buyers would pay for regardless of whether they needed such volume. The LNG price
was linked to a competing fuel rather than being based on the production and transport cost.
The LNG bought could not be resold to third parties. These conditions guaranteed security of
supply for the buyers, an offtake for the seller, and a fixed price with a balance between return
on investment for the seller and non-volatile pricing for the buyer (IRENA, 2022d). In 2020,
almost 55 years after the first LNG shipment, only about a third of the price formation was on
the spot market and almost 60% was still with oil price escalation (IGU, 2021a). For hydrogen,
the terms of these first few bilateral trades can be reported in the trade press and become the
basis for price formation. After price disclosure comes price discovery and attracting more
players to the market (Heather, 2016).

Barriers hindering trade
Hydrogen does not emit CO2 upon use, so that makes tracking production and transport
emissions essential to enabling global hydrogen trade to contribute to climate mitigation. There
are multiple challenges in this respect. First, there are several schemes that are advanced in
their definition (e.g. Australia, EU, United Kingdom) but none of them is implemented at large
scale with actual production, which means it is early stages and schemes might still change
as the process develops. Second, to enable global trade, there should be consistency in the
methodological aspects (including boundaries, emissions included and factors used, treatment
84 of co-products, among others) across countries to provide importers with a guarantee of the
GHG emissions and the impact associated with the production of the hydrogen imported
so that they can track progress towards their targets and ensure sustainability. Because of
this, importers have an edge in establishing the guidelines for certification. Third, each of the
transport pathways could require different boundaries and conditions (e.g. origin of the LOHC
used), which makes the process of standardising the certification of transport more difficult.
Lastly, while certification in shipping can be directly linked to physical trading, this might not
be possible for trading through a pipeline network, which will require a different approach
(e.g. mass balancing) to cope with the different qualities of hydrogen.

The next step is to broaden the scope to include conversion to a carrier and the transport
step itself. Like production, where each pathway requires different boundaries and components
(e.g. methane emissions), the conversion step will require definition of boundaries for each
pathway. For example, LOHC hydrogenation has a large heat release, and its emissions will
depend on the benefit assumed for such heat. In contrast, hydrogen liquefaction uses a large
amount of electricity, which may not be renewable, since the liquefaction could be located
at the port while the hydrogen production could be inland. The International Partnership for
Hydrogen and Fuel Cells in the Economy is already embarking on efforts to agree on the
methodology for some of these issues, and a draft should be available later in 2022. A similar
approach is needed for the reconversion to hydrogen (if necessary), and the methodology for
the heat consumed will be critical. A modular approach with separate certification for each step
in the value chain (production, conversion, transport) might facilitate the process of defining the
certification scheme since it simplifies the scope (White et al., 2021). Certification efforts that are
already covering ammonia as a conversion pathway include those from the Ammonia Energy
Association, the Smart Energy Council in Australia, and the Midwest Renewable Energy Tracking
System in the United States.

promoting a sustainable growth in income and employment and covers aspects such as
infrastructure, trade and public financing. The social dimension includes not having a negative
impact on the local community in terms of human rights, health and safety risks, or access to
energy. Governance refers to aspects such as transparency, political stability and stakeholder
engagement (see Figure 4.4) (PtX Hub, 2021). One of the certification initiatives already moving
in this direction is the Green Hydrogen Organization. This non-profit organisation launched in
September 2021 and is supported by private funds. It is planning to set up a green hydrogen
standard that extends beyond what the International Partnership for Hydrogen and Fuel Cells
in the Economy is doing and to use ESG aspects and align with the Sustainable Development
Goals beyond climate change (GH2, 2021).

The pace of development for the conversion technologies could also pose a challenge. Ammonia
today is a 183 Mt/year market, which is equivalent to about 32 MtH2/year, which in turn would
be only about 6% of the global hydrogen demand in 2050. The LNG trade market in 2020
was 356 Mt (IGU, 2021b), which in energy terms would be equivalent to about 150 MtH2/year.
It took about five to seven decades40 for each of these technologies to reach these orders of
magnitude. Ammonia and LNG can serve as a reference for trade flows since they are globally
traded commodities. Other pathways with limited trade of the product, yet with a fast growth,
are wind and solar, which have experienced average compound annual growth rates of 22% and 39%, respectively, during the last 20 years (BP, 2021). With these growth rates, wind and solar
have respectively reached almost 1 600 and 850 TWh of generation in 2020, equivalent to about
48 and 26 MtH2/year. In all these cases, the drastic growth achieved would be eclipsed by the
growth needed for low-carbon (i.e. green and blue) hydrogen, which would need to grow from
almost zero today to 150 MtH2/year by 2030 and 614 MtH2/year by 2050 (see Figure 4.7).

Actions and roadmap to address barriers
The fundamental limitation for renewable deployment is not potential or material constraints,
it is how fast the supply chain can scale up to reach the levels needed for a 1.5°C scenario.
To achieve this, an acceleration of the capital mobilisation is needed. Annual investments in
renewable electricity generation need to almost quadruple, from a historical level of around
USD 250 billion to more than USD 1 050 billion on average for the next 10 years (IRENA, 2022a).

Infrastructure and regulation
Barriers hindering trade: Infrastructure
Infrastructure might become the largest hurdle for the liquid hydrogen route. The need for
cryogenic temperatures results in high capital costs across the value chain (IRENA, 2022b),
which can be 2-2.5 times higher than the total investment needed for ammonia or LOHC.
There are virtually no facilities at the right scale for global trade of liquid hydrogen, and the
liquefaction plants, storage, bunkering, ships and regasification would need to all be greenfield
facilities. However, ammonia and LOHC each have some existing facilities that could be used.
Ammonia is already produced, stored and traded in over 130 ports. LOHC can build on the
chemical infrastructure for handling around ports. Both, however, would need new infrastructure
development. Even if a terminal and storage facilities are available at both ports involved in a
trade, the reconversion plant for these pathways could represent 25-35% of the total investment
required in the importing and exporting port.


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