Shipping’s Role in the

Global Energy Transition

A report commissioned by the International Chamber of Shipping, written by

researchers at the Tyndall Centre for Climate Change Research at the University of
Manchester

November 2022

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The International Chamber of Shipping (ICS) is the global trade association
representing national shipowners’ associations from Asia, Africa, the Americas and
Europe and more than 80% of the world merchant fleet. Established in 1921, ICS is
concerned with all aspects of maritime affairs particularly maritime safety,
environmental protection, maritime law and employment affairs. ICS enjoys
consultative status with the UN International Maritime Organization (IMO) and
International Labour Organization (ILO).

The Tyndall Centre for Climate Change Research was founded in 2000 to conduct
cutting edge, interdisciplinary research, and provide a conduit between scientists
and policymakers. With nearly 200 members ranging from PhD researchers to
Professors, from the Universities of Manchester, East Anglia, Cardiff and Newcastle,
the Tyndall Centre represents a substantial body of the UK’s climate change
expertise from across the scientific, engineering, social science and economic
communities.

Please cite as:

Jones, C., Bullock, S., Ap Dafydd Tomos, B., Freer, M., Welfle, A., and Larkin, A. 2022.
Shipping’s role in the global energy transition. A report for the International Chamber
of Shipping. Tyndall Centre for Climate Change Research, University of Manchester.
https://tyndall.ac.uk/news/new-shipping-emissions-report/

NB: All views contained with this report are attributable solely to the named authors
and do not necessarily reflect those of researchers within the wider Tyndall Centre
for Climate Change Research.

Disclaimer:

While the advice given in this report has been developed using the best information
available, it is intended purely as guidance to be used at the user’s own risk. No responsibility
is accepted by Tyndall Centre for Climate Change Research or by the International
Chamber of Shipping or by any person, firm, corporation or organisation who or which has
been in any way concerned with the furnishing of information or data, the compilation,
publication or any translation, supply or sale of this report for the accuracy of any information
or advice given herein or for any omission herefrom or from any consequences whatsoever
resulting directly or indirectly from compliance with or adoption of guidance contained
therein even if caused by a failure to exercise reasonable care.

© International Chamber of Shipping 2022

Email: info@ics-shipping.org

Web: www.ics-shipping.org

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EXECUTIVE SUMMARY
This executive summary sets out the scale of the global energy transition needed to
meet the Paris Climate Agreement goals, the implications for the shipping sector,
and actions which could be taken by national energy ministries and by the shipping
sector to help deliver this transition.

Scale of the global energy transition

It is imperative that nations keep global heating below 1.5˚C – in line with the Paris
Climate Agreement. Even at 1˚C of warming, climate impacts on humanity and
nature are already extensive and growing. The risk of passing multiple climate
tipping points increases rapidly between 1.5˚ and 2˚C.

To meet the Paris goals, major and unprecedented levels of carbon dioxide
emissions reductions are needed this decade, on a pathway to zero emissions
around 2050. The timescales are extremely urgent. Delay is not an option.

Meeting this challenge has profound implications for global energy use, and the
systems that provide that energy. A suite of energy scenarios that limit temperature
rises to 1.5˚C are assessed in this report. Five changes to the energy system by 2050
are consistent across these scenarios:

 Reductions in overall global energy consumption, mainly due to greater

energy efficiency;
 Rapid electrification of many sectors of the global economy;
 Rapid decarbonisation of the electricity sector, with large increases in wind
and solar replacing coal and gas;
 Rapid reductions in coal, oil and gas use;
 Growth in the use of lower-carbon fuels such as hydrogen and bioenergy.

However, delivery of these changes is currently way off-track. Far more assertive
Government action is urgently required.

Implications for the shipping sector of meeting the Paris goals

If realised, these energy system changes will have profound implications for shipping,
as 36% of the shipping sector’s current trade is transporting energy products,
primarily oil, coal and gas. In future, shipping will transport different fuels, in different
quantities, between different countries, and if the 1.5˚C scenarios become a reality,
this transition will start in earnest in a timeframe as short as months and years. This
presents challenges and opportunities.

Overall, the mix of energy products transport by ship changes, while total shipping of
energy products falls: growth of transport of new fuels is outweighed by greater falls
in shipments of oil and coal. Figure A shows potential shipments of fuels in the 1.5˚C
scenarios reviewed here, compared with today.

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 5000
2020
4500
2030
4000

3500
Energy Products (Mt)

2050 Ammonia
3000
Biofuels
2500
Biomass
2000
Coal
1500
Gas
1000 Oil

500

0
IPCC - Ren

IPCC - SP

IPCC - Ren

IPCC - SP
Baseline

IRENA 1.5

IRENA 1.5
IEA NZE

IEA NZE
Figure A: Potential seaborne trade outcomes for the 1.5˚C scenarios, assuming higher levels of trade of emergent low-
carbon fuels and deployment at scale of carbon capture and storage technologies.

The scenarios show that a 1.5˚C transition reduces the global quantities of coal, oil
and gas produced, transported and consumed, and increases the quantities of
hydrogen and biomass, with hydrogen transported by ship in the form of ammonia.

To realise these scenarios, the shipping sector needs to prepare for a rapid transition
away from transporting coal and oil for energy consumption. Reductions start this
decade. By 2050 coal shipments fall 90-100%, oil 50-90%. Although natural gas
consumption decreases too, a greater proportion of this gas is transported by ship,
so the shipping sector would expect a continuing role for shipping natural gas
products in the medium-term.

An opportunity is that future bioenergy and ammonia shipments have the potential
to be as high as coal and gas shipments today. These increased shipments will not
be technically difficult for the sector to deliver, given existing infrastructure and
familiarity with cargoes. Nevertheless, such increases still do not offset an overall
decline in energy products transported by sea.

Gap between plans and real progress on delivering 1.5 ˚C

Hydrogen-based fuels present a major opportunity for the shipping sector. However,
there is a big gap between the planned production of low-carbon hydrogen, and
what is required to deliver these 1.5˚C scenarios. The International Energy Agency
estimates low-carbon hydrogen production of 24 Mt by 2030 but 1.5˚C scenarios
need at least double that figure, see Figure B. Moreover, the majority of the projects
comprising this 24 Mt are still at concept or feasibility stage. Although project
announcements are growing very rapidly, projects with final investments decisions
are scarce; with project developers unsure of potential markets, and potential

4
consumers unsure of suppliers. Stronger policies are needed now to translate the
recent surge of interest in hydrogen into actual projects, and to connect consumers
and producers.

180

160

140
Low-carbon hydrogen required

Existing uses
120
to fill the gap (Mt)

New uses
100

80

60

40

20

0
Operational Proposed IPCC REN IPCC SP IPCC LD IEA Net Zero IRENA

Figure B: the gap between proposed 2030 low-carbon hydrogen (green), and what is needed in 1.5˚C scenarios (blue/red).
IRENA values as expressed here merge low-carbon hydrogen for existing and current uses (yellow).

There are two sources of demand for low-carbon hydrogen. First, replacing the
highly carbon-intensive current method of “grey” hydrogen production. Second,
1.5˚C scenarios assume a growing need for hydrogen in new uses – for example in
industry, shipping, aviation and power generation. This must also be low carbon.
Current grey hydrogen tends to be produced very close to where it is used, with low
transport needs. However, given that for green hydrogen in particular, producer
countries are likely to be distant from consumer markets, transport of green
hydrogen will be necessary, either by pipeline or ship. As distances increase,
shipping will be preferable.

It is economically more efficient to ship hydrogen as ammonia. There is however a

cost penalty at the destination in converting ammonia back to hydrogen. Therefore,
the best export markets for green hydrogen producers are likely to be those with
direct uses of ammonia, such as in fertiliser manufacture – avoiding the need for
reconversion. Five insights that arise from increasing production and shipping of
green ammonia are:

 Existing fertiliser manufacture is the largest potential market for low-carbon

hydrogen to 2030, while new energy uses scale up.

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  It is imperative that existing hydrogen production is decarbonised quickly, as
part of the wider global energy transition; grey hydrogen production is highly
carbon-intensive, with CO2 emissions equivalent to the entire shipping sector.

 Imported green ammonia can reduce reliance on natural gas, increasingly

important for many countries’ strategic goals around energy security.

 Green ammonia is becoming economically viable - the recent price hikes for
natural gas, and falls in electrolyser, wind and solar costs, mean that in the EU,
imported green ammonia can be cheaper than domestic grey ammonia
production, around a decade earlier than thought likely just two years ago.

 The shipping sector will need to increase the number of ammonia-carriers,

accelerating to construction of around 20 large vessels a year in the latter
half of the decade. This represents a scale-up of the recent rate of five vessels
a year.

Bioenergy use grows in the 1.5˚C scenarios, but needs to be subject to strict
requirements on sustainability impacts. It is likely there will be growth in shipments of
both biomass and biofuels, although there is great uncertainty about sustainable
levels of bioenergy production, and the countries that would see greatest growth.

For bioenergy too there is a gap between planned projects and required ambition.
The growth rate for biofuels has been 5% a year in the last decade, however the
growth rate in sustainable biofuels needs to increase to between 7% and 18% per
year to deliver these 1.5˚C scenarios by 2030.

Production scale-up appears stalled by a lack of confidence in sustainable markets

for low-carbon hydrogen and second generation bioenergy products. Action from
governments and investors is needed if these fuels are to reach the levels required.

Priorities for policy makers

There is a coordination issue potentially holding development of hydrogen in limbo,

with hydrogen projects requiring buyers before final investment decisions are made,
and sectors planning a move into hydrogen being unsure of supply. These are
compounded by major further infrastructure investments often being needed to
deliver hydrogen products from producers to consumers. The priority is therefore to
convert the current explosion of interest in hydrogen into actual projects in the
coming few years.

National hydrogen strategies for consumer countries need to have a greater focus
on imports if the gap between what’s needed in the 1.5˚C scenarios and what is
materialising in practice is to close in time. The EU’s recent RepowerEU target to
import 10Mt green H2 by 2030 is a positive example, but needs to be backed up with
enabling policies. Four examples are:

 The German H2Global contract-for-difference double-auction proposal is a

positive development, providing guaranteed markets and prices for
producers and consumers.

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  Bilateral contracts between countries could be deployed to a greater extent –
mirroring the accelerated growth of the Australian LNG sector in the 2010s
after long-term high-volume contracts were signed with China.

 Mandates for increasing percentages of green hydrogen should be

introduced, as is being explored by India for its fertiliser and refinery sectors.

 Stronger policy is also necessary in more producer countries - the recent $3/kg
H2 production credit in the Inflation Reduction Act is a positive example which
could deliver exponential growth in the USA’s green hydrogen production.

The short-medium term gap between likely production and 1.5˚C requirements
makes it even more imperative that countries treat low-carbon hydrogen as a
valuable resource that is deployed carefully and not used in sectors with cheaper
and more efficient alternatives, for example in surface transport and domestic
heating. Hydrogen strategies should prioritise decarbonising existing hydrogen
consumption, and sectors where there are fewer alternatives – such as shipping.

Because of shipping’s international nature, there is a danger that shipping will slip
through the net of national strategies, both in terms of investment in infrastructure for
importing or exporting hydrogen, and for the shipping sector’s own future use of
hydrogen. The different pace of growth of new hydrogen demand across sectors
has two main implications for shipping.

First, in the short term it is unlikely that the shipping sector provides the much needed
demand-side impetus for green hydrogen projects. That role will fall to
decarbonising existing hydrogen processes. If this occurs, there will be a major role
for the shipping sector as an enabler of the wider energy transition, in connecting
producers and consumers. There is extensive infrastructure already in place globally
for ammonia shipments, and experience in using it. Annual build rates for new
ammonia carriers to meet a rising demand for ammonia in 1.5˚C scenarios are high –
at around 20 large carriers per year - but this is within the range of what has been
achieved in previous years.

Second, because the sector has a slow turn-over of assets, it will only be in the 2030s
and 2040s that the shipping sector becomes a major user of hydrogen products,
including ammonia, to decarbonise its own operations. But steps need to be taken
now to ensure infrastructure is developed in time for the rapid scale-up in the 2030s.
New ammonia carriers need to be designed to run on ammonia to gain synergies in
development and deployment of bunkering infrastructure. Overall, at least 5% of the
fuel used by the shipping sector needs be low-carbon by 2030, as a platform for
more rapid deployment in the 2030s. In addition, deployment of green hydrogen
hubs and corridor initiatives, as well as other measures to connect producers and
suppliers will be required. The work of the ICS’ Clean Energy Marine Hubs, the
Getting to Zero Coalition’s green corridors work, and bunkering initiatives in
Singapore and Rotterdam, among others, are recent examples of what will be
needed.

Crucially, the success of low-carbon hydrogen and sustainable biofuels is critically

dependent upon robust and enforced mechanisms to ensure full-lifecycle emissions
and other sustainability impacts are fully accounted for, and that genuine

7
sustainability and greenhouse gas (GHG) benefits are realised. This means ensuring
bioenergy production does not cause deforestation or conflict with essential uses of
land for food, and that for both bioenergy and hydrogen, upstream as well as
downstream GHG emissions are measured. Clear accounting methodologies need
to be strengthened, integrated and consistent across the whole energy sector.

The shipping sector will be pivotal in facilitating the global energy transition needed
to protect humanity and nature from the worsening impacts of climate change.
Although it can expect to transport far lower quantities of energy products in a 1.5˚C
future, the sector has a crucial role in enabling trade in new low-carbon energy
products. If the shipping sector can energise faster growth in sustainable fuels, it will
be playing a pioneering role in closing the gap between grand theoretical plans
and a real world fit for future generations.

8
1. Introduction

This report provides insights on the implications for the shipping sector of different
global energy scenarios for pursuing efforts to limit global temperature rise to 1.5˚C,
and the opportunities for shipping to support the global low-carbon transition.
Shipping is integral to global trade, transporting ~80% of goods by volume (UNCTAD,
2021). Energy products were ~36% of global seaborne trade in 2021, with around
15% of coal, 17% of natural gas and 64% of oil produced globally moved by ship
(Clarksons, 2022a). Interactions between the energy system and the shipping
industry are a key determinant of the success of new supply chains for an energy
transition compatible with limiting global warming to 1.5˚C.

The report presents an analysis of 1.5˚C energy scenarios alongside a review of

existing hydrogen and biomass energy projects and plans, to explore the extent of
the gap between what’s needed to deliver a 1.5˚C future, and what’s happening
on the ground. It follows a period of high interest in low-carbon fuels – particularly
hydrogen. At least 16 reports on future hydrogen production, demand and transport
have been released between January and November 2022. Analysis of the global
low-carbon hydrogen project pipeline indicates it is currently insufficient to meet
required hydrogen usage scenarios, but announced projects are increasing
exponentially. Growing biomass to remove CO2 from the atmosphere and using
biomass products for energy supply both have a prominent role in discussions about
the future energy system. The rate at which various forms of bioenergy products can
be scaled up and coupled with carbon capture and storage technologies to deliver
net CO2 reductions within the constraints of other sustainable development goals is
uncertain and contested (Rose, 2022). Across the 1.5˚C scenarios reviewed in this
report, modern bioenergy production ranges from between 45 EJ/yr and 99 EJ/yr by
2030 and from 54 EJ/yr to 153 EJ/yr by 2050, from a baseline of 38 EJ/yr. To keep
within sustainability constraints, high bioenergy scenarios by IEA and IRENA also
assume a transition to second generation biofuels largely based on wastes, residues
and energy crops on marginal land. For both hydrogen and biomass-based fuels,
there is a significant gap to close between stated ambition or plans, and in-
development projects.

Limiting Global Warming to 1.5˚C

This study is framed by the ongoing energy system transition needed to limit climate
change to a 1.5˚C temperature increase above the pre-industrial average. It also
once again highlights that progress towards this goal is far too slow. While the
analysis of fuels in Section 2 indicates that current trends make limiting warming to
1.5˚C unlikely, it remains the case that delivering the energy transition to minimise the
risk of breaching this threshold is a global imperative. Climate change is impacting
all sectors of the economy, both in terms of the energy transition to avoid it, and
global warming driven impacts such as disruption from extreme weather (IPCC,
2022b).

9
When considering the barriers to the global energy transition, and the likelihood of its
success, it is important at the same to keep in mind the significant threat to society,
the environment and the economy if goals to limit climate change are not met.
Even today (at ~1.1˚C global warming), the impacts of climate change are
endangering life and damaging economies, and these impacts will continue to
increase even if temperature rise is limited to 1.5˚C (IPCC, 2022a). If global
temperatures are allowed to rise beyond this, climate change pressures will further
grow through an increased frequency and intensity of droughts, floods and
heatwaves, and even greater damage caused by storms as sea levels continue to
rise (IPCC, 2022a). In addition, the risk of passing six climate tipping points, including
the collapse of the Greenland and West Antarctic ice sheets, becomes likely in the
range of 1.5˚C to 2˚C of global heating (Armstrong McKay et al., 2022).

Estimates of future economic damages are uncertain as scenario models do not

fully include climate impact and adaptation costs, but studies do suggest that costs
will increase non-linearly with global warming levels. For example, under a scenario
with high warming (>4˚C) and limited adaptation, anticipated economic losses are
expected to exceed those during the 2008-2009 recession and the COVID-19
pandemic in 2020 (Pörtner, 2022). Meanwhile, the Swiss Re Institute estimates global
economic value reducing by 18% by 2050 under its 3.2˚C temperature increase
scenario (Swiss Re Institute, 2021). Living with climate change is more costly than the
transition to avoid it.

The economic impacts of a higher than 1.5˚C temperature rise have important
implications for global trade and shipping. As food scarcity is expected in some
regions as a result of climate change impacts on agriculture, there could be a
potential role for shipping as an element of climate change adaptation through
facilitating a shift in trading partners (Zimmermann, 2018). Adams (2021) however
highlights that the risks to agricultural production in a warming world far outweigh
the benefits. Furthermore, the specific infrastructure for shipping that supports food
security is itself vulnerable to climate change impacts. Storm damage to a port is
one such example, another is a flooding event or storm that blocks or disrupts a
major sea channel – also known as a ‘chokepoint’. Chokepoints, such as the Suez
Canal, are known to create widespread supply chain disruption if subject to a
blockage (King, 2022) – something expected to be more likely to occur as global
temperatures rise (Masters, 2021). Moreover climate-related impacts on food
security can have additional multiplier effects impacting on security and conflict,
which in turn becomes an indirect cost to society and the economy associated with
climate change (King, 2022). And while shipping’s interconnected nature provides a
degree of resilience, it also means that disruption to a port not only causes local
impacts, but has global ripple effects across trade-dependent industries including
food, energy and assembled products (Becker, 2018).

10
Figure 1: Schematic illustrating the various ways in which climate change will impact on shipping and
ports, with anticipated rising costs and damage.

To support the energy transition to meet the 1.5 scenarios, shipping needs to reduce
its overall energy fuel demand and transition rapidly to alternative fuels. Furthermore,
the 1.5˚C scenarios imply a reduction in energy trade by ship, as in all cases overall
global energy demand is lower through significant energy efficiency gains, and
coal, gas and oil consumption is reduced. Scenarios exceeding 1.5˚C will also see
impacts on trade, and this is aside from the direct climate impacts on the sector
itself, which include slow-onset impacts to infrastructure maintenance costs from
rising salinity and sea levels. Figure 1 highlights some of the ways in which climate
change impacts on shipping and trade, impacts that are set to increase if an
energy transition to 1.5˚C is not successful.

Table 1 summarises the implications of different global temperature outcomes for

shipping and the wider economy based on IPCC climate impact projections (IPCC,
2022a) and IMO (IMO, 2020) assessments on shipping specific impacts. The key
insight is that transition costs (changing demand and fuels) are linked to climate
change costs. Pursuing a 1.5˚C limit entails a rapid shift in the energy sector with
potentially higher costs than a slower transition, but the costs of climate change
impacts are much reduced (Warren, 2022). Conversely avoided transition costs in a
>2˚C temperature outcome also correspond to increasingly elevated climate
induced risks, with associated adaptation and impact costs.

11
Table 1: Summary of the implications of different levels of global warming for shipping.

Shipping’s Shipping Impacts of Impacts of

transport of fuels sector’s use of climate change climate change
fuel on shipping on global
sector society/economy
1.5oC Very rapid Overall energy Some increased Far higher
transition away demand disruption and impacts than
from transporting reduction plus damage to today, increased
coal, coke, oil; very rapid coastal risk of passing
slower transition transition to infrastructure tipping points
for gas ammonia and
other fuels
2 oC Rapid transition Demand Damage and Catastrophic
away from constant, fast disruption impacts and high
transporting coal transition to NH3 increases, major risk of passing
and oil, very slow and other fuels events more tipping points
for gas likely
3 oC+ Rapid transition Slow transition Major, frequent High risk to
away from coal, to other fuels, damage and human life in
slow transition demand disruption to several regions,
away from oil, constant or infrastructure major ecosystem
very slow on gas increasing collapse

An energy scenario focus

Given the imperative of limiting the global temperature rise to 1.5˚C, this study
begins with a high-level assessment of future energy systems and changing fuel use
within them for widely used scenarios premised on this temperature limit. Scenarios
are selected on the basis that they include no or limited ‘overshoot’ of 1.5˚C,
provide a range of future outcomes and supporting data is readily available. They
comprise: 1.5˚C scenarios produced by the International Energy Agency (IEA),
International Renewable Energy Agency (IRENA) and three distinct 1.5˚C limited
overshoot scenarios from the Intergovernmental Panel on Climate Change (IPCC).

The gap between the required outcomes in the 1.5˚C scenarios and the current
pipeline of low-carbon fuel technology development and deployment is explored.
The potential to close this gap is then examined, with the implications for seaborne
trade discussed.

2. Energy Use in Scenarios for Limiting Global Warming to 1.5˚C

This report considers three sets of future energy scenarios framed around meeting
climate change and sustainable development goals. The scenarios are chosen for
their compatibility with the aim of limiting global warming to 1.5˚C with only a small
overshoot (not exceeding a 1.6˚C temperature increase this century) and data
availability. Scenarios with significant overshoot of 1.5˚C (i.e. reaching 1.7˚C or
above during the century) – for example Shell ‘Sky’ scenario and IPCC Illustrative

12
Pathway Negative Emissions focus scenario - are not included. Two scenarios
produced in-house by international bodies – the International Energy Agency (IEA)
‘Net Zero’ scenarios (IEA, 2021c) and the International Renewable Energy Agency
(IRENA) ‘1.5˚C’ scenario (IRENA, 2022e) - are used. Three scenarios from a wide
range of system modelling communities that have been harmonised and validated
for use by the Intergovernmental Panel on Climate Change (IPCC) are also used,
with varying assumptions for how the 1.5˚C goal is reached; aggressive energy
reduction (as in IPCC Low Demand) (Grubler, 2018); high electrification with
renewables (as in IPCC Renewables and IPCC Sustainable Development) (Soergel,
2021, Luderer, 2021).

Comparing across the different scenarios gives a broad understanding of how

different mitigation pathways would impact the global energy system. The scenarios
however cannot be compared as entirely consistent elements. All of the scenarios
across the three sets are differentiated in how they are produced, the underlying
assumptions on issues such as technology costs and demand, and what parameters
they are working to. Key factors that shape scenarios include:

 The climate change outcome (measured as change in global average

temperature above pre-industrial era) and whether the outcome is based on
the end of the century value (i.e. potential to ‘overshoot’ a temperature
threshold temporarily) or limiting to a maximum across the whole period.
 Underlying macro trends such as population and GDP.
 Meeting different Sustainable Development Goals (SDGs).
 Changes that ultimately lead to differing final energy consumption – energy
efficiency, economic growth and energy access.
 Assumptions on technology costs, learning curves, access and cost of capital,
future energy and commodity prices.
 Resource constraints such as land and water availability.
 Preferences for emergent technologies and expectations on how/if they are
deployed – hydrogen fuels, carbon capture and storage (CCS).1
 The role of carbon dioxide removal (CDR) technologies in the future.

1
Carbon Capture, Utilisation and Storage (CCUS) has a slightly different role in energy scenarios if featured

13
Table 2: Key Features of Scenarios. *Temperature increase above pre-industrial average is the median
value based on MAGICCv7.5.3 for IEA and IPCC scenarios, unclear what is used for IRENA emissions to
temperature determination. Highlighted rows show 1.5˚C based targets. ** IRENA 1.5 based on
emissions pathway 2020 to 2050.

PEAK 2100 TEMP CUMULATIVE FINAL ENERGY

TEMP (˚C)* NET CO2 (2020- CONSUMED 2050
(˚C)* 2100, GtCO2) (EJ)

IPCC - NDC MOD. ACT 2.7 2.7 2,963 552

IEA NET ZERO 1.5 1.4 500 344
IPCC - RENEWABLES 1.6 1.4 440 369
IPCC - SUS. DEVELOPMENT 1.6 1.2 564 355
IPCC - LOW DEMAND 1.6 1.3 227 243
IRENA 1.5 1.5 1.5 **496 348

Table 2 summarises key features of all the scenarios considered in this review. The
IPCC scenario projecting forward CO2 emissions based on national policies as of
2021 - Nationally Determined Contributions (NDCs) - is used for reference: note that
this is not a 1.5˚C scenario. As can be seen, some have a limited overshoot in
temperature at some point but temperatures in all scenarios reduce by the end of
the century. Overshooting 1.5˚C for even a decade can still trigger greater climate
impacts with potentially long lasting or even irreversible effects (notably species
extinction) compared to scenarios that do not exceed 1.5˚C, or have limited
overshoot (IPCC, 2022a). It is also a high risk that CDR cannot be deployed at the
projected scale (IPCC, 2021, Larkin et al., 2018). All five 1.5˚C scenarios rely heavily
on CDR at scale during 2050-2100, with CO2 removals of up to 5 Gt/yr. A more
precautionary approach would see steeper CO2 reductions to 2050, to reduce risks
around relying on CDR.

45
Energy and Process Emissions (GtCO2)

40
35
30
25
20
15
10
5
0
-5
2015 2020 2025 2030 2035 2040 2045 2050
IEA Net Zero IPCC - Renewables
IPCC - Sus. Development IPCC Low Demand
IRENA WETO 1.5 IPCC - NDC Mod. Act

Figure 2: Emissions pathways in the IEA, IRENA and IPCC 1.5C scenarios and the IPCC projection of
current national policies

14
In the 1.5˚C scenarios, the period 2020 to 2025 is an inflection point wherein CO2
emissions must start a sustained decline (Figure 2). If emissions do not begin to
decline before 2025, limiting temperature rise to 1.5˚C will almost certainly not be
possible (IPCC, 2021). The IPCC scenario for current (though pre-2022) Nationally
Determined Contributions (NDCs) and moderate action implies a global emissions
pathway consistent with 2.5-3˚C of warming this century.

There are two main trends common to all the 1.5˚C scenarios. First, the scenarios all
have a reduction in global final energy demand, with four scenarios having similar
demand reductions from 2020 to 2050, in the range of 11-17%, and the IPCC low-
demand scenario having reductions of 42% (Figure 3). This reflects the challenge of
transforming energy system infrastructure in such a short space of time – the lower
the demand, the quicker the transformation can take place.

600

500
Final energy Demand (EJ)

400

300

200

100

0
IMP_REN IMP_SP IMP_LD IEA NZE IRENA IMP_MOD_ACT

2020 2030 2050

Figure 3: Global final energy demand by scenario, 2020 to 2050

Second, electricity provides a far higher proportion of final energy demand,

increasing from 20% to 49-66%. This reflects a greater use of electricity for end-uses
such as cars that currently use other fuels (Figure 4). Electricity is decarbonised also,
with solar and wind becoming the predominant means of generation, compared
with coal and gas today.

15
 70

60
Electricity % of global final energy

50

40
demand

30

20

10

0
IMP_REN IMP_SP IMP_LD IEA NZE IRENA IMP_MOD_ACT

2020 2030 2050

Figure 4: the increasing role of electricity in global energy consumption

These trends lead to a major decline in the use of coal, oil and gas to supply the
global energy system (Figure 5).

700

600
Primary energy supply (EJ)

500

400

300

200

100

0
2020 IMP_REN IMP_SP IMP_LD IEA IMP_MOD_ACT

Figure 5: the decreasing contribution of fossil fuels to global energy supply. Blue and red bars = 2050
values, orange bar on left = 2020 value. Fossil fuels – coal, oil and gas.

Aside from these falls in overall energy demand, and in coal, oil and gas supply, the
1.5˚C scenarios see increases in bioenergy, set out alongside the changes to other
primary energy sources in Figure 6.

16
 800

700
Primary Energy supply (EJ)

600

500

400

300

200

100

0
2020 IMP_REN IMP_SP IMP_LD IEA IMP_MOD_ACT

FOSSIL BIOMASS SOLAR &WIND OTHER

Figure 6: 2050 primary energy by type and scenario. NB: other comprises sources such as hydro, nuclear
etc. and hydrogen as a secondary fuel will be captured within ‘fossil’ or ‘solar & wind’ depending on
whether it is grey, blue or green.

The scenarios also have a major increase in “secondary” energy production of

hydrogen, produced either from fossil fuel use with carbon capture and storage
(“blue” hydrogen), or electrolysis using solar and wind electricity (“green”
hydrogen). The growth in hydrogen varies considerably by scenario however, and
this is discussed in detail in section 2.1.

The tonnage of fuel used in the 1.5˚C scenarios also declines, despite the lower
energy content of some of the alternative fuels. Biomass and liquid biofuels have a
lower calorific value (~16 to 27 EJ/Gt) in comparison with coal, oil and natural gas
(~26 to 48 EJ/Gt), so when they substitute for fossil fuels, a greater tonnage of fuel is
required for the equivalent energy provision. These issues are complex – for example
in the case of hydrogen-based products, the energy per unit volume and the
energy per tonne vary greatly depending on whether the fuel is in the form of either
liquid hydrogen, gaseous hydrogen or ammonia. The volumetric energy density also
depends on the temperature and pressure conditions required to transport the fuel.
Overall, it is expected that per unit of energy, hydrogen-based products will require
more volume to be transported (Mestemaker et al., 2019).

These changes are important to understand, but it is the large increases in electricity
from renewable sources to meet energy needs that has a greater influence on fuel
volumes. This means that overall there will be a significant reduction in the tonnage
of fuels required in the 1.5˚C scenarios (Figure 6).

The scenarios show that a 1.5˚C transition reduces the global quantities of coal, oil
and gas produced, transported and consumed, and increases the quantities of
hydrogen and biomass. The next sections look in detail at hydrogen and biomass.
For hydrogen, section 2.1 assesses the quantities required in 1.5˚C scenarios,
particularly in the near term to 2030 and compares this with an assessment of likely
production from hydrogen projects. The gap between current projections and
required production is assessed in relation to developments in hydrogen deployment

17
and policy in leading nations. Trends and requirements in biomass and fossil fuels are
discussed in sections 2.2 and 2.3.

Section 3 assesses the implications of these changes for shipping. Changes to fuel
production locations and changes to the types and quantities of energy required by
different national economies affect the future need for transportation of coal, oil,
gas, biofuels and hydrogen from producer to consumer. Geography and economics
are two critical factors determining whether this transport would be by truck,
pipeline, rail, plane or ship.

2.1 Hydrogen in 1.5˚C Scenarios

Hydrogen as a fuel is an emergent energy vector that is currently not established
within the global energy system, but is expected to have a significant role in future
low-carbon energy systems. Today hydrogen is primarily used for producing fertiliser,
oil refining and steelmaking, and not, for example, as a transport fuel. It is produced
almost entirely through the use of unabated fossil fuels – either directly through
processes such as steam methane reformation (SMR) and coal gasification or as the
by-product of another industrial process (often petrochemical). Scenarios for 1.5˚C
envisage new roles for hydrogen as a transport fuel, heating buildings, in high
temperature industrial processes and for power generation through combustion and
fuel cells. As well as new uses, scenarios for 1.5˚C also entail a wholesale change in
the production of hydrogen from current methods (referred to as ‘grey’ hydrogen)
to one of the following:

 Electrolysis whereby electricity is used to separate hydrogen from water with a

polymer electrolyte membrane (PEM), alkaline or solid oxide electrolysers.
Electrolysis supplied by renewable energy is typically referred to as ‘green
hydrogen’.
 SMR, autothermal reformation (ATR) and natural gas decomposition with
carbon capture and storage (CCS). This is typically referred to as ‘blue
hydrogen’.
 Biomass conversion routes through thermochemical and fermentation
processes.
Low-carbon hydrogen is still at a very early stage of commercialisation, and so in
any future scenario for limiting global warming to 1.5˚C with a role for hydrogen as a
fuel, there needs to be a rapid scale-up of new hydrogen production capacity.
Figure 7 shows the 2030 production of low-carbon hydrogen2, predominantly for new
uses, across the scenarios.

2Although other “colours” of hydrogen are possible, this report assumes that the
overwhelming majority of low-carbon hydrogen will be green (electrolysis using renewable
electricity) or blue (fossil fuel + CCS).

18
 180
Blue/Green Hyrdogen production (Mt)
160

140

120

100

80

60

40

20

0
IPCC REN IPCC SP IPCC LD IEA Net Zero IRENA IPCC MOD ACT
Figure 7: Low-carbon Hydrogen supplied for the energy system in 1.5˚C energy scenarios in 2030 (EJ)

There is a wide variation in low-carbon hydrogen production by 2030 across

scenarios. This range continues out to 2050, with production in the range of 150-600
Mt per year in 2050 – reflecting the uncertainties around the extent to which
hydrogen will penetrate into different economic sectors.

In the IRENA 1.5˚C low-carbon scenario, hydrogen supply for energy use (including
to produce hydrogen derived fuels such as ammonia) increases very rapidly – from
negligible in 2020, to ~20 EJ/year in 2030, before reaching ~70 EJ/year by 20503. The
IPCC 1.5˚C scenarios used in this report project lower levels of hydrogen supply to
meet their emissions pathways.

Within these global hydrogen demand figures there are sectoral breakdowns for
2030 indicating where the scenarios envisage hydrogen demand happening and
how hydrogen is used. The IPCC Renewables, Low Demand and Sustainable
Development scenarios provide a longer-term breakdown of hydrogen energy use
by sector. They show a model preference for hydrogen use in industry and transport
over the residential and commercial building sector. This likely reflects the relative
costs and competition with alternative low-carbon options for which there are fewer
in heavy freight transport and industrial processes. The focus of hydrogen-based
fuels in scenarios tends to be where the direct use of electricity is less feasible,
consequently there is lower increased demand for hydrogen products in light road
transport and heating buildings. There is also the potential for some transitional use of
ammonia as a fuel in power stations, co-firing with coal or gas to lower these power
stations’ emissions, as being developed in Japan, India, South Korea and China
(Atchison, 2022d, IHI Corporation, 2022, Xie, 2022).

2.1.1 The hydrogen production gap

There are two essential requirements for hydrogen for compatibility with a 1.5˚C
pathway. First, existing grey hydrogen for non-energy uses needs to be replaced

3
EJ to Mt conversion = multiply by 8.1

19
with low-carbon production methods. Second, accelerated production of low-
carbon hydrogen is needed for new energy sector uses, for example as shipping
and aviation fuel, for power, and in industrial processes such as steel and cement
production. This section compares planned production with these scenario
requirements.

There is a growing pipeline of new hydrogen projects, with many more being
announced every year. However there is great uncertainty as to what percentage of
these projects will become operational and if they will be on time.

The IEA maintains a database of planned blue and green hydrogen projects. Their
September 2022 Global Hydrogen Review states that if all the announced projects
are realised, then low-emission hydrogen production could be 24 Mt/yr by 2030, split
between 14 Mt green hydrogen, 10 Mt blue (IEA, 2022d).

60000

50000
Normalised H2 capacity (kt)

40000

30000 2021
2022
20000

10000

0
Concept Feasibility study Final Investment Under construction Operational
Decision

Figure 8: Status of Hydrogen projects in 2021 and 2022

These figures come with major uncertainties. On one hand it could be seen as an
upper-bound, because the overwhelming majority of these projects are only at
feasibility or concept stage, with under 4% being in operation, under construction or
with a final investment decision (FID) (Figure 8). On the other hand, the projected
pipeline is growing very rapidly – in the October 2022 update of the IEA’s database
(IEA, 2022e), the total normalised hydrogen capacity of all projects had increased
by 50% compared with October 2021, from 66 Mt/yr to 100 Mt/yr of normalised
production capacity4. Beyond the overall increase in projects, some additional
stand-out changes in the twelve months from October 2021 to October 2022 are:

 85% of the capacity in new announcements is for electrolyser projects;

4
These figures are so much higher than the projected actual production of 24 Mt/yr because i) they are
normalised capacity figures, ie for green hydrogen projects they don’t take into account the load factor of the
electrolyser, and ii) because the overall database contains many projects whose completion date is either post
2030 or currently unknown.

20
  Although operational/final investment decision projects have stayed broadly
constant, projects are moving rapidly from “concept” to “feasibility study” –
with the capacity of projects in the feasibility study category more than
doubling in the last year;

 There is a major increase in the number of projects with a completion date of

2025-2027, and also 2030;

 2022 has seen some new countries emerge as major players – notably the
USA, Argentina, South Africa and Egypt – as well as some existing countries
announcing new large-scale projects (Australia, Chile, UK). The biggest
increases during 2022 are shown in Figure 9 and the countries with the largest
portfolios of projects are shown in Figure 10.

8000

7000

6000
Normalised capacity (kt)

5000

4000

3000

2000

1000

Figure 9: Countries with the biggest increases in new proposed low-carbon H2 projects between October 2021 to October
2022

21
 Australia
RoW

Spain/France

China
Argentina
Oman
USA
Chile
Kazakhstan
Mauritania UK
Germany Netherlands

Fig 10: Countries with the greatest quantity of proposed low-carbon hydrogen production

Overall, the IEA’s value of 24 Mt/yr low-carbon hydrogen production by 2030 can be
seen as a best-estimate, but in practice the actual value achieved could easily be
much lower or higher.

Figure 11 compares this 2030 production estimate with the quantities of low-carbon
hydrogen required by that date in the 1.5˚C scenarios. It assumes first that major
progress would be needed in decarbonising the existing hydrogen production: the
IPCC assumes that as an average across all sectors, around 43% global emissions
reductions are required by 2030 for 1.5˚C pathways (IPCC, 2022b). As a first-order
estimate, this figure is applied to the hydrogen sector – meaning that around 31 Mt
of low-carbon hydrogen is needed5. Moreover, the five scenarios estimate
additional hydrogen that would be needed for new uses – these values vary greatly
between scenarios, with considerably less hydrogen required in both 2030 and 2050
in the IPCC scenarios compared with the IEA/IRENA scenarios. However, even in the
lowest demand scenario, the gap is over double that of estimated 2030 production.
So, despite the rapid increase in new projects in just the last 12 months, greater
capacity and on a much accelerated timeline is needed to bring this in line with the
1.5˚C scenarios.

5
2020 production was 90Mt, 72.7 Mt from fossil fuels (16 Mt as by-product from chemical processes); this
estimate then assumes that 31 Mt (43%) of this would need to be replaced with low-carbon hydrogen.

22
 180
Low-carbon hydrogen required to fill the gap (Mt)
160

140

120

100
Existing uses
80
New uses

60

40

20

0
Operational Proposed IPCC REN IPCC SP IPCC LD IEA Net IRENA
Zero

Figure 11: The gap between proposed 2030 low-carbon hydrogen (green), and what is needed in 1.5˚C
scenarios (blue/red). IRENA values as expressed here merge low-carbon hydrogen for existing and
current uses (yellow).

2.1.2 Closing the hydrogen gap

There are drivers and barriers affecting whether this gap could be closed,
summarised for green hydrogen in Table 3. For blue hydrogen similar barriers exist in
terms of supplier-producer agreements. Additionally, this pathway requires
interactions with carbon capture and storage infrastructure, which is slow to
develop. The Northern Lights sequestration project in Norway working with ammonia
producer Yara is one of the most advanced blue hydrogen projects (capturing CO2
from ammonia production) with a timetable to begin operation in 2025 (Yara,
2022a). Projects such as this and the UK blue hydrogen projects such as HyNet, must
run on, or ahead, of schedule and scale up rapidly to align with quantities in the
1.5˚C scenario pathways. They also need to demonstrate consistent capture rates of
>90% are possible in commercial operation. This would entail speeding up of
government decision making on financial support – particularly when natural gas
prices are high – and regulatory and liability issues around carbon storage being
resolved.

23
Table 3: Drivers and barriers for green hydrogen projects:

Drivers Barriers
Increasing number of announced Lack of supportive domestic policies for
projects – new Giga-scale projects hydrogen projects in many countries
every month
Many bilateral hydrogen agreements Higher relative costs for green
forming hydrogen/ammonia versus grey will
return if gas prices fall

Falling electrolyser costs Very few projects are as yet progressing

to final investment decisions
Falling solar and wind costs Few concrete agreements between
producer and consumer
Current high gas prices in Europe/Asia In shipping, ammonia twice as
dramatically improves economics of expensive as MGO; no carbon price
green vs grey/blue hydrogen and which would make a material
ammonia difference is likely in short or medium
term

There is a coordination issue potentially holding development of hydrogen in limbo,

with hydrogen projects requiring buyers before final investment decisions are made,
and sectors planning a move into hydrogen being unsure of supply. These are
compounded by major further infrastructure investments often being needed to
deliver hydrogen products from producers to consumers. The priority is therefore to
convert the current explosion of interest in hydrogen into actual projects in the
coming few years. Increasingly there may be collaborations which seek to
overcome coordination problems by linking many or all of the stages in the green
ammonia/hydrogen supply chain, for example the recent initiative by Amon
Maritime (Stott, 2022a).

Government policies that can bridge supply and demand – providing investors on
both sides with greater confidence in the transition to low carbon hydrogen – will be
an important factor in whether the gap between low-carbon hydrogen use in 1.5˚C
scenarios and the current situation can be closed. This applies both to regions
expected to be net importers of low-carbon hydrogen providing incentives and
regulatory certainty around future demand, and potential exporter countries
supporting investments in production capacity and supply infrastructure.

There are a number of major reports which have assessed the types of policy
needed to accelerate low-carbon hydrogen deployment (IEA, 2019, IEA, 2022d,
IRENA, 2022b). These policies have been categorised into five types:

 measures to reassure investors of a future market-place, such as national

targets and hydrogen strategies;

 standards and certification policies to ensure robust sustainability benefits;

 policies to stimulate demand for low-carbon hydrogen;

24
  supply-side support, to accelerate investment in low-carbon hydrogen
production, storage and transportation infrastructure;

 RD&D support for demonstration projects for elements of the hydrogen supply
chain not yet fully market-ready (IEA, 2022d).

Recent reports cite literally hundreds of policies and give examples of planned or
recently introduced measures across dozens of countries, right across the hydrogen
supply chain. To a degree, the issue at hand is not so much that policies are
needed, but which are the highest priority.

Assessing the most appropriate suite of policies is beyond the scope of this report,
however certain measures introduced in the last year appear to be strong
candidates for wider uptake. We highlight four here:

Using quotas and mandates: up until 2030, the biggest potential source of demand
for new low-carbon hydrogen projects will be through replacing grey hydrogen in
existing industrial processes, with green hydrogen. India has included within its
evolving hydrogen strategy the potential to mandate rising percentages of green
hydrogen within both fertiliser and refinery sectors (Staines, 2022). Similarly, in May
2022 the European Commission launched its RepowerEU package (European
Commission, 2022a) to make Europe independent of Russian fossil fuels. This includes
a major expansion of hydrogen, including an import target of 10Mt renewable H2 by
2030. However the majority of this import target does not yet have clear markets. Use
of increasing quotas, as being suggested in India, would accelerate the
decarbonisation of EU refineries and fertiliser sectors, and increase demand for
hydrogen projects in other countries.

Contracts for difference: two problems for low-carbon hydrogen are uncertainty for
suppliers that they will have long-term buyers, and demand-side concerns regarding
price. Contract for difference-style policy mechanisms can overcome both. One
initiative by the German Government (H2 global, 2022) creates a double auction:
first, producers bid for 10-year Hydrogen Purchase Agreements; second, consumers
bid for Hydrogen Supply Agreements. The price difference is paid by an intermediary
company, funded via the German Government. The details are being finalised
(Freshfields Bruckhaus Deringer, 2022), with first delivery periods anticipated being for
2024 to 2033.

Hydrogen production credits: on the production side, in August 2022 a mammoth US

Inflation Reduction Act was passed – including a package of measures aimed at
boosting the hydrogen economy. The major element of this package is the Clean
Hydrogen Production Credit, which introduces a 10-year sliding-scale of credits for
hydrogen production, depending on carbon reductions – reaching $3/kg for green
hydrogen projects, which is widely seen as large enough to allow green hydrogen to
compete with grey hydrogen today (Webster, 2022), even with the USA’s far lower
than global average gas prices.

Prioritising end-uses: given the short- and medium-term gap between low-carbon
hydrogen requirements for 1.5˚C, and likely production volumes, government clarity

25
on the priority end-uses for hydrogen is particularly important. Hydrogen’s
production and storage is too energy-intensive for it to be wasted on sectors where
there are alternatives. Beyond its essential uses in non-energy sectors such as fertiliser
production, hydrogen’s energy uses are best targeted at sectors where
electrification is more difficult – such as shipping, aviation and steel manufacture.
Governments should not be prioritising hydrogen use in buildings, most forms of road
transport or power generation. A typology for a hierarchy of hydrogen use is set out
in Figure 12.

Figure 12: Hydrogen Ladder (Leibrich, 2021)

Finally, increasingly there are collaborations seeking to overcome coordination

problems by linking many or all of the stages in the green ammonia/hydrogen
supply chain, for example the recent initiative by Amon Maritime (Stott, 2022a),
Clean Energy Maritime Hubs (Clean Energy Ministerial, 2022) and the Silk Alliance
Green Corridor/hubs project for container shipping in Asia (Lloyd's Register, 2022).
The actions of Maersk in agreeing contracts for supply of fuel for its new methanol
vessels are a further example of forging stronger links between producers and
consumer (Maersk, 2022)6.

6
Methanol emits CO2 when burned, so to be carbon-neutral would either need to be produced from
sustainable biomass (biomethanol), or from captured carbon dioxide and hydrogen produced from renewable
electricity (e-methanol).

26
2.1.3 National hydrogen strategies

Figures 13 and 14 summarise progress on national low-carbon hydrogen strategies

for countries expected to be leading consumers or producers in the emerging low-
carbon hydrogen transition. The figure also highlights where there is interest in acting
as international trading hubs for hydrogen – e.g. Singapore and the Netherlands.

Figure 13: Progress on Implementing national hydrogen strategies of import focused countries. *In development refers to
low-carbon hydrogen projects currently in construction, final investment decision, planning or concept stage. Import
orientated status determined by stated aims in national strategies or scenarios/hydrogen literature as future blue/green
hydrogen importers.

27
Figure 14: Progress on implementing national hydrogen strategies of export focused countries. *In development refers to
low-carbon hydrogen projects currently in construction, final investment decision, planning or concept stage. Export
orientated status determined by stated aims in national strategies or scenarios/hydrogen literature as future blue/green
hydrogen exporters.

National hydrogen strategies have become more widespread and detailed in

recent years, however countries are at different stages of development. The front
runners in this regard are Japan, South Korea and Germany. These nations have
plans to stimulate industrial demand for hydrogen and ammonia fuels, trade deals
with prospective exporter countries such as Australia, Saudi Arabia and Chile, and
have also explored transportation options. These front runners also highlight the
issues currently facing hydrogen and its derived fuels for energy usage. There is not
yet a significant supply of low-carbon hydrogen production to meet the targets set
in these hydrogen strategies even between the leading nations. Getting volumes of
blue and green hydrogen to flow between producers and users is the emergent
challenge for national hydrogen strategies – and for going further to meet the goals
of 1.5˚C scenarios. Ultimately more low-carbon hydrogen production must come
online in the next few years to meet even the slower growth rate of hydrogen
reported in the IPCC 1.5˚C scenarios.

28
Table 4: Examples of key investments announced for hydrogen projects - all values normalised to US$

Country Government announced investment Private sector/expected

investment
Japan Government R&D funding of $344 million $3.4 billion private sector
announced(Nakano, 2021) funding expected.
South N/A 10 year fund from private
Korea sector coalition worth
$383million (Hydrogen
Central, 2022).
Germany $8.1billion investment announced for Plans to trigger $38.3billion
speeding up market rollout of technology, of private investment.
and £2.3 billion for fostering international
partnerships. Further $9.7 billion related to EU
scheme (Huber, 2021).
Singapore $49million announced by government as a N/A
research and development fund (Ning,
2021).
EU $5.4 billion announced for important projects Dependent on member
of common European interest (IPCEI) in the states.
hydrogen technology value chain (European
Commission, 2022b).
Australia Government funding round of $47million Private investment to sector
announced and received by successful valued at $88-123billion
applicants (Australian Government, 2020). (Singh, 2022).
$2 billion investment into green hydrogen also
approved by New South Wales Government
(Carroll, 2021).
UK £240million net zero hydrogen fund, and Unlocking of $4.5 billion
£60million for low-carbon hydrogen supply, as private sector funding
well as further funding for other projects expected.
involving hydrogen such as net zero transport
(£183million), low-carbon fuels(£315million),
and energy storage(£68million) (UK
Government, 2021).
Spain Allocation of $1.5billion to green hydrogen Expected attraction of
development as part of its 2 year energy plan $9.3billion in private funding
(LSE, 2022). expected for renewables,
green hydrogen and energy
storage (Reuters, 2021).
Chile N/A Private investment of over
$1billion sanctioned by
government (Walne, 2022).
Saudi N/A £36 billion in private sector
Arabia investment expected
(FuelCellsWorks, 2022).
Namibia N/A $9.4 billion of private
funding announced
(FuelCellsWorks, 2021)
Netherlands $740million announced as available from Private investment plan of
government for green hydrogen transport $8.9billion announced
network (Biogradlija, 2022). (Gasunie, 2020).
(NB: all values cited converted from original currencies into US$, based on exchange rate at
time of writing: 1USD= 1.01euro=0.88GBP=1.51 AU$)

29
The following two case studies look in more detail at two of the most developed
regions for low-carbon hydrogen production – Australia and Europe.

Case Study: Australia

Australia is relatively advanced in moving forward as a potential low-carbon

hydrogen exporter. It has the largest quantity and capacity of potential new
hydrogen projects, existing port infrastructure for ammonia export, and very high
renewable energy resources, planned projects near ports, and low costs of capital
(IRENA, 2022b).

For a number of years, Australia has been developing a potential ammonia trading
relationship with Japan, South Korea and Singapore. These are the most long-
standing and advanced bilateral agreements on low-carbon hydrogen production
and consumption. Further large consumer-supplier relationships between Australia
and Germany (e.g. Fortescue and E.ON) have increased the importance of
developments in Australia for the global low-carbon hydrogen trade.

Proposed hydrogen projects are spread across Australia – ten of the largest are set
out in Figure 15.

Figure 15: Spatial Distribution of low-carbon hydrogen projects announced as of October 2022 (Source; IEA Hydrogen
Project Database, 2022).

Table 5 highlights key attributes of the proposed projects in terms of their suitability
for seaborne export. Projects in the North East are located near to major port
infrastructure at Gladstone but are currently at relatively small scale. Larger projects
on the West coast are located in the vicinity of port infrastructure for iron ore export,

30
however the largest announced project – the Western green Energy Hub is further
from large port infrastructure. Overall Australia has significant proposed capacity
located near to suitable port infrastructure.

Table 5: Summary of proposed hydrogen projects in Australia

Project Type Normalised Notes

capacity
(kt H2)
WGEH Green NH3 3601 Longer distances to Asian markets. FID
expected after 2028
AREH Green H2 and 2426 Very close to the Pilbara iron ore ports
NH3
HyEnergy Green H2 1386 Export focus
Desert Green H2 1386 Inland project
Bloom
Murchison Green H2 and 750 Asia export focus
NH3
Stanwell Green H2 520 Local industry and export
H2Perth Green & Blue 520 Domestic uses and export
H2 & NH3
Gladstone Green NH3 494 Major port infrastructure at Gladstone
Tiwi Green H2 485 Very close to Port Melville
islands
Sun Green NH3 454 Export to Korea and Japan
Brilliance

Beyond production, other aspects in the hydrogen/ammonia chain show progress,

such as:

 Bilateral hydrogen agreements with Japan (Japan and Australia, 2020),

Singapore on Maritime fuels, June 2021(Six, 2021), and South Korea (Morrison,
2021, Paul, 2022) including specific 200kt export deal (Vorrath, 2021).

 Producer to producer agreements:

o Pipeline proposal green hydrogen to domestic ammonia production
plant (Atchison, 2022b);
o Offtake agreement for domestic use of green ammonia production
(Atchison, 2022a);
o Fortescue (Australia) and Covestro (Germany), 100ktH2/yr (Petrova,
2022);
o Fortescue and E.On (Germany) memorandum of understanding re 5Mt
H2/yr (E.On, 2022).

 Other elements of supply chains:

o Electrolyser manufacturing plant construction starts at Gladstone
(Fortescue Future Industries, 2022);

31
 o April 2022, letter of intent re iron ore Green Corridor between Australia
and East Asia, from BHP, Rio Tinto, Oldendorff Carriers, Star Bulk Carriers
(BHP, 2022);
o Rio Tinto & Anglo Eastern plan ammonia-powered bulk carriers for Port
of Newcastle (Atchison, 2022e).

Despite the large number of potential projects and agreements in Australia, the
industry is nascent. It appears that projects have remained in limbo awaiting
investors to commit capital to production facilities. The absence of clear consistent
signals and support from the government in the transition from fossil fuels is a
contributing factor (Fernyhough, 2022) – with the introduction of tax breaks (such as
the USA’s recent tax credit in the Inflation Reduction Act), carbon pricing and a
clear renewables strategy cited as necessary. In addition, having guaranteed
markets is seen as a prerequisite for project success, for example through the
negotiation of long-term bilateral contracts for green hydrogen. Such contracts
have been pivotal in the development of Australian LNG exports in the 2010s, with
multiple 20-25 year high-volume LNG contracts signed between Australia and
Chinese companies CNOOC, Petrochina and Sinopec (Yin and Lam, 2022).

The change in Australian Government following the May 2022 general election is
likely to lead to stronger climate policy in general, potentially leading to a more
supportive policy environment for green hydrogen projects. This may be helped by
the delivery of a planned National Hydrogen Infrastructure Assessment, due in 2022.
As these projects get nearer to construction there may be further barriers associated
with bringing large infrastructure projects through to planning consent. The large
Western Australia AREH project (1.6 Mt Hydrogen per year) has faced challenges
over its environmental impact on wetlands, and the Western Green Energy Hub
(WGEH) has been successful only through working with Aboriginal groups to allay
concerns (Greenhalgh, 2022). At present analysis appears to show that the lack of
supportive national policy is a key reason for difficulties in project delivery (Parkinson,
2022, Thornton, 2022). If this were resolved there could potentially be a step change
in global low-carbon hydrogen production via the realisation of the project pipeline
in Australia.

Case Study: European Union

The EU’s ambition on hydrogen has increased significantly in the last three years, with
an industry-led roadmap in 2019 (FCH, 2019) leading to the publication of a
Hydrogen Strategy in 2020 (European Commission, 2020), then the “Fit for 55”
package in 2021 (European Commission, 2021), and further strengthening of
ambition and policy in the May 2022 RepowerEU proposals (European Commission,
2022a).

The EU’s focus has been specifically on developing renewable hydrogen – the initial
2020 strategy set the strategic objective of 10Mt of renewable hydrogen production
in the EU by 2020. The 2022 RepowerEU set an additional target of 10Mt of
renewable hydrogen imports by 2030. To date the import focus has been on
hydrogen corridors with nearby nations – highlighting the North Sea, Ukraine and the
Mediterranean. So far, wider bilateral relationships at EU level are limited - the 2019

32
joint statement by Japan, the European Commission, and the USA (USA DoE, 2019)
to strengthen trilateral cooperation is limited to technology cooperation, data
sharing and joint research. However individual EU states have pursued a range of
bilateral hydrogen agreements with more distant nations, for example France with
India in October 2022 (Economic Times, 2022)(and see next section).

Member states have their own more developed plans for hydrogen. Most notably;

Spain: Spain may have a key role in EU hydrogen trade, via pipelines. Projects in
development would make up almost 50% the EU’s production capacity pipeline.
However, slow progress is seen in achieving this. Despite export goals, Spain has not
signed any bilateral agreements on hydrogen trade. Currently operating production
of green/blue hydrogen is negligible, especially compared with the targets set by
projects in development. There are limited developments in the shipping of
hydrogen and its derivatives from Spain. The majority of transport projects are
focused on pipelines, including proposed plans for hydrogen pipelines to Portugal,
France and Italy. A further identified potential pipeline route would be between
Spain and Morocco, therefore, opening up pipeline trade between Africa and the
EU. Therefore, despite Spain’s large potential for production, its interactions with the
international shipping trade may be minimal.

Germany: National policy of Germany on hydrogen includes expectations that

Germany will need to import hydrogen products from abroad, as well as producing
it (German Federal Government, 2020). The hydrogen strategy therefore discusses
preparing infrastructure for future hydrogen supply, including production, transport,
storage and use, and building trust in a hydrogen economy. It also includes
proposals to develop transport and distribution infrastructure is key to import
hydrogen. Reducing reliance on Russian gas in the medium to longer term is one
driver in potentially accelerating a move to hydrogen.

There is investment in production facilities, however current capacity is very small at

0.01 MtH2/yr (IEA, 2021a), compared with projects in development expecting
capacity of 3 MtH2/yr, showing that there is significant work to be done to achieve
this. Germany’s high potential energy demand and geographical location may
mean that importing from the Netherlands, Norway, Spain, and other closer
European countries is necessary in the future. Recent bilateral trade agreements on
hydrogen have been developed with Chile, Saudi Arabia and Australia. All these
countries would require hydrogen or ammonia shipping to import hydrogen into
Germany.

The new H2Global double auction policy (see Section 2.1.2) will reimburse sellers for
the transport, logistics, and import duty costs of importing green hydrogen derived
products. This means that the import of ammonia, methanol, and kerosene from
green hydrogen will be promoted, and notably the initiative aim is to work with non-
EU suppliers. This opens up the potential of the establishment of a hydrogen
derivative shipping trade, between Germany and other nations.

Overall it looks like there is commitment to expanding the market for hydrogen
energy products. Export of hydrogen production technology is also discussed in the
strategy, mentions green hydrogen production as a stimulus for developing countries

33
to rapidly expand renewable capacity, and benefit local markets. Technology or
other bilateral agreements are with Singapore, UEA, New Zealand, Norway,
Canada, Tunisia, Netherlands, Ukraine, Nigeria, China, Namibia and Japan.

Netherlands: The Netherlands’ ambition to become an export nation is set out in its
hydrogen strategy (Government of the Netherlands, 2020). Developments in
Germany (such as increased hydrogen refuelling stations) are significant to the
Netherlands, as some of this demand will have to be met through imports that enter
Europe through the Netherlands. Therefore, the port of Rotterdam is set to be key in
future hydrogen use in Europe, giving hydrogen and ammonia exporters access to
the European market. The port was named as the “most active” organisation
concerning international cooperation on hydrogen by the IEA.

Notably, the Netherlands has expressed interest in expanding existing infrastructure

to increase ammonia imports. The port of Rotterdam is planned to expand its
capacity for ammonia from 4000ktpa, to 1.2Mtpa by 2023, and invest in a port side
ammonia-to-hydrogen cracking facility that will be operational by 2026. Investing in
these new facilities could strengthen the Netherlands’ position as a hydrogen
supplier for the rest of Europe.

The strategy states that intercontinental transport is expected to take place by sea,
likely in the form of ammonia, but transport across Europe will be cheapest via
pipeline. The green octopus project aims to connect pipelines with seaports,
therefore, opening up trade between further EU nations and non-EU hydrogen and
ammonia suppliers. This could be advantageous for EU nations that have significant
energy demands, but have less developed port infrastructure than the Netherlands.

The Netherlands is additionally exploring the possibility of intra-EU hydrogen shipping

from Portugal. This is the only current example of a hydrogen shipping project
planned within the EU, and would involve the shipping of 1Mtpa of hydrogen
annually.

According to the IEA database the largest operational green/blue hydrogen

production site in both Europe and worldwide, (1MtH2/yr) is the Shell heavy residue
gasification CCU - Pernis refinery. This site will utilise carbon capture in 2024, after the
Porthos carbon storage project is realised in Rotterdam (Porthos Project, 2022).
Capacity of projects in development stage is 5.6MtH2/yr, meaning the ambition is to
increase current production capacity by over five times

Overall the Netherlands’ focus is on trade and market development. The strategy is
well developed relative to other national hydrogen strategies, as it discusses next
stages related to introducing regulation and laws related to hydrogen, as well as
mentions of specific projects and future relationships. Even if the Netherlands does
not become a major producer, its position in Europe related to sea trade means that
it is still a key part of future hydrogen trade. Netherlands had bilateral trade
agreements with Chile, Namibia, Canada, Portugal and Uruguay, all countries with
export ambitions. This suggests that the Netherlands’ position as an exporter may be
related to re-selling and re-exporting hydrogen to the rest of Europe via Rotterdam.

34
2.2 Bioenergy in 1.5˚C Scenarios
Bioenergy has a more established supply chain when compared with hydrogen. In
2020 solid biomass and biofuels met 9% and 1% of global final energy demand
respectively (IEA, 2021c). Biofuel increases to-date have been largely driven by
government policies on tax and minimum content obligations in road transport and
aviation fuels, while demand for solid biomass for heat and power generation has
grown quickly in Europe due to subsidies and given its strong potential for use as a
drop in fuel using existing infrastructure (IEA Bioenergy, 2018).

Bioenergy is expected to increase to some extent in all of the 1.5˚C scenarios

examined, with the exception of IPCC Low Demand where primary bioenergy
decreases slowly by 2050. Figure 16 shows modern bioenergy primary energy
(biofuel gases, biofuel liquid and modern solid biomass) increasing from 38 EJ/yr to
between 45 EJ/yr and 99 EJ/yr by 2030, and between 54 EJ/yr and 153 EJ/yr by 2050,
while traditional biomass reduces to 0-5 EJ by 2050.

180
2050
160

140
Primary Bioenergy (EJ)

120
2030
100
2020
80

60

40

20

0
Baseline IEA NZE IRENA IPCC IPCC SD IPCC LD IEA NZE IRENA IPCC IPCC SD IPCC LD
1.5 Ren 1.5 Ren

Biofuel Liquid Biofuel Gases Modern Solid Biomass Biomass Combined Tradition Solid Biomass

Figure 16: Primary Bioenergy Supply in Energy Scenarios (EJ). The IPCC Low Demand scenario does not break down biomass
by type Modern bioenergy = biofuel liquid +biofuel gases +modern biomass.

As well as changing trends in bioenergy demand, the characteristics of bioenergy is

expected to transform in three ways across the scenarios:

1: Changes in feedstock – from traditional biomass use (e.g. wood fires, charcoal) to
modern biomass (pelletised fuels, liquid and gas bio products), and from first
generation biofuels reliant on food crops (such as corn and soy) to second
generation ‘advanced biofuels’ using forestry residues, energy crops grown on
marginal land and wastes.

2: Changes in application – trending away from uses in power and road transport,
towards the hard-to electrify sectors such as aviation, shipping and to generate heat
for industry.

35
3: Interaction with carbon removal – with the exception of the IPCC Low Demand
scenario, all of the 1.5˚C scenarios in this study (and more widely (IEA Bioenergy,
2022)) feature bioenergy carbon capture and storage (BECCS) to balance out
excess GHG emissions in their carbon budgets.

Traditional biomass is currently ~40% of primary biomass energy (IEA, 2021c). This form
of bioenergy is typically unsustainable in the methods used to source biomass and
inefficient in the methods used to convert it to energy, therefore phasing out this
form of bioenergy will be vital to achieving emission targets (Welfle et al., 2020). In
the IEA NZE and IRENA 1.5˚C scenarios, traditional biomass is completely phased out
by 2030, while in the IPCC Renewables and Sustainable Development scenarios this
phase out is more gradual, and largely happens between 2030 and 2050. Therefore
a very rapid and sustained growth of modern bioenergy will be required to balance
biomass energy demands in the 1.5˚C scenario. The international trade of biomass
and biofuels is expected to increase as overall demand for modern solid biomass
and biofuels grows, as not every nation has adequate domestic feedstock supply to
meet domestic demand (IEA Bioenergy, 2022). This will require new cooperative
practices between agriculture, forestry, waste and the energy sectors and effective
policy mechanisms to monitor, regulate and ensure sustainability, technical and
carbon performances (IEA Bioenergy, 2022).

Another key feature is the transition away from ‘conventional’ (1st generation)
biofuels that rely on agricultural land to be produced (such as sugar cane and corn
ethanol) to ‘advanced’ (2nd generation) biofuels that do not directly compete with
food production (such as agricultural residues, waste and woody crops). The IPCC
Renewable scenario specifies second generation bioenergy crops (grassy and
woody varieties) in its scenarios description (Luderer, 2021). IPCC Low Demand
avoids competition between biofuels and food security by limiting biofuel use,
predominantly through reduced transport energy demand (Grubler, 2018). Across
the IPCC illustrative pathways there is a transition to advanced biofuels in the
medium to longer term (IPCC, 2022b). In IEA NZE scenario most of the increase in
liquid biofuels by 2030 – from 3.8 EJ/yr to 12.5 EJ/yr – is from new advanced (second
generation and beyond) biofuel production methods, and between 2030 and 2050
there is a wholesale shift away from 1st generation biofuels (IEA, 2021c).

As well as changing the type of biomass used in bioenergy applications, the 1.5˚C
scenarios imply a change in use in the energy sector. By 2050, the IEA NZE scenarios
project that 74% of biomass feedstock supply will be solid biomass, 15% liquid biofuels
and 14% biogases. The projected end-users of the solid biomass derived bioenergy
will be directed for fuel switching in industries that require high-temperature heat,
such as cement (30%) and paper/pulp production (60%), and for emerging
economies, it will be used in the building sector (10%). 80% of biogases are projected
to be used in fuel blending in industry and the remaining 20% is projected to be used
by the building and transport sectors. Liquid biofuels are projected to be directed to
the transport sector, particularly for the decarbonisation of road freight and aviation,
although there is uncertainty in the breakdown of the liquid biofuel end-users due to
the decarbonisation of the transport sector via electrification and hydrogen fuel
switching (IEA Bioenergy, 2022). There is though a common feature that bioenergy
(outside of carbon removal) is predominantly used in future for hard to electrify

36
applications – such as some transport and industrial processes (IEA, 2021c, IPCC,
2022b, IRENA, 2022e).

In the interim to 2030, all scenarios see a rapid growth for liquid biofuels and modern
solid biomass. The growth in liquid biofuels is in road transport while awaiting the
uptake of electric vehicles and end of life of petrol and diesel engines. The IRENA
1.5˚C scenario has a greater role for bioenergy in heating throughout the pathways
and very strong growth in liquid biofuel for transport to 2030, but as in the IEA NZE,
this growth slows as the decarbonisation of road transport moves away from liquid
fuels out to 2050 (IEA, 2021c, IRENA, 2022e). High demand for modern solid biomass
in the IRENA 1.5˚C scenarios corresponds to the greater role of bioenergy with
carbon capture and storage (BECCS) in keeping the scenario within a 1.5˚C
consistent global carbon budget when compared with other scenarios. This also
requires the co-development of CCS infrastructure to enable biomass use in this
way, and the co-location of bioenergy facilities with carbon storage or
transportation infrastructure – not an insignificant requirement. Depending on the
nation, BECCS projects are expected to be deployed in industrial clusters, often
formed around estuaries with strong access to shipping ports, providing the low-
carbon opportunity to source biomass both domestically and internationally (IPCC,
2021).

There is also expected to be increased competition for all categories of sustainable

biomass over the timeline to 2050, both from different users within the bioenergy
sector and with wider sectors. For example, biomass (sustainable sources of carbon)
is increasingly targeted by the chemical sector to produce low carbon bio-
chemicals, bio-plastics etc. There may be opportunities for optimising the utilisation
of available biomass through circular economy approaches and with development
of bioenergy with carbon capture and utilisation (BECCU) initiatives.

2.2.1 The bioenergy production gap

The 1.5˚C scenarios call for an annual increase in liquid biofuel supply of between 7%
and 18% across the pathways from 2020 to 2030, from ~4 EJ to between 8 EJ and 20
EJ per year primary energy. The IEA projected growth in production as potentially
only averaging 3% per annum between 2020 and 2025 (IEA, 2020), this however is
before impacts on transport demand in 2020 and 2021 due to the Covid-19
pandemic are factored in. As such even faster rates of production increase will be
needed to get back on track even for the IPCC Sustainable Development scenario
with relatively slow biofuel growth (7%/annum).

37
 25
Primary Energy for Liquid Biofuels (EJ)

20

15

10

0
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

IEA NZE IRENA 1.5 IPCC Ren IPCC SD IEA Projection

Figure 17: Implied liquid biofuel growth between 2020 and 2030 in the 1.5˚C Scenarios.
Projected 5 year outlook for production capacity from IEA (2020).

Growth in biofuels has been 5%/yr in the last decade (IEA, 2021b). Biofuels are
growing from a more established base than low-carbon hydrogen – accounting for
3% of transport fuel demand already (IEA, 2021b). In absolute terms, the gap
between current production and the scenarios to 2030 is not as great as with
hydrogen (see Figure 11). However, biofuel growth in the scenarios is largely
expected to be from second generation biofuels in the longer term, yet currently
only 7% of liquid biofuel production are second-generation. Second generation
biofuels have so far not been able to compete with first generation fuels at scale
due to higher costs (IRENA, 2019, IEA, 2021b). Closing the gap between biofuel and
biomass uptake in the 1.5˚C Scenarios and current production would require
additional government policies to grow/ produce / mobilise more feedstock supply
to balance future increases in demand.

Improving vehicle efficiency and impacts on travel demand such as the Covid-19
pandemic have the potential to slow demand for biofuels. However, increased
mandates and production policies appear popular in countries where first-
generation food crop based biofuels (such as palm oil in biodiesel and corn ethanol)
are dominant. This is because these countries have favourable geographic
conditions for large scale crop growth, and have the required agricultural systems in
place. This could however cause conflict related to food scarcity, as accelerated
growth of first generation biofuels would naturally decrease the available land for
food production. For example, the disruption to food production during the Russian
invasion of Ukraine in 2022 has reportedly led to proposed waivers for existing biofuel
blends and limiting the production of first-generation biofuels to ease food scarcity
concerns (McFarlane, 2022). Specific mandates and direct support for advanced
biofuels to replace cheaper first-generation fuels are lacking (IRENA, 2019). While

38
first-generation biofuels dominate, the risk of actual and perceived conflicts with
food production is likely to make accelerated growth unsustainable.

Bioenergy deployment faces similar challenges to hydrogen in terms of supply chain

interactions, as raw biomass producers are not confident that demand will be met
(particularly for energy crops and forestry) and land could have been better utilised
for other production. Although, the majority of challenges facing bioenergy
deployment are related to tensions between food and crop production, land-use
change and biodiversity. Greater coordination, communication and transparency
between sectors (agriculture, forestry and energy end-users) will be critical in
ensuring that bioenergy supply chains are sustainably sourced and that the supply
and demand between raw biomass-producing and bioenergy-consuming countries
are sustainably and cost-effectively matched. Governance around procurement
practices is a priority for bioenergy as bioenergy production interacts with
eliminating hunger, increasing access to clean water, protecting biodiversity and
economic development goals. Although there are both regulatory schemes (such
as the EU Renewable Energy Directive) and voluntary schemes (such as the
Roundtable on Sustainable Palm Oil (RSPO)), there is still no comprehensive
governance framework for the wider ‘bioeconomy’ (IEA Bioenergy, 2022, Rose,
2022), and this is potentially a barrier to a rapid scale-up (Welfle and Roder, 2022).

In concert these factor lead to uncertainty about the quantities of biomass available
to meet potential demand across all emerging sectors of demand. It is also unclear
to what extent competing demand for biomass products as substitutes in bio-
chemicals and bio-plastics will mean for availability in bioenergy applications.
Competing demands for biomass from industrial processes are not integrated into
future energy scenarios. The IRENA 1.5˚C scenario considers biomass as a feedstock
to industrial products but it is not clear on the proportions expected for this use or the
basis for these expectations. However although demand for non-energy bio-
products may triple to 16 Mt by 2030, this is from a low base of 5.5Mt (E4 Technology,
2021). The literature on projected bio-plastic and bio-chemical demand out to 2050
is not sufficient to quantify how it might affect overall assumed biomass resources in
energy scenarios. In the near term (to 2030), it is the capacity of biomass conversion
and processing infrastructure and of end-user demand drivers, not resource
availability, that are the limiting factors on bioenergy reaching the levels required in
the scenarios. There is potential for intra-competition for biomass resources from
liquid biofuel bioenergy projects and electricity BECCS projects. In some cases, such
as the UK, the available biomass may be directed for BECCS-power projects (to
meet carbon removal as well as energy needs) which may not leave enough
available biomass for liquid biofuel production for transport and aviation, although
currently the vast majority of BECCS projects (BECCS-Biofuels) in the US are
producing liquid biofuels, such as bioethanol, which are being directed towards
decarbonising road and shipping transportation (Consoli, 2019, Bello et al., 2020).
The aviation sector has identified second generation biofuels as a key component of
the sustainable aviation fuel agenda. Although still in an early stage, mandates for
biofuels in aviation fuel are emerging – for example in California.

39
2.3 Fossil Fuels in 1.5˚C Scenarios

The phase out of unabated fossil fuel is a major component of the 1.5˚C scenarios.
However international actors at the UNFCCC COP26 in Glasgow in 2021 only went as
far as a promised ‘phase down’ of coal rather than a phase out of oil, natural gas
and coal. Financial support from governments for fossil fuel production and
consumption is increasing (IEA, 2022g) despite climate pledges meaning that the
likely near term trend is to follow an emissions pathway to >3˚C rather than to limit to
1.5˚C.

Figure 18 highlights the potential gap between how current government policies
could affect coal use and the pathways required for a 1.5˚C global warming
outcome. For the 1.5˚C scenarios there is a sustained and rapid decrease in coal
demand between 2020 and 2030.

200
180
World Coal Demand (EJ)

160
140
120
100
80
60
40
20
0
2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2048 2050

IEA Net Zero IPCC - NDC Current Policy IPCC - Renewables

IPCC - Sus. Development IPCC Low Demand

Figure 18: Projected coal demand in scenario pathways.

The current trajectory of coal use may exceed even the scenario based on current
NDC pledges. Coal demand rebounded strongly from the Covid-19 economic
downturn and may slightly increase out to 2023, or at least remain flat (IEA, 2022a).
Disruption to world energy markets in 2022 due to the Russian invasion of Ukraine is
one reason for this, however coal demand was increasing in 2021 also, highlighting
that stronger policies and international cooperation is needed to close the gap on
required declining coal use.

The 1.5˚C scenarios and the IPCC NDC based scenario assume that oil demand at
least plateaus in the near term (to 2030), before declining steadily in the 1.5˚C
scenarios (Figure 19). Regional breakdowns in the scenario datasets indicate growth
in developing Asian economies partially or wholly offsetting declines in oil demand in
Europe and North America to 2030 before declining in all regions post – 2030.

40
 250

200
World Oil Demand (EJ)

150

100

50

0
2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2048 2050

IEA Net Zero IPCC - NDC Current Policy IPCC - Renewables

IPCC - Sus. Development IPCC Low Demand

Figure 19: Oil demand pathways in scenarios.

As with coal, oil demand is not on track to peak and reduce in the near term. Even
with a potential economic slowdown forecast for the 2022 to 2025 and higher prices,
oil demand is not expected to plateau or decline in the existing market and policy
context. Away from macroeconomic influences on oil demand (i.e. fuel price and
GDP) there are also indications that policies to reduce demand are lacking. In
Europe average CO2 emissions (consequently fuel consumption) from new cars
registered have been increasing again between 2016 and 2020, potentially due to
the prevalence of heavier sports utility vehicles (SUVs) (European Environment
Agency, 2022). Interim EU targets in 2024 for average new passenger vehicle fuel
consumption, where scenarios anticipate oil decline happening earliest, look likely
to be missed. Strong growth in the EV market and improvements to public and
active transport are be needed to adjust underlying structural demand for oil
aligned with 1.5˚C pathways.

Natural gas consumption is projected to have sustained growth through to 2050 in

the current NDC policy scenarios, indicating that in the absence of further climate
change policy it would increase to be a mainstay for global energy use (Figure 20).
In the 1.5˚C scenarios the decrease in natural gas use declines to varying degrees
between 2020 and 2030 before a more consistent rate of decline across all
scenarios.

41
 300

250
Natural Gas Demand (EJ)

200

150

100

50

0
2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040 2042 2044 2046 2048 2050

IEA Net Zero IPCC - NDC Current Policy IPCC - Renewables

IPCC - Sus. Development IPCC Low Demand

Figure 20: Natural gas demand pathways in scenarios

Higher gas prices and other impacts due to the Russian invasion of Ukraine suggest
no or low growth in natural gas demand in the 2022 to 2025 period (IEA, 2022b). This
effect is larger than any climate policy driven impact – prior to the Russian invasion,
natural gas demand was expected to have robust growth (McKinsey, 2021). A return
to growing unabated natural gas use is likely unless the response to supply disruption
considers climate change co-benefits. However, sustained high prices could drive
accelerated investments in supply alternatives and energy efficiency measures that
could embed the longer-term transitional changes in energy systems required in
1.5˚C scenarios.

Comparing the required energy system changes to achieve the 1.5˚C scenario
pathways highlights the need for a rapid phase out of coal and the peaking and
phase down of oil and natural gas over the coming decades. The rates at which
electrification, hydrogen and biomass fuels replace conventional fuels and energy
demand reduces varies across the pathways. Current trends however point to a
growing gap between the energy pathways for 1.5˚C and actual energy system
characteristics. Energy demand globally increased in 2021 to higher than pre-Covid
levels, fossil fuel use has not stopped growing and production of low-carbon fuels is
nowhere near the pace required for the scenarios. Assertive government action is
needed to drive investment and preference for low-carbon fuels and change the
current direction of travel in order to limit global temperature rise to 1.5˚C. The next
section of the report considers what the changes in the energy system if this were
achieved could mean for the shipping industry.

42
3. Implications for Shipping
Across all of the 1.5˚C scenarios there is a rapid transition from fossil fuels to low-
carbon fuels and renewable electricity. This reconfiguration of the energy system will
have important implications for the global fuel trade as soon as 2030 if these low
emissions pathways are achieved. Shipping is an important component of the
global fuel trade, with these changes affecting not only the quantity and type of
fuels shipped, but potentially the fuel use of ships themselves. This section considers
the implications of the 1.5˚C scenarios for the seaborne fuel trade. Changes in
global fuel demand implied by the scenarios are presented, key factors in
determining to what extent low-carbon fuels are traded are discussed, before the
potential implications for seaborne energy products trade are quantified.

In 2021 energy products accounted for ~36% of global seaborne trade by tonnage
(Clarksons, 2022a). The relative significance of energy products to shipping has
decreased overtime – from ~45% of seaborne trade in 2000 – while the shipping
industry has grown (Clarksons, 2022a). Crude oil and oil products is the majority
(~66%) of seaborne energy transported. At present, ~64% of oil, and ~15% of both
natural gas and coal is transported by sea (see Figure 21).

7000

6000
Energy Products (Mt)

5000

4000

3000

2000

1000

0
Coal Oil Gas

Seaborne Other

Figure 21: Fossil Fuel Energy Products - Total production in 2021 and the proportion transported by ship (seaborne) and
either pipeline, road or rail freight (Other). Source (Clarksons, 2022a)

The implications for the shipping sector of changes in the global fuel mix depend on
a range of factors. Features of a fuel and its production and consumption determine
how it is transported. This includes the spatial relationship between where it is
produced and consumed and the relative cost effectiveness and technical
feasibility of alternative transport: by pipeline, road and rail (Figure 22). As fossil fuel
use declines, the extent to which reduced capacity is replaced by low-carbon fuels
depends largely on the features of low-carbon fuels in the same regard. The factors
influencing the extent to which fuels might be transported by ship in the 1.5˚C

43
scenarios is discussed in turn and the potential outcomes for quantities of seaborne
energy products traded is considered across a range of possible outcomes.

Figure 22: Flow chart of proportion of low-carbon fuels potentially transported by ship.

3.1 Seaborne Hydrogen Trade

The increase in hydrogen consumption for energy across the scenarios may be
expected to lead to more hydrogen being traded between nations, but this will
depend on how the global hydrogen economy develops. The type of hydrogen
production (whether green or blue) and relative costs of production, transport and
conversion to liquid hydrogen or ammonia all determine the extent to which
hydrogen for energy use becomes a globally traded commodity.

Current grey hydrogen production is frequently co-located near to demand centres

and methane supplies (in part due its use in oil refining processes). Although green
hydrogen could be produced in a wider variety of locations and co-located with
demand, differences in production costs, existing infrastructure and government
policy means some trade between nations is likely. While there are plans for blue
and green hydrogen production in consumer regions such as the EU and China, the
lowest cost green and blue hydrogen may be produced in countries and regions
such as Australia, the Middle East, Africa (e.g. Morocco and Namibia) and South
America (Chile) (IRENA, 2022b). Countries with strategies to increase hydrogen
demand in the near term – Japan, South Korea, Singapore and Germany – have
bilateral trade agreements with these producer countries (Figure 6).

These exports would either be by pipeline or by ship. IRENA estimate that due to
relative costs, pipelines are more likely for transmission distances up to 5,000km
before shipping becomes more cost effective (IRENA, 2022b). Cost is not however
the only issue: for mid-ranges the greater flexibility of ships over pipelines make
shipping a potentially more attractive option to take advantage of changing prices
for hydrogen, natural gas prices and power generation in different countries (ICS,
2022).

Hydrogen has a low volumetric density, and consequently to reduce the space
required for its transport would require it to be liquefied or converted into ammonia.
Trials of liquid hydrogen tanker ships are underway (Sonali P, 2022) however
ammonia is already routinely shipped and there is currently an expectation that
hydrogen will be predominantly shipped as ammonia in the future (IRENA, 2022b).

44
Transporting hydrogen as ammonia by ship may follow a supply chain as set out in
the example in Figure 23 showing potential interactions between export and import
countries and ammonia and hydrogen in the non-energy sector as well as for
energy services.

Figure 23: Stages in green ammonia production, transport and use

From an assessment of existing planned hydrogen projects, Australia, Mauritania,

Oman, Chile, Saudi Arabia, Brazil, Morocco, Democratic Republic of Congo and
Egypt are example potential exporters of hydrogen energy products. A number of
issues affect the extent to which hydrogen in these countries might be exported by
ship:

 Competing demand for hydrogen/ammonia within the producer country

(points 10&11 in Fig. 23)
 The feasibility of a pipeline connection to a consumer country
 The relative cost of transport by ship versus pipeline
 The relative cost of imported green hydrogen/ammonia (points 1-3) versus
grey/green/blue hydrogen/ammonia produced in the potentially importing
country (points 12-16, Fig. 23)

The cost of transporting hydrogen by ship is cited as an issue (IRENA, 2022b),

particularly when comparing hydrogen produced domestically with imports. This is
because although it is most efficient to ship hydrogen as ammonia, because of
hydrogen’s low density, doing so incurs an energy and cost penalty, both in
converting hydrogen to ammonia in the producing country, and then cracking this
ammonia back to hydrogen in the consuming country.

This issue does not necessarily apply if the imported ammonia is used directly as
ammonia in the consuming country, for example to use for power generation. In this
case, cracking is not required. Overall, the actual transport cost of importing
ammonia is low, adding around $100/t NH3 (IRENA, 2022a) and consequently
imported green ammonia is already potentially competitive with green ammonia

45
produced in the EU (ICS, 2022), given the cheaper costs of renewable electricity in
exporting countries (points 6&7 in Figure 23).

In addition, the case for green ammonia imports in 2022 compared with using
blue/grey ammonia is better than previously assumed due to increased natural gas
prices. For example, one comparison of green vs grey/blue ammonia costs
estimated green ammonia production costs of $1,055/t NH3, compared with $375-
475 for grey/blue (Yara, 2022b). This however assumes a gas price of $4.5/MMBtu
from 2022 to 2050. Gas prices constitute around one third (Yara, 2022b) of grey/blue
NH3 production costs and have been over $10/MMBtu in Europe and Asia since May
2021, and have averaged over $30/MMBtu between October 2021 and June 2022 in
Europe(YCharts, 2022, IEA, 2022f). While there is great uncertainty about future gas
prices, and prices in 2021/22 have been impacted by the Covid-19 pandemic and
the Russian invasion of Ukraine, gas future prices to 2025 are $24/MMBtu as of Sept
2022 (CME Group, 2022) . More recent reports (Janzow, 2022, Green Hydrogen Task
Force, 2022, ICS, 2022), have brought forward the point at which green
hydrogen/ammonia can be cheaper than grey/blue hydrogen/ammonia far faster
than previous analyses have anticipated. This point does not apply everywhere
however – although natural gas prices in the USA are higher in 2022 than in 2020,
they are still very low (~$8/MMBtu) compared with 2021/22 prices in Europe and
Asia.

Shipping green ammonia from countries such as Australia/Chile to Japan/Europe

also has to compete with this ammonia (or hydrogen) being used domestically.
Australia in particular has large industries and other sectors capable of soaking up a
lot of hydrogen demand. However, the sheer scale of hydrogen resource potential
in these countries is such that most analyses believe that many countries, including
Australia, would be major net exporters of hydrogen (IRENA, 2022b, Janzow, 2022).
The potential to diversify trading partners and the lower operating costs relative to
capital costs for green hydrogen and ammonia could make this technology
pathway appealing on energy security grounds as well (Janzow, 2022).

Overall, the possibility space for a global hydrogen trade remains broad. It is
uncertain which countries will see the greatest growth in production of and demand
for low carbon hydrogen. These dynamics will determine future trade patterns.
IRENA estimates that potentially a quarter of hydrogen produced for energy will be
traded internationally, of which 45% would be by ship. In other words, 11% of
hydrogen produced for energy use could be transported by ship (IRENA, 2022b)
representing a practical indication of how the hydrogen trade might develop if
proposed projects and bilateral agreements are realised.

3.2 Seaborne Bioenergy Trade

There is high certainty that demand for biomass and biofuels from the international
trade markets will continue to grow (Welfle, 2017). The uncertainties lie around how
future bioenergy supplies will develop globally, as well as the regional distribution of
production and demand.

46
Global bioenergy trade activity will vary by type. Europe has been the leading
market for solid modern biomass products (Commission and Joint Research Centre,
2019). A large intra-European trade, as well as the development of trans-national
biomass supply chains from North America to Europe, characterises most of modern
solid biomass trade at present (5.8 Mt of wood pellets from North America to Europe,
6.7 Mt transported within Europe) (Junginger, 2019). This is because until recently,
countries with growing demand and policy incentives for biomass have had
relatively low biomass availability (Welfle and Slade, 2018). The UK and Italy for
example import 95% and 81% of their wood pellet fuel respectively from other
countries (Commission and Joint Research Centre, 2019). In the case of the UK, 7.8
Mt of wood pellets were imported, predominantly (82%) from North America. A
significant proportion of global solid biomass trade is by ship – however most biomass
is used domestically or regionally (IEA Bioenergy, 2018, Junginger, 2019).

There is debate about whether decentralised biomass production, using local

resources to mitigate concerns about GHG emissions, biodiversity and food
production impacts (Welfle and Slade, 2018, Forster et al., 2020), is more optimal
than more centralised facilities that maximise economies of scale (Sanchez and
Callaway, 2016). Port to port transport of biomass is not significant in determining the
overall sustainability of a biomass product, however emissions can be reduced by
minimising distances bulk biomass products are transported by road if shifted onto
low-carbon transportation methods like shipping and rail (Sanchez and Callaway,
2016). The travel distance by road of solid biomass would therefore be a key
consideration on its suitability for export if regulations were in place to minimise
supply chain emissions of biomass resources. This is before interactions between
biomass and carbon capture and storage infrastructure for carbon removals is
considered. To what extent bulk biomass will be shipped to locations for carbon
capture and storage is unclear given the slow development of carbon capture –
however notably CO2 is starting to be shipped from emissions sources to integrate
into carbon storage infrastructure, as in the case of the Norwegian Northern Lights
project and carbon capture projects in South Wales, London and Southampton in
the UK (Yara, 2022a).

The trade in bioethanol has historically been predominantly regional within North
America and Europe (0.1 Mt of bioethanol), with global trade mostly from Brazil to
North America (0.5 Mt of bioethanol) and Japan (0.4 Mt of bioethanol) (Junginger,
2019). For biodiesel the significant flows are from Argentina (0.6Mt of biodiesel),
Indonesia and Malaysia (0.2Mt of biodiesel) to North America, but leading biodiesel
markets in Europe like Germany are currently self-sufficient. Demand is driven by
mandates on the content of biofuels in transport fuels. In the near term, the largest
growth in production capacity is in large bioethanol and biodiesel producer
countries that are also increasing their fuel blend mandates – Indonesia, Brazil, USA
and Malaysia (IEA, 2022c). Near term growth through expanded global trade in
biofuels in not therefore expected. In the IEA NZE and IRENA 1.5˚C scenarios, biofuel
demand growth slows after 2030 as liquid fuel use for transport declines from 2030
onwards. This is due to the electrification of surface transport while biofuels become
more applicable to aviation, shipping and road haulage. Liquid fuels have a greater
role in road transport in the IPCC Renewables and Sustainable Development

47
scenarios and biofuel demand is greater suggesting fuel blend mandates increase
and the move to electric vehicles is assumed to be slower. In recent years, major car
markets across Europe, Japan, North America and China have stated that there will
be prohibitions on new petrol and diesel cars in the 2030s. If implemented, there
would be significant decline in the fuel systems that use biofuels for passenger
vehicles by 2050 as indicated in the IEA and IRENA scenarios.

In 2019 it was estimated that ~2% of global bioenergy production was sourced from
biomass feedstock that was transported via ship (Junginger, 2019). However there
remains a diversity of views on what biomass resources will be dominant and where
they will be produced (Rose, 2022). The costs of resources, carbon pricing and
environmental and social constraints used in models lead to varying results (Rose,
2022). The key implication is that the type of biomass used – e.g. residues, energy
crops and forestry – and whether countries self-consume, export or import, depends
on how these features of the bioenergy sector develop. There is some evidence to
suggest that bioenergy products could be largely consumed domestically or
regionally where producer countries have policies to drive consumption (Welfle and
Slade, 2018, Junginger, 2019, Welfle, 2017). However, this does not rule out the
potential for a global biomass trade. The development of the bioenergy sector
shows that regions with advanced incentives for bioenergy consumption can end
up needing to import from countries with high resource and low utilisation (such as
UK imports of biomass form North America). In the end, the extent to which biomass
and biofuels will be shipped will significantly depend on the shift away from utilisation
for road transportation and what feed-stocks come to dominate supply – which also
hinges on the extent to which legislation, regulations and other protections focussed
on biomass sustainability are put in place.

Changes in Fossil Fuel Seaborne Trade

Phasing out fossil fuel use globally will reduce traded volumes of energy products by
ship. Although the relative share of energy products as a proportion of tonnage has
been declining (Clarksons, 2022a), energy is an important part of shipping trade.
Changes in oil and coal demand would be expected to translate into significantly
reduced quantities of energy products shipped in the next decade. However, the
outlook for natural gas shipments is distinct in that within the 1.5˚C scenarios,
although overall demand reduces, it is projected to increase in developing countries
(see Figure 24).

48
Figure 24: Regional distribution of natural gas demand in IPCC Renewables and Sustainable Development scenarios

In these IPCC scenarios, natural gas demand is between 452 Mt and 780 Mt greater
in non-OECD Asian countries in 2040 compared to the 2020 baseline. In keeping with
the common but differentiated responsibility and respective capabilities framing of
much of the international climate change discourse, natural gas and oil use reduces
at a much faster rate in developed OECD (Annex-I) countries while there is still
growth in developing economies. This might be predominantly expected to be
transported by ship, given current supply and the distances between key producers
and consumers.

The IMO’s assessment of future traded fuels in IPCC emissions pathways shows a
similar expected outcome. Tonne mileages for coal and oil fall steeply, whereas gas
tonne mileages rise (Table 6) – this is because although gas demand falls, the
distance each unit gas is shipped almost doubles (IMO, 2020).

Table 6: Projected Transport Work (billion tonne miles) in IPCC 1.5C emissions pathways - SSP1_RCP1.9 and SSP2+RCP1.9,
table 19, p372 in (IMO, 2020).

Billion tonne 2020 2050 % change

miles/yr
Coal 5,563 1,089-1,553 -72 to -80
Oil 13,561 2,256-2,989 -78 to -83
Gas 1,781 2,075-2,245 +16 to +26

Therefore while coal and oil trade by ship is expected to reduce in line with declining
global demand, natural gas shipments can be expected to at least remain at
current levels and potentially increase to 2040 before reducing in 1.5˚C scenarios. A
strong caveat to this assumption is that the full lifecycle GHG emissions of LNG
shipments must be accounted for in any assessment of the relative merits of pipeline
versus shipment of gas products, as overall gas use declines.

49
Projections of future seaborne transport of fuels

Based on the assessment above, two ‘what-if’ extrapolations for seaborne fuel
trades in the 1.5˚C scenarios are shown in Figures 25 and 26. Traded volumes of coal
and oil by are assumed to decrease proportionally with overall global demand
changes in the scenarios. Natural gas transported by ship is assumed to stay
constant in absolute terms out to 20507, though the proportional share of produced
natural gas that is shipped increases from 15% (2020) to between 38% and 80%
depending on the scenario by 2050.

High export and low export variations of low-carbon fuel seaborne trade are
assumed. It is assumed that hydrogen is shipped as ammonia, and that the
proportion shipped ranges from 7-15% in 2050, with a mid-value of 11% (IRENA,
2022b). For bioenergy, in the high export version it is assumed that the percentage of
bioenergy shipped increases from 2% now to 15% by 2050, in line with the
percentage of coal shipped. A low export version assumes an increase to half that
amount (7.5%) by 2050. This variation highlights the potential for significant domestic
and intra-regional utilisation of these fuels. This is still a considerable increase from the
current 2% of biomass supply that is shipped. This increase would require policy to
discourage the use of short-distance carbon-intensive HGV biomass transportation
and encourage the recalibration of biomass supply chains to use low-carbon
transportation alternatives such as shipping and rail.

7
As a sensitivity, different assumptions of 40-60% of gas transported by ship in 2050 would give a range of
248-775 Mt, instead of the 492 Mt value in Table 7.

50
 5000
2020
4500
2030
4000

3500
Energy Products (Mt)

2050 Ammonia
3000
Biofuels
2500
Biomass
2000
Coal
1500
Gas
1000 Oil

500

0
IPCC - Ren

IPCC - SP

IPCC - Ren

IPCC - SP
Baseline

IRENA 1.5

IRENA 1.5
IEA NZE

IEA NZE
Figure 25: Potential seaborne trade outcomes for the 1.5˚C scenarios, assuming higher levels of trade of emergent low-
carbon fuels and deployment at scale of carbon capture and storage technologies.

5000

4500
2030
4000

3500
Energy Products (Mt)

2050 Ammonia
3000
Biofuels
2500
Biomass
2000
Coal
1500
Gas
1000 Oil
500

0
IPCC - Ren

IPCC - Ren
IPCC - SP

IPCC - SP
IRENA 1.5

IRENA 1.5
Baseline

IEA NZE
IEA NZE

Figure 26: Potential seaborne trade outcomes for the 1.5˚C scenarios, assuming lower levels of trade of emergent low-
carbon fuels and deployment at scale of carbon capture and storage technologies.

51
Table 7: Seaborne trade of fuels under high and low-carbon fuel trade assumptions across the 1.5˚C scenarios.

Mt/Year 2020 2030 2050

Oil 2834 1,801-2,879 272-1,363
Gas 492 492 492
Coal 963 108 - 426 4 -102
Biomass (High Export) 71 216-252 294 - 911
Biofuels (High Export) 3 18-47 81 - 322
Ammonia (High Export) 20 39 - 135 171 - 527
Biomass (Low Export) 71 130-153 147-156
Biofuels (Low Export) 3 11-28 41-161
Ammonia (Low Export) 20 19 - 68 86 - 264

Figures 25 & 26 and Table 7 show how overall tonnage of shipped energy products
may evolve in the 1.5˚C scenarios. Even with the higher seaborne trade assumption
for low-carbon fuels, natural gas shipments remaining constant and lower density
ammonia assumed for hydrogen shipments, overall tonnage of energy products
reduces by 41% to 52% across the scenarios. This is primarily because low-carbon
fuels are not expected to fill the role that oil has today – an energy product traded
predominantly by ship. It also highlights the implications in the scenarios of reduced
energy demand and greater electrification of both surface transport and building
energy use provided not by fossil fuels, but by renewables. Nonetheless, despite
these overall falls, the shipping sector could be expected to become a major
transporter of bioenergy products and ammonia, with overall tonnage of shipments
for each comparable with current global shipments of coal and gas.

4. Shipping Enabling the 1.5˚C Scenarios

For low-carbon fuel shipments to be ready to support the deployment rates assumed
in the 1.5˚C scenarios, global shipped trade of low-carbon fuels requires much more
than production facilities and willing consumers. Infrastructure investments will be
needed to get products to exporting ports, for storage, loading into appropriate
vessels, for transport to market and then for unloading, storage and distribution at
importing ports. This section of the report considers the preparedness of the shipping
industry to support the transport of low-carbon fuels. Hydrogen and hydrogen-
derived fuels are used as an example.

Countries and regions expecting to import hydrogen are already well equipped to
deal with ammonia imports. 10% of global ammonia production (17 Mt/yr) is already
traded (IRENA, 2022d), and there is a large global ammonia infrastructure in place.
Furthermore, there is ammonia bunkering infrastructure at over 150 ports (DNV,
2022), with a total capacity of 5Mt (Table 8).

52
Table 8: Ammonia terminal capacity (source: analysis of AFI.dnvgl.com data)

Number Total
Ammonia tonnage
Region terminals
Europe & Russia 49 1,075,029
Asia 51 1,025,376
South & Central
America 23 865,200
USA 19 715,200
Middle East 11 623,000
Africa 12 555,000
Australia 5 173,000
Total 170 5,031,805

Some ports are also actively planning additional ammonia infrastructure, for
example Rotterdam. Other ports that do not have ammonia infrastructure (such as
Singapore) are actively planning how to enable ammonia bunkering, for use by
international shipping.

 Singapore
o Consortium feasibility study on green ammonia supply chain and
bunkering, March 2021 (Maersk, 2021), phase 1 report in April 2022
(SABRE, 2022, Stott, 2022b);
o Sumitomo Corp and Keppel sign m.o.u for Singapore ammonia
bunkering, Dec 2021(Pekic, 2021)
o Ammonia bunker vessel gets Approval-in-Principle backing from
classification society ABS (Ship Technology, 2022), June 2022
o Sembcorp, Chiyoda and Mitsubishi sign green hydrogen into Singapore
supply chain m.o.u (Sembcorp, 2022).

 Rotterdam
o June 2022, final investment decision for OCI to triple ammonia
capacity at Rotterdam to 1.2 Mt/y (OCI, 2022);
o May 2022, 69 player consortium announces plans of import of 4Mt
green H2/yr into Rotterdam (Port of Rotterdam, 2022);
o May 2022 Rotterdam signs hydrogen supply chain memorandum of
understanding with Queensland, Australia (PACE, 2022)
o June 2022, Air Products and Gunvor sign joint development agreement
for green hydrogen import terminal (Air Products, 2022);
o April 2022, Gasunie, HES international and Vopak announce plans for
new ammonia import terminal (Vopak, 2022);

 2021 Safety study for bunkering at Amsterdam (DNV, 2021b);

 2021 Risk assessment for bunkering at Oslo (DNV, 2021a);

53
  Mitsubishi and Mitsui complete ammonia bunkering study, Feb 2022
(Mitsubishi, 2021);

 Yokohama, Japan, April 2022 alliance agreement signed on ammonia

receiving terminals (JGC, 2022);

 Brunsbüttel, Germany, March 2022. 300kt ammonia import terminal

announced (RWE, 2022).

While for importing ports, ammonia infrastructure is well developed, the outlook for
new potential exporting ports is less so. For exporting ports, it is possible that new
ammonia infrastructure will be required, as new production facilities are not
guaranteed to be near ports that already have ammonia infrastructure. This is not a
uniform picture – for example the planned Australian Renewable Energy Hub in
Western Australia is close to the Pilbara ports, with 80,000 tonnes of ammonia
storage, and Saudi Arabia has major plans for green hydrogen and ammonia
production, and is already the world’s largest grey ammonia exporter (4Mt/yr) with
major ammonia infrastructure at multiple ports. Abu Dhabi has also announced a
new planned ammonia export terminal (TAQA, 2021).

The outlook for vessels to support traded hydrogen and derived fuels also appears
well positioned to support product flows as they develop. Currently there are 1,545
LPG vessels globally, 443 of these are classed by Clarksons as ammonia carriers.
Other estimates are that only 40-170 or so vessels are responsible for the majority of
global ammonia shipments (17 Mt/year)(IRENA, 2022d, IRENA, 2022c, Topsoe et al,
2020)8. LPG carriers can be adapted to carry ammonia, and there appears to be
capacity in the current ammonia carrier fleet to absorb short-term increases in
ammonia transport. However, over time additional ammonia carriers will be needed.
Table 9 sets out some potential green ammonia demand figures for different sectors.
Table 9: Potential Green Ammonia Demands

Demand type Ammonia Assumptions

requirement/yr
Japan co-firing in power 0.5 Mt Tender issued by power utility JERA
stations (Atchison, 2022c)
Australia-Japan iron ore 1 Mt All the current iron ore trade on the
route is replaced by 41 dedicated
zero-emission vessels(Getting to
Zero Coalition, 2021)
Asia-Europe shipping 3.5 Mt 17% of ships are zero emission by
containers 2030 (Getting to Zero Coalition,
2021)
All Germany/ UK/ France/ 9Mt Assumes all replaced with imports9
Netherlands ammonia
consumption

8 With IRENA 2022d saying there are 170 vessels which can transport ammonia, and 40 doing so continually,
and IRENA 2022c saying this trade is by 70 LPG tankers, citing Topsoe et al, 2020.
9
Sources: Wits.worldbank.org for import/export data; production data from
https://www.nationmaster.com/nmx/ranking/ammonia-production

54
The number of ships required to transport ammonia depends on:

 Ship size
 Ship speed
 Distance travelled
 Time between trips

Ammonia carriers vary greatly in size, from under 5000 Gt to over 50,000 Gt. The
average size is 17,000 Gt. It could be expected that carriers supplying new ammonia
transport from, say, Australia to Asia would be larger carriers. Carrying capacities for
different vessel sizes are set out in Table 10.
Table 10: Ammonia carrier sizes and capacity

Example Vessel Vessel Vessel

vessel name size ammonia ammonia
(gross capacity capacity10
tonnage) (m3) (tonnes)
Trammo Paris 17,242 23,237 15,848

Yara Aesa 25,118 38,000 25,916

Clipper Orion 36,459 60,000 40,920

JS Ineos 59,299 81,898 55,854

Dolphin

Distances vary greatly. The average distance for an ammonia cargo in 2020 was
2,700 miles, which would be a round trip of 5,400 nautical miles. Assuming a speed of
11 knots, this is 21 days, a maximum of 17 round trips per vessel per year. A round-trip
from Oman to South Korea would be 13,500 nautical miles, 51 days, with a maximum
of only 7 round-trips a year possible. Australia to Singapore would be 4,400-8,300
nautical miles, depending on which Australian port was used.

Table 11 sets out the number of ammonia ships needed, depending on vessel size
and route. This assumes an average speed of 11 knots, and 5 days between trips.
Table 11: ship requirements versus routes and size

Number of ships needed to transport 1 million tonnes NH3 per

year
Vessel size (gross Current average Port Hedland, Duqm, Oman to
tonnage) route Australia to Ulsan, South Korea
Fukuyama, Japan
17,242 4.4 5.9 9.7
25,118 2.7 3.6 5.9
36,459 1.7 2.3 3.8
59,299 1.2 1.7 2.8

10
Calculated assuming ammonia has a volumetric energy density of 0.682t/m 3, reference Seo and Han, 2021.

55
As an example, assuming from Table 7 a mid-range value of an additional 60Mt of
ammonia sea-trade in 2030 for a 1.5oC compatible pathway, this would be the
equivalent of 101 large vessels on Australia-Japan length routes.

The historic build rate for ammonia carriers is set out in Figure 27. There are a further
16 on order books for delivery over the next three years – well below the historical
build rate. If 101 vessels are needed by 2030, this would then require a further 85
vessels from 2026-2030, 21 a year, a rate that has been attained in six years in the last
20.

35

30

25
Total=443 vessels
A further 16 on orderbooks
20

15

10

0
1961 1972 1977 1979 1982 1986 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022

Figure 27: Ammonia carriers by year built. Source; Clarksons

Shipping as an Adopter of Low-carbon Fuels

The shipping industry itself can be an important market for emerging low-carbon
fuels. In the IEA NZE 1.5˚C scenario for example, hydrogen based fuels account for
45% of shipping fuel in 2050(IEA, 2021c). Biofuels could also be an important drop-in
and full fuel substitute for marine diesel in the nearer-term future. Due to wider
sustainability concerns and engine compatibility, second generation biodiesels are
the most likely drop-in fuel candidate. However, second generation feed-stocks for
biodiesel (e.g. waste cooking oils) are relatively limited (compared to bioethanol)
which may lead to competition with the aviation sector (IEA Bioenergy, 2017).

It is imperative that the 2020s sees scaling of the adoption of low carbon fuels to
reach 5% of the international shipping fuel mix by 2030, to enable more rapid
deployment through the 2030s and 2040s (Osterkamp, 2021). This 2020s focus on fuels
would need to be complemented with a package of other measures, on energy
efficiency, wind-assist technologies, shore power and other options, to deliver a

56
Paris-compatible trajectory for the international shipping sector of 34% cuts in
carbon dioxide emissions on 2008 levels by 2030 (Bullock et al., 2022).

In terms of low-carbon vessels available in the near-term, there is growth in some

segments (methanol, hydrogen) but this is from a very low base. Although many trials
are underway, ammonia powered vessels are not expected in service until 2024. The
status of alternative fuel vessels is set out in Figure 28. Although sea transport of
ammonia is a well-established practice with strong safety protocols, it will be
imperative that safety concerns are fully addressed, both for the expansion of port-
side ammonia bunkering infrastructure, and the new safety requirements on vessels
for the use of ammonia in engines (rather than solely their storage).

120

100

80
Number of Vessels

60

40

20

0
In Service On Order In Service On Order In Service On Order In Service On Order In Service On Order
Biofuel Hydrogen Methanol Ammonia Ammonia + Methanol
Fuel type and current status

Alternative fuel using - single fuel Alternative fuel using - dual fuel with fossil fuel Alternative fuel ready

Figure 28: Numbers of vessels using different fuels, and ready to use different fuels, either already in service or on order
(Clarksons, 2022b)

57
5. Conclusions
The climate and energy challenge

Unprecedented levels of greenhouse gas emissions reductions are needed this

decade, on a pathway to zero emissions around 2050. The timescales are extremely
urgent. Further delay is not an option. Meeting this challenge has profound
implications for the global use of energy, and the systems that provide that energy.

Five changes to the energy system by 2050 are consistent across the 1.5˚C scenarios
reviewed:

 Reductions in overall global energy consumption, mainly due to greater

energy efficiency;
 Rapid electrification of many sectors of the global economy;
 Rapid decarbonisation of the electricity sector, with large increases in wind
and solar replacing coal and gas;
 Rapid reductions in coal, oil and gas use;
 Growth in the use of lower-carbon fuels such as hydrogen and bioenergy.

These changes will have profound implications for shipping. In future, shipping will
transport different fuels, in different quantities, between different countries, and if
1.5˚C of warming is to be avoided, this transition will start in earnest in a timeframe as
short as months and years.

Implications for shipping

The shipping sector needs to prepare for a rapid transition away from coal and oil.
Reductions start this decade. By 2050 coal shipments fall 90-100%, oil 50-90%.
Although natural gas demand also decreases significantly, a greater proportion of
gas is traded by ship, so the shipping sector can expect a continuing role for
shipping natural gas products in the medium-term.

Bioenergy use grows in 1.5˚C scenarios, subject to strict requirements on sustainability

impacts. It is likely there will be growth in shipments of both biomass and biofuels,
although there is great uncertainty about sustainable levels of bioenergy
production, and the countries that would see greatest growth.

Hydrogen presents a major opportunity fuel for the shipping sector. Replacing the
highly carbon-intensive current method of “grey” hydrogen production which is
produced close to where it is used currently, with green / blue hydrogen is an
opportunity for more hydrogen trade.

Hydrogen is also expected to have new uses – for example in industry, shipping,
aviation and power generation and the transport of green hydrogen will be
necessary, either by pipeline or ship. As distances increase, shipping will be
preferable, but it is economically more efficient to ship hydrogen as ammonia. There

58
is also a cost penalty at the destination in converting ammonia back to hydrogen,
so the best export markets for green hydrogen producers are likely to be those with
direct uses of ammonia, such as in fertiliser manufacture.

In short, existing uses of hydrogen (fertiliser manufacture) are the largest potential
market for low-carbon hydrogen to 2030. Moreover, imported green ammonia can
reduce reliance on natural gas, increasingly important for many countries’ strategic
goals around energy security and despite its more energy intensive production
needs, green ammonia is becoming economically viable.

Bioenergy and ammonia shipments have the potential to be as high as coal and
gas shipments today, and these increased shipments will not be technically difficult
for the sector to deliver, given existing infrastructure and familiarity with cargoes.
However, overall the shipping of energy products will fall, as the growth of transport
of new fuels is outweighed by greater falls in shipments of oil and coal.

Closing the gap between plans and hopes of delivering 1.5˚C

scenarios

There is a major gap between the planned production of low-carbon hydrogen,

and what is required to deliver the 1.5˚C scenarios.

Government policies that can bridge supply and demand – providing investors on
both sides with greater confidence in the transition to low carbon hydrogen – will be
an important factor in whether the gap between low-carbon hydrogen use in 1.5˚C
scenarios and the current situation can be closed.

It is unlikely that the shipping sector provides the much needed demand-side
impetus for green hydrogen projects but there will be a major role for the shipping
sector in connecting hydrogen producers and consumers.

For bioenergy too there is a gap between planned projects and required ambition.
The growth rate in sustainable biofuels needs to between 7% and 18% per year to
deliver the 1.5˚C scenarios. Action from governments and investors is needed
urgently if these fuels are to reach the levels required in time.

The role for the shipping sector

There is extensive infrastructure already in place globally for ammonia shipments,
and experience in using it. Annual build rates for new ammonia carriers to meet a
rising demand for ammonia in 1.5˚C scenarios are high, but within the range of what
has been achieved in recent decades.

Because the sector has a slow turn-over of assets, it will be post 2030 before the
sector uses hydrogen for more than 5% of its fuel, but in the 2030s and 2040s, the
shipping sector is likely to become a major user of hydrogen products, including
ammonia, to decarbonise its own operations.

59
In addition to measures focused on cutting the sector’s CO2 emissions during this
decade (Bullock et al., 2020), steps need to be taken now to ensure infrastructures
for new fuels are developed in time. There are two clear priorities. First, ensuring new
ammonia carriers are designed to run on ammonia, to gain synergies in
development and deployment of bunkering infrastructure. Second, the scaling up
in deployment of green hydrogen hubs and corridor initiatives, and other measures
to connect producers and consumers, such as in the work of the ICS’ Clean Energy
Marine Hubs, the Getting to Zero Coalition’s green corridors work, and bunkering
initiatives in Singapore and Rotterdam, among others.

Crucially, the success of low-carbon hydrogen and sustainable biofuels is critically

dependent upon robust and enforced mechanisms to ensure full-lifecycle emissions
and other sustainability impacts are fully accounted for, and that genuine
sustainability and greenhouse gas (GHG) benefits are realised. This means ensuring
bioenergy production does not cause deforestation or conflict with essential uses of
land for food, and that for both bioenergy and hydrogen that upstream as well as
downstream GHG emissions are measured.

The shipping sector will be pivotal in facilitating the global energy transition needed
to protect humanity and nature from the worsening impacts of climate change.
Although it can expect to transport far lower quantities of energy products in a 1.5˚C
future, the sector has a crucial role in enabling trade in new low-carbon energy
products. Now is a critical time for the sector to get on the front foot as a potential
catalyst for change – but it will require many more hands on deck. It must build on its
unique global reach to prioritise developing the networks and infrastructure to
connect new fuel producers with the emerging consumers. If the shipping sector
can energise faster growth in sustainable fuels, it will be playing a pioneering role in
closing the gap between grand theoretical plans and a real world fit for future
generations.

60
References
ADAMS, K. M., BENZIE, M., CROFT, S. AND SADOWSKI, S, 2021. Climate change, trade,
and global food security: A global assessment of transboundary climate risks
in agricultural commodity flows. Stockholm Environment Institute.
AIR PRODUCTS 2022. Air Products and Gunvor to Cooperate on Green Hydrogen
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