IEEJ：October 2021 © IEEJ2021

FINAL REPORTSTUDY ONTHE ECONOMICS OF
THE GREEN HYDROGEN
INTERNATIONAL
SUPPLY CHAINOCTOBER 2021
THE INSTITUTE OF ENERGY ECONOMICS, JAPANTABLE OF CONTENTSEXECUTIVE SUMMARY ............................................................................................................................................... 1
CHAPTER 1. BACKGROUND AND OBJECTIVES OF STUDY ............................................................................................. 3
CHAPTER 2. SCOPE OF STUDY AND METHODOLOGY ................................................................................................... 4
CHAPTER 3. MAJOR FINDINGS.................................................................................................................................... 7
3.1. ECONOMICS OF HYDROGEN SUPPLY CHAIN ........................................................................................................................... 7
3.2. ECONOMICS OF HYDROGEN SUPPLY CHAIN INCLUDING CARBON FOOTPRINT .............................................................................. 10
3.3. ISSUES IN ANALYSES ...................................................................................................................................................... 15
CHAPTER 4. RECOMMENDATIONS............................................................................................................................ 17
4.1 POTENTIAL HYDROGEN DEMAND IN JAPAN ......................................................................................................................... 17
4.2 ENABLING THE HYDROGEN ECONOMY IN GREEN HYDROGEN EXPORTERS .................................................................................. 18
4.3 POTENTIAL AREAS OF COLLABORATION BETWEEN JAPAN AND EXPORTERS ................................................................................. 19
APPENDIX: MAJOR ASSUMPTIONS ........................................................................................................................... 21

AUTHORS:
Yoshiaki Shibata, Kan Sichao, Masato Yoshida, Hiroko Nakamura, Toshiyuki Sakamoto,
The Institute of Energy Economics, Japan©IEEJ 2021

FINAL REPORTSTUDY ON THE ECONOMICS OF THE GREENHYDROGEN INTERNATIONAL SUPPLY CHAINEXECUTIVE SUMMARY
Japan needs large amounts of hydrogen in order to decarbonize its energy system by 2050. As
domestic resources for hydrogen are presumably limited in Japan, hydrogen will need to be imported.
There is a variety of options for importing hydrogen, in terms of potential exporting countries and hydrogen
resources. Japan has carried out or is currently carrying out demonstration projects for the establishmentof international hydrogen supply chains with Australia, Brunei and Saudi Arabia, and forging dialogues on
future collaboration with other countries like Argentina and Russia. Chile would also be a promising
candidate as an exporter of hydrogen to Japan, as its renewable energy potential, including solar and wind
power, is huge and its renewable energy costs are substantially low.
This study reveals the costs and carbon footprint across the whole green and blue hydrogen supply
chains from potential suppliers to Japan; green hydrogen from Australia, Chile and the USA and bluehydrogen from Australia and Saudi Arabia.
When using liquified hydrogen or methylcyclohexane as the hydrogen carrier, the cost of greenhydrogen from Chile is the lowest among green hydrogen supply chains and can also compete with bluehydrogen supply chains if the electrolyzer cost is reduced to a third of today’s level, which is expected tobe realized internationally by 2030. However, in the case of using ammonia as the hydrogen carrier, thecost of blue ammonia from natural gas of Saudi Arabia is the lowest. Assuming a carbon price of $100/tCO2 is imposed, Chilean green hydrogen by means of liquified hydrogen or methylcyclohexane becomesa more attractive option for Japan, as the carbon footprint of green hydrogen is much smaller than bluehydrogen, while the cost advantage of blue ammonia from natural gas still remains due to the lower
production cost.
In order for green hydrogen to be even more attractive, production costs should be further reducedby, for example, elevating the capacity factor of electrolyzers through smoothing the power input by
combining solar and wind. Another option would be employing electrolyzers, not only for producing
hydrogen from renewable energy, but also as a grid service provider through demand response, which inturn will reduce the hydrogen production cost by remuneration from the grid services. If ammonia isselected as the hydrogen carrier for early-stage long-distance hydrogen transportation to Japan, green
ammonia production technologies that can cope with variable input from renewable energy should befurther developed.
However, it should be noted that possible applications of ammonia are rather limited, such as power
generation and shipping fuels. For the decarbonization of the energy system, sectors such as industry and1©IEEJ 2021

mobility bear crucial roles. Hydrogen transported in the form of liquified hydrogen or methylcyclohexane
can contribute to decarbonization of these sectors.
In addition to green hydrogen exports, domestic hydrogen applications in the exporters should also
be addressed, as these can help decarbonize the exporter’s energy system and develop related-industries
including fuel cell that are expected to contribute to mobility and stationary combined heat and power.
Furthermore, it should also be remembered that storing hydrogen over long periods is much easier thanstoring electricity in batteries, thus giving hydrogen high potential for seasonal storage. This characteristic
allows hydrogen to be a key mechanism for facilitating integration of higher shares of renewable energy
into power grids that are isolated from the national grid system. Hydrogen will bear an important role in
improving national energy security, securing a stable energy supply and enhancing resiliency in a
decarbonized manner by stockpiling renewable energy.
From Japan’s point of view, critical aspect other than hydrogen cost is energy security, which is often
overshadowed by decarbonization discussions, despite its significance for Japan, as it depends heavily
on energy supply from overseas. Green hydrogen promises to play a significant role in improving Japan’s
energy security by diversifying its energy supply resources, especially in geographical terms. For example,
Chile’s location in the APAC region can alleviate concerns over sea lane security. This study revealed thatthe shipping cost of hydrogen/ammonia does not have a significant impact on the overall supply cost, andthus the disadvantage of the long-distance transportation of hydrogen/ammonia to Japan is limited.
Collaboration between Japan and hydrogen exporters in establishing an international hydrogen supply
chain and developing domestic applications of hydrogen will open windows of more concrete business
opportunities. Areas for government to government cooperation and business matching, along withexperience-sharing may be explored through in-depth discussions among stakeholders, including
government, academia, businesses, and financial institutions. Such actions will eventually contribute to
the development of the international hydrogen/ammonia market.

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©IEEJ 2021

CHAPTER 1. BACKGROUND AND OBJECTIVES OF STUDY
Discussions on how Japan should procure hydrogen started in 2012, one year after the Great East
Japan Earthquake. It was when Japan was faced with challenges in decarbonizing its energy system,
especially its electric power system, given issues with nuclear power generation and difficulties in rapidly
deploying renewable energy. Since then, Japan has been accelerating its efforts to procure affordablehydrogen from abroad. The Japanese government and private sector have recently been jointly negotiatingwith oil & gas and coal producing countries to import blue hydrogen. The then Prime Minister Suga’s
announcement of Japan’s goal to achieve carbon neutrality in 2050 has increased the importance ofhydrogen import and has thus added momentum to actions taken toward importing hydrogen.
In general, blue hydrogen is regarded inexpensive for the moment. However, blue hydrogen entails
inherently challenging issues: the carbon footprint of blue hydrogen is larger than that of green hydrogen,international pressures on fossil fuel use is being strengthened, and blue hydrogen will not contribute toimproving Japan’s energy security if it is imported from the same oil & gas producing countries from which
Japan currently imports fossil fuels. Given these challenges pertaining to blue hydrogen, green hydrogenis a promising alternative. For example, Chile has huge potential for green hydrogen production fromrenewable energy at the lowest cost in the world1. Furthermore, its geographical location in the APAC
region, like Australia and the USA, will contribute to improving Japan’s energy security through thediversification of hydrogen supply chains, avoiding heavy dependence on oil & gas producing countries.
This study will reveal the costs and carbon footprint across entire green hydrogen supply chains frompotential suppliers to Japan and discuss their potential advantages, as well as the challenges to beaddressed by comparison with blue hydrogen supply chains.

1 “The Future of Hydrogen”, IEA, 20193

©IEEJ 2021

CHAPTER 2. SCOPE OF STUDY AND METHODOLOGY
The green hydrogen resources considered in this report are solar photovoltaics and wind power. The
green hydrogen producing countries addressed are Chile, Australia and the USA. For blue hydrogen, theresources considered are natural gas and coal and the producing countries are Saudi Arabia and Australia(Table 1).
TABLE 1. SCOPE OF HYDROGEN EXPORTING COUNTRIES AND RESOURCES

Green H2Blue H2

Country
Chile
Australia
USA
Saudi Arabia
Australia

Resources for hydrogen
Solar PV and wind
Solar PV and wind
Solar PV and windGas
Gas and coal

Note: Ammonia is included in hydrogen.

The hydrogen supply chain from the exporting country to Japan covers hydrogen production, domestictransportation in resource countries (hydrogen pipeline), conversion to hydrogen carriers, export ports,
international shipping, receiving ports, and reconversion in Japan. Liquefied hydrogen (LH2),
methylcyclohexane (MCH) and ammonia (NH3) have been selected as hydrogen carriers. This study
assumes reconversion is not needed for liquefied hydrogen, but needed for MCH (dehydrogenation) andNH3 (cracking). On the other hand, In Japan’s strategy to achieve carbon neutrality, NH3 has both the roleof a hydrogen carrier and a clean fuel for power generation, either co-fired with coal or 100% NH3
combustion. For this reason, the case in which the reconversion of NH3 is unnecessary is also addressed.
For NH3 production this study assumes two conditions. If the hydrogen for NH3 production comes fromgreen hydrogen or hydrogen produced with brown coal + CCS, the study assumes hydrogen production
and NH3 conversion (Haber-Bosch process) separately (Figure 1). However, since the process of NH3
production from natural gas is already a mature and widely-used technology, the study assumes hydrogenproduction and NH3 production are integrated in the case of blue NH3 production from natural gas (Figure
2).

4©IEEJ 2021

Hydrogenproduction

Hydrogen Conversion Export port
pipeline

Blue H2
Green H2

Water electrolysis with Solar
PV or Wind power

Receiving
port

Export port
(Liquifiedhydrogenstorage tanks)

Liquified H2
ship

Port in Japan(Liquifiedhydrogenstorage tanks)

H2+Toluene->
MCH

Export port
(Toluenestorage tanks)

MCH shipPort in Japan(Toluenestorage tanks)

Haber-Bosch:green H2 or H2from brown
coal CCS

Export port
(NH3 storage
tanks)

NH3 shipPort in Japan(NH3 storage
tanks)

Liquefaction
Natural gas reforming + CCS
Brown coal gasification + CCS
Assume100km
pipeline
distance
for allcases

Shipping

Recoversion

MCH
Reconversion

NH3
Reconversion or
No reconversion

FIGURE 1. HYDROGEN SUPPLY CHAIN

NH3 production Export port

NH3 production:
Natural gas
input + CCS

Export port
(NH3 storage
tanks)

Shipping

NH3 shipReceiving port

Port in Japan(NH3 storage
tanks)

Recoversion

NH3
Reconversion or
No reconversion

FIGURE 2. BLUE AMMONIA SUPPLY CHAIN WITH NATURAL GAS AS FEEDSTOCK

To compare the economics and GHG emission (CO2 equivalent: CO2eq) among different supply
chains, this study assumed the same scale of hydrogen production for each supply chain: 225,000 tons ofhydrogen production per year, which is equivalent to the annual volume of hydrogen to be used for 1 GW
of hydrogen-fired gas turbine power generation. The study uses 2030 as the reference year for evaluating
the economics and GHG emissions.
Hydrogen supply costs are impacted by many factors. Engineering details associated with eachprocess of the hydrogen supply chain are not included within the scope of this study. The figures presented
in this study only indicate one possible case under certain assumptions; and therefore, the hydrogen
supply cost and GHG emissions of the hydrogen supply chain in a real case could be different from thestudy’s evaluation results. However, the assumptions used in this study have been derived from reliable
sources: IEA, government studies, etc.

5Green H2Blue H2©IEEJ 2021

Upstream

HydrogenFossil fuelexploration,
production,
processing

H2 production(+CCS)Naturalgas/coal +carboncapture rate:
90%

Hydrogenpipeline

H2
compression&
pipeline(Gridelectricity)

No GHGemission for
RE power
generation

No GHGemission

Conversion andexport port

Shipping

Receiving
port

Recoversion

Liquefaction(Grid electricity)

Using H2 as shipping
fuel(Blue/Green H2emission factor)

Port inJapan(Gridelectricity)

Hydrogen + Toluene-> MCH(Grid electricity,
natural gas)

Fuel for shipping:
Very low sulfur fueloil (VLSFO)Port inJapan(Gridelectricity)

MCH-> Hydrogen+ Toluene(Natural gas,
Grid electricity)- NH3 production from H2(Grid electricity)- NH3 production fromnatural gas (Natural gas)

Fuel for shipping:
Very low sulfur fueloil (VLSFO)Port inJapan(Gridelectricity)

Reconversion
or noreconversion

Resource countries

Japan

FIGURE 3. HYDROGEN SUPPLY CHAIN & GHG EMISSION EVALUATION FLOW AND EMISSIONSOURCES FOR EACH PROCESSThis study will identify GHG emissions from the entire hydrogen supply chain (Figure 3). However, it
should be noted that this does not mean that this study has conducted a life-cycle GHG (LCGHG)
assessment that includes GHG emissions from the manufacturing process of all equipment and facilities
across the supply chain. LCGHG assessments often complicate the interpretation of analysis results wheninternational comparisons are involved. For the sake of simplicity and maintaining clear messages fromanalysis results, this study includes GHG emissions from the individual processes across the hydrogen
supply chain. Upstream fugitive emissions also include methane, which is converted to CO2 equivalent.

6©IEEJ 2021

CHAPTER 3. MAJOR FINDINGS
Based on the methodology above, the supply cost to Japan ($/kg-H2) and the carbon footprint of green
and blue hydrogen (kg-CO2eq/kg-H2) are compared among different supply chains.
This study considers two major cases for the economic evaluation of hydrogen supply chains. The
difference between the two cases lies in the assumptions for the electrolyzer cost: $700/kW for the BaseCase, and $336/kW for the Low Electrolyzer Cost Case (today’s cost is $900/kW). The technology for bluehydrogen production is already mature and thus has limited potential for cost reduction. On the other hand,electrolyzers have much room for further cost reduction. However, there is much uncertainty involved withthe cost reduction of electrolyzers, which is impacted by many factors, and therefore, this study considers
two cases for future electrolyzer costs. In addition to these two cases, a case considering a carbon priceunder the Low Electrolyzer Cost Case is also included in order to analyze economic implications of carbon
footprint differences.

3.1. ECONOMICS OF HYDROGEN SUPPLY CHAIN
Figure 4 shows the hydrogen supply cost for each supply chain. In case of NH3, ammonia is assumed
to be cracked into hydrogen so as to compare different hydrogen carriers at level playing field. Looking at
LH2 as hydrogen carrier, Chile_Wind ($4.8/kg-H2) is the most competitive among green hydrogen supply
chains, followed by Chile_PV ($5.1/kg-H2) for the Base Case. Only green hydrogen from Chile_Wind cancompete with blue hydrogen from Australia (AUS_CoalCCS and AUS gasCCS), while blue hydrogen from
Saudi Arabia is the least expensive. If the electrolyzer cost is reduced by half (Low Electrolyzer Cost Case),
the supply cost of green hydrogen from Chile (Chile_Wind and Chile_PV) can be curbed to $4.5/kg-H2,
which is lower than blue hydrogen from Australia ($4.8~4.9/kg-H2), but still higher than Saudi_GasCCS($4.1/kg-H2).
Lower elyctrolyzer cost allows green hydrogen supply options to be more competitive than bluehydrogen. Not only green hydrogen from Chile, but also green hydrogen from Australia (AUS_PV) can becheaper than blue hydrogen from Australia. However, green hydrogen production costs exhibit different
sensitivity to electrolyzer costs due to the difference in renewable energy capacity factors. Electrolyzer
CAPEX has less impact on hydrogen production cost when the capacity factor is higher.
The relative relationship among hydrogen supply costs of different supply chains using MCH as thehydrogen carrier is observed not to differ largely from that for LH2. However, in the case of NH3, the supply
cost of green ammonia from Chile in the Low Electrolyzer Cost ($3.7~3.8/kg-H2) case remains higher thanthat of blue ammonia from Saudi Arabia (Saudi_GasCCS: $2.8/kg-H2) and Australia (AUS_GasCCS:$3.3/kg-H2). As blue ammonia production from natural gas is a mature technology with optimized

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©IEEJ 2021

processes, the production cost of blue NH3 from natural gas is lower than that of green NH3 or of blue NH3
produced from coal.
With regard to comparisons among different hydrogen carriers (LH2, MCH and NH3) for greenhydrogen, MCH (ranging from $3.7/kg-H2 to 4.8/kg-H2 for the Base Case and $3.4/kg-H2 to 4.2/kg-H2 for
the Low Electrolyzer Cost Case) is the most competitive option due to lower conversion costs and shipping
costs for MCH (even if reconversion is included).
If ammonia is assumed to be directly used for power generation, either co-firing with coal-fired power
plants or 100%-ammonia gas turbines2, there is no need to crack ammonia into hydrogen at the importterminal, then the supply cost can be reduced. Figure 5 shows the ammonia supply cost without cracking(reconversion). The least expensive green NH3 is $2.9/kg-H2 of Chile_wind and Chile_PV for the Low
Electrolyzer Cost Case, which is cheaper than blue ammonia of AUS_coalCCS, while more expensive
than the blue ammonia of Saudi_gasCCS.
When taking a closer look at the shipping cost, as Chile is located farthest from Japan among thecountries addressed in this study, the longer transportation distance of hydrogen/ammonia may arise
concerns of larger shipping costs. However, this study reveals that the shipping cost of hydrogen/ammonia
accounts for a limited percentage of the whole supply cost; and therefore, the longer distance between
Chile and Japan does not cause much disadvantage.

2 100%-ammonia gas turbines in fact can be regarded as 100%-hydrogen gas turbines that crack ammonia into hydrogenby exhaust heat from gas turbines, then the hydrogen is fed into gas turbines.

8Green(Low ELY Cost)

Green(Base)LH2

Blue©IEEJ 2021

AUS_CoalCCS
AUS_GasCCS
Saudi_GasCCS
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind

4.9
4.8
4.1
5.9
5.6
5.4
5.2
5.1
4.8
5.3
5.2
5.0
4.6
4.5
4.5

Green
(Low ELY Cost)

Green(Base)

MCH

Blue

0.0

Blue
Green
(Base)
Green(Low ELY Cost)

2.0

3.0

4.0

5.0

Production

Compressor&Pipeline

Conversion

Shipping

Import terminal

Reconversion

AUS_CoalCCS
AUS_GasCCS
Saudi_GasCCS
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind

6.0

3.2
4.8
4.5
4.2
4.0
4.0
3.7
4.2
4.0
3.8
3.4
3.4
3.4
1.0

2.0

3.0

$/kg‐H2
4.0

5.0

Production

Compressor&Pipeline

Conversion

Shipping

Import terminal

Reconversion

AUS_CoalCCS
AUS_GasCCS
Saudi_GasCCS
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind

6.0

7.0

Export terminal

Ammonia is assumed to be cracked intohydrogen so as to compare hydrogen
carriers at level playing field.

4.3
3.3
2.8

5.1
4.8
4.9
4.6
4.4
4.0
4.5
4.4
4.5
4.1
3.8
3.7
0.0

1.0

2.0

3.0

4.0

Production

Compressor&Pipeline

Conversion

Shipping

Import terminal

Reconversion$/kg‐H2
5.0

6.0

Export terminal

FIGURE 4. HYDROGEN SUPPLY COST
Note: “Base” stands for Base Case and “Low ELY Cost,” for Low Electrolyzer Cost Case.

9

7.0

Export terminal

3.6
3.6

0.0

NH3

1.0

$/kg‐H2

7.0

Green(Low ELY Cost)

Green(Base)NH3

Blue©IEEJ 2021

AUS_CoalCCS
AUS_GasCCS
Saudi_GasCCS
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind

3.4
2.0
4.3
4.0
4.0
3.8
3.5
3.2
3.7
3.5
3.6
3.2
2.9
2.9

Green
(Base)

Blue

0.0

Green
(Low ELY Cost)

Unit converted to hydrogen equivalent

2.5

1.0

2.0

$/kg‐H2

3.0

4.0

Production

Compressor&Pipeline

Conversion

Shipping

Import terminal

Reconversion

AUS_CoalCCS
AUS_GasCCS
Saudi_GasCCS
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind

5.0

6.0

7.0

Export terminal

611

In unique unit

448
353

765
709
717
676
628
568
654
629
646
574
525
517
0

200

400

600

Production

Compressor&Pipeline

Conversion

Shipping

Import terminal

Reconversion$/t‐NH3
800

1000

1200

Export terminal

FIGURE 5. AMMONIA SUPPLY COST (WITHOUT CRACKING)
Note: “Base” stands for Base Case and “Low ELY Cost,” for Low Electrolyzer Cost Case.

3.2. ECONOMICS OF HYDROGEN SUPPLY CHAIN INCLUDING CARBON FOOTPRINT
The carbon footprint of each hydrogen supply chain is shown in Figure 6. As with the economics ofhydrogen supply, the carbon footprint of hydrogen supply chain is affected by many factors. In general,the green hydrogen supply chain exhibits smaller carbon footprint than that of blue hydrogen due to lower
GHG emissions from the hydrogen production process. However, GHG emissions associated with otherprocesses also constitute a large part total GHG emissions from the hydrogen supply chain. For example,
the conversion processes of LH2 and NH3 are electricity intensive. This study assumes that the electricity

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©IEEJ 2021

input for conversion comes from the grid, and as a result in countries with lower grid emission factors3,
such as Chile, the conversion process involves lower GHG emissions. Furthermore, since the study
assumes that 90% of GHG emissions associated with blue NH3 production is captured, in some cases,
the blue NH3 supply chain can involve less GHG emissions compared even to green NH3 (from the US
and Australia) .
With regard to comparisons among different hydrogen carriers (LH2, MCH and NH3), LH2 exhibits thelowest carbon footprint due partly to the fact that hydrogen is used for driving the shipping while others are
assumed to be driven by heavy fuels, and partly to the fact that reconversion process is not needed. If
ammonia is assumed to be cracking-free (reconversion-free), its carbon footprint can be reduced.

3 Grid emission factor is calculated based on the expected power generation mix of 2030. The power generation mix isderived from published literature.

11

©IEEJ 2021

LH2
Blue

AUS_CoalCCS

5.6

AUS_GasCCS

4.8

Green
(Base)

Saudi_GasCCS

4.1

US_PV

2.1

US_Wind

2.1

AUS_Wind3.0

AUS_PV

3.0

Chile_PV

0.8

Chile_Wind

0.8
0.0

MCH

kg‐CO2eq/kg‐H2

Production

2.0
Compressor&Pipeline

4.0
Conversion

6.0

Shipping

Import terminal

Reconversion

8.0
Export terminal

Green(Base)Blue

AUS_CoalCCS

7.3

AUS_GasCCS

6.5

Saudi_GasCCS

6.6

US_PV

5.3

US_Wind

5.3

AUS_Wind

4.8

AUS_PV

4.8

Chile_PV

5.0

Chile_Wind

5.0

Production

0.0

2.0
Compressor&Pipeline

4.0
Conversion

Shipping

Import terminal

Reconversion

kg‐CO2eq/kg‐H2
6.0

8.0
Export terminal

6.0

NH3
Blue

AUS_CoalCCS

8.4
2.8

AUS_GasCCS

5.2
2.6

Saudi_GasCCS

5.0
2.8

US_PV

5.2

2.8

US_Wind

Italic numbers stand for carbon footprint
when ammonia cracking is not required.

5.2

Green
(Base)

3.5
AUS_Wind

5.9
3.5

AUS_PV

5.9
1.5

Chile_PV

3.8

1.5
Chile_Wind
0.0
Production
Export terminal
Reconversion

3.8
2.0

4.0
Compressor&Pipeline
Shipping

kg‐CO2eq/kg‐H2
6.0
8.0
Conversion
Import terminal

FIGURE 6. CARBON FOOTPRINT (GHG EMISSION) OF HYDROGEN SUPPLY CHAIN

12©IEEJ 2021

In the GHG emissions evaluation of the supply chain, fugitive GHG emissions associated with fossil
fuel exploration and production are also included. However, due to a lack of reliable information, this study
applies the calculated average fugitive emissions factor of coal mining and natural gas systems(exploration, production, and processing) in the United States to all cases. The U.S.’ average emission
factor has been calculated based on the U.S. Environmental Protection Agency’s GHG emissions report4
and statistics for natural gas5 and coal production6. Upstream GHG emissions are dependent on casespecific factors and further studies will be required to evaluate the emission more correctly and precisely.
With more and more countries committed to carbon neutrality and considering placing a price on GHG
emissions, GHG emissions associated with the hydrogen supply chain could translate into economic costs.
To see how the carbon cost, if introduced7, can impact the economics of hydrogen supply, the study
assumed a carbon cost of $100/t-CO2 to be added to the hydrogen supply chain (Figure 7) and ammonia
supply chain (Figure 8). Adding a carbon price results in higher hydrogen supply costs for both greenhydrogen and blue hydrogen. However, the carbon cost associated with blue hydrogen is larger than thatof green hydrogen. Therefore, when a carbon cost is considered, green hydrogen from Chile (Chile_Wind
and Chile_PV) for the Low Electrolyzer Cost Case can compete with the cheapest blue hydrogen from
Saudi Arabia in the case of LH2 and MCH. However, when the hydrogen carrier is NH3, the cost of green
ammonia from Chile remains higher than blue ammonia from Saudi Arabia (Saudi_gasCCS) and Australia(AUS_gasCCS).

4 United States Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-2019,https://www.epa.gov/sites/default/files/2021-04/documents/us-ghg-inventory-2021-maintext.pdf?VersionId=wEy8wQuGrWS8Ef_hSLXHy1kYwKs4.ZaU
5 Natural gas production data from U.S. Energy Information Administration (EIA):
https://www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_FPD_mmcf_a.htm
6 Coal production data is also in the same EPA report
7 This report stands neutral with regard to Japan’s policy decision on carbon price. Carbon cost of $100/t-CO is assumed
2
purely for the purpose of economic analysis to take into account carbon footprint differences.

13

Green(Low ELY Cost)

Green(Base)LH2

Blue©IEEJ 2021

AUS_CoalCCS
AUS_GasCCS
Saudi_GasCCS
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind

5.4
5.3
4.5
6.1
5.8
5.7
5.5
5.2
4.9
5.5
5.4
5.4
4.9
4.6
4.6

Green
(Low ELY Cost)

Green(Base)

MCH

Blue

0.0

Blue
Green
(Base)
Green(Low ELY Cost)

2.0

3.0

4.0

5.0

6.0

7.0

Production

Compressor&Pipeline

Conversion

Export terminal

Shipping

Import terminal

Reconversion

Carbon cost

AUS_CoalCCS
AUS_GasCCS
Saudi_GasCCS
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
0.0
Production
Export terminal
Reconversion

NH3

1.0

$/kg‐H2

4.3
4.3
3.9
5.3
5.0
4.7
4.5
4.5
4.2
4.7
4.6
4.3
3.9
3.9
3.9
1.0

AUS_CoalCCS
AUS_GasCCS
Saudi_GasCCS
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
0.0
Production
Export terminal
Reconversion$/kg‐H2

2.0
3.0
4.0
Compressor&Pipeline
Shipping
Carbon cost

5.0
6.0
Conversion
Import terminal

7.0

5.1 Ammonia is assumed to be cracked intohydrogen so as to compare hydrogen
carriers at level playing field.

3.9
3.3

5.6
5.3
5.4
5.2
4.7
4.4
5.0
4.9
5.0
4.6
4.2
4.1
1.0

2.0
3.0
4.0
Compressor&Pipeline
Shipping
Carbon cost$/kg‐H2
5.0
6.0
Conversion
Import terminal

FIGURE 7. HYDROGEN SUPPLY COST INCLUDING CARBON COST
Note: The carbon price is assumed to be $100/t-CO2.

14

7.0

Green(Low ELY Cost)

Green(Base)NH3

Blue©IEEJ 2021

AUS_CoalCCS
AUS_GasCCS
Saudi_GasCCS
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind

Green(Low ELY Cost)

Green(Base)

Blue

0.0
Production
Export terminal
Reconversion

4.0
2.2

4.6
4.3
4.4
4.1
3.7
3.3
4.0
3.8
4.0
3.6
3.1
3.1
1.0

AUS_CoalCCS
AUS_GasCCS
Saudi_GasCCS
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
US_PV
US_Wind
AUS_Wind
AUS_PV
Chile_PV
Chile_Wind
0
Production
Export terminal
Reconversion

Unit converted to hydrogen equivalent

2.8$/kg‐H2

2.0
3.0
4.0
Compressor&Pipeline
Shipping
Carbon cost

5.0
6.0
Conversion
Import terminal

718

7.0

In unique unit

498
400
815
759
779
738
654
594
704
679
709
636
551
543
200

400
600
Compressor&Pipeline
Shipping
Carbon cost$/t‐NH3
800
1000
Conversion
Import terminal

1200

FIGURE 8. AMMONIA SUPPLY COST INCLUDING CARBON COST (WITHOUT CRACKING)
Note: The carbon price is assumed to be $100/t-CO2.

3.3. ISSUES IN ANALYSES
It should be noted that there are uncertainties in the assumptions made in this study (See Appendix).
For example, blue hydrogen/ammonia is assumed to be produced with an additional cost for CCS with acarbon capture rate of 90%. This can be realized in steam methane reforming of gas for blue hydrogen.
However, in the case of blue ammonia, the current carbon capture rate for the entire blue ammonia

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production from gas is, in general, 50% to 60%8. Hence the assumption for blue ammonia may be too
optimistic. If a carbon capture rate of 90% is sought for all blue ammonia production, costs could be higher.
On the other hand, in terms of green ammonia production, this study assumes the same process as blue
ammonia production from gas. However, the large-scale and constant operation assumed for this process
is not appropriate for variable input from renewable energy. To realize green ammonia production costs ofthe same level as blue ammonia, technology development for coping with variable input is necessary.

8 70% of CO emissions come from the main (intensive) process and 30% from the remaining (distributed) process.
2

Therefore, if the carbon capture rate of the main process is assumed to be 90%, the whole capture rate will be around
60%.

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CHAPTER 4. RECOMMENDATIONS
4.1 POTENTIAL HYDROGEN DEMAND IN JAPAN
Under the Green Growth Strategy9, Japan seeks to create hydrogen demand of 3 million tons in 2030
and 20 million tons in 205010. Commercial vehicles, including fuel cell (FC) trucks and hydrogen-powered
ships will be introduced through 2030. In the power sector, stationary fuel cells and small-scale hydrogenturbines will be locally introduced in the short term, with an aim to install large-scale hydrogen gas turbines
in around 2030, when a commercially viable hydrogen supply chain has been established globally. Pilot
projects to decarbonize manufacturing processes using clean hydrogen will be continued through 2030.
During the transition to a hydrogen economy, fuel ammonia will be first used for co-firing at existingcoal-fired power plants 11 . To this end, the demonstration project in Chubu-area is expected to becompleted around 2025. Therefore, Japan will need to rely on ammonia imports to decarbonize its fuelsupply in the short to medium term.
In the industry, commercial and household sectors, fossil fuels will be replaced with hydrogen for heat
demand by installing either hydrogen burners/boilers for industrial use or fuel cells and boilers forcommercial and residential use, as well as through newly built pipeline distribution of hydrogen or throughdelivery of synthetic methane produced from hydrogen by the existing city gas pipeline. Given limited
domestic resources, clean hydrogen imports will be key to mainstreaming hydrogen in Japan.
While it is true that Japan needs to import hydrogen, it should be noted that Japan’s energy security
cannot be improved if hydrogen is imported from the countries from which Japan is currently importing
fossil fuels. In this sense, green hydrogen from for example Chile promises to play a significant role in
improving Japan’s energy security through diversifying its energy supply resources, especially in terms of
its geographical location in the APAC region, which can alleviate concerns over sea lane security. The
longer distance between Chile to Japan compared to other hydrogen/ammonia supply chains may arise
concerns of larger shipping costs. However, this study reveals that the shipping cost of hydrogen/ammonia
does not have a significant impact on the overall supply cost, Therefore, the disadvantages of the longerdistance transportation of hydrogen/ammonia from Chile to Japan is limited.
From the viewpoint of hydrogen carriers, this study has found that MCH is the most competitive option
due to lower conversion costs and shipping costs for MCH even if reconversion is included. If it is assumed
that NH3 does not need reconversion (cracking) to hydrogen, NH3 is the less expensive option through2030. However, it should be noted that possible applications of ammonia are rather limited, such as power

9 Ministry of Economy, Trade and Industry (2020) Green Growth Strategy Through Achieving Carbon Neutrality in 2050,

https://www.meti.go.jp/english/press/2020/pdf/1225_001b.pdf
10 Domestic hydrogen demand for large-scale power generation is estimated to be 5-10 million tons per year. Around 6

million tons will be needed to fuel commercial vehicles such as FC trucks, and 7 million tons, for green steel.
11 For example, if 20% co-firing is implemented at all coal-fired thermal power plants in Japanese major power companies,
an estimate of about 10% of CO2 emissions from the domestic electric power sector will be reduced.

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generation and shipping fuels. In fact, Japan aims to use ammonia first for co-firing with coal-fired power
generation where toxic ammonia can be centrally managed and controlled. If ammonia is to be used for
distributed applications, such as industrial heat or fuel cells, the process of ammonia cracking to hydrogen
will be required; and this may result in raising the supply cost. Hence, attention should be paid to the factthat ammonia can be used only for rather limited applications, while Japan needs hydrogen for othersectors as well, including high temperature industrial heat demand and mobility. For these applications,hydrogen imported by means of MCH and LH2 can be candidates. Selection of hydrogen carriers should
be discussed based on hydrogen applications.

4.2 ENABLING THE HYDROGEN ECONOMY IN GREEN HYDROGEN EXPORTERS
According to the economic analysis herein of hydrogen exports to Japan, the prices of green hydrogenare still higher than Japan’s target price, which is JPY30/Nm3-H212 in 2030 and JPY20/Nm3-H213 beyond
2030 14 . However, potential reductions in hydrogen shipping costs are heavily dependent on future
developments in LH2 and MCH technologies in Japan. Furthermore, ammonia shipping technology has
almost reached maturity. Hence, further reductions in overall costs to meet Japan’s target will call for lower
green hydrogen production costs in producing countries.
Specific measures to reduce costs of green hydrogen production from electrolyzers should beestablished. Points that should be highlighted are how the power inputs to electrolyzers can be smoothedand how electrolyzers can be employed as grid service providers. This study assumed solar PV and windseparately as sources of green hydrogen/ammonia. However, in reality, smoothed power input toelectrolyzer from a combination of solar PV and wind can be an option, thus contributing to elevating thecapacity factor of electrolyzers and leading to lower hydrogen production costs. To make this happen, theoptimal power supply from a combination of solar PV and wind should be identified, taking account ofgeographical location. Another option to improve the capacity factor of electrolyzers may be using gridelectricity. This would involve optimizing the electrolyzer operation pattern to minimize the hydrogenproduction cost based on two factors: the power procurement cost and capacity factor. By expanding theoperating capacity of electrolyzers at during the hours when the wholesale power price is low (i.e. when
the share of renewable electricity is high), and vice versa, the hydrogen production cost can be minimized
and the use of renewable electricity can be maximized. However, it should be noted that the carbon
footprint of hydrogen depends on the power generation mix. Above all, electrolyzers can be used for LFC

12 USD3/kg-H = USD0.47/kg-NH
2
3
13 USD2/kg-H = USD0.31/kg-NH
2
3
14 Hydrogen and Fuel Cell Strategy Council (2019) The Strategic Road Map for Hydrogen and Fuel Cells- Industry-academia-government action plan to realize a “Hydrogen Society” –(https://www.meti.go.jp/english/press/2019/pdf/0312_002b.pdf)

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(Load Frequency Control) through demand response. This will allow electrolyzer costs to be compensatedby providing grid services, thus leading to reducing hydrogen production cost.
In addition to the measures above, cost reductions in green hydrogen production can be pursued byadvancing production technology development. However, scaling up electrolyzer capacity should beaccompanied by increased domestic application. The domestic use of hydrogen will also contribute todecarbonizing the energy system of green hydrogen exporters. Increased demand in the industrial,
transport and household sectors may enable the achievement of economies of scale. Formulating aroadmap for domestic applications and thus presenting policy direction will facilitate the uptake of suchtechnologies.
Furthermore, it should also be remembered that storing hydrogen over long periods is much easierthan storing electricity in batteries, thus giving hydrogen high potential for seasonal storage. This
characteristic allows hydrogen to be a key mechanism for facilitating integration of higher shares ofrenewable energy into power grids that are isolated from the national grid system. Hydrogen will bear an
important role in improving national energy security, securing a stable energy supply and enhancing
resiliency in a decarbonized manner by stockpiling renewable energy.

4.3 POTENTIAL AREAS OF COLLABORATION BETWEEN JAPAN AND EXPORTERS
Various solutions can be explored through bilateral cooperation and other forms of collaboration
among various players in Japan and green hydrogen exporters. Channels for cooperation should besought across the entire supply chain, covering hydrogen production, transport, storage and application.
As one of the first countries in the world that formulated a hydrogen strategy and roadmap, Japan canoffer its support in designing a roadmap for hydrogen deployment in green hydrogen exporters. Clear
political will promises to attract foreign investment in target areas.
Hydrogen transport and energy carrier technologies, as well as port infrastructure technologies areimportant areas for collaboration between Japan and green hydrogen exporters. In addition to realizing
future exports of green hydrogen to Japan, collaboration should be sought in the domestic application ofhydrogen as an option for decarbonizing the domestic energy system. Some proposed areas forcollaboration are, as aforementioned, harnessing electrolyzers for smoothing the increased fluctuation
caused by the integration of solar PV and wind power into the power grid. In Japan, such technologies are
currently being tested in several demonstration projects, including the Fukushima Hydrogen Energy
Research Field (FH2R), which aims to balance supply and demand in the power grid while establishing
low-cost green hydrogen production technology.15

15 NEDO (2020) “The world's largest-class hydrogen production, Fukushima Hydrogen Energy Research Field (FH2R)

now is completed at Namie town in Fukushima” Press release (March 7, 2020)(https://www.nedo.go.jp/english/news/AA5en_100422.html)

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Regarding ammonia production, Harber-Bosch process was originally designed for constant operationand large-scale production. However, technologies for ammonia production based on variable input fromrenewable energy is currently being developed in Japan. Sharing these experiences would be promisingareas of cooperation.
Other potential areas of cooperation include decarbonizing the final energy demand (industry,
residential and transport sectors), by promoting the hydrogen application in the industry and the use ofcommercial and residential stationary fuel cells, as well as deploying fuel cell vehicles and hydrogen fueling
networks to support them.
It should also be noted that while hydrogen plays an important role for decarbonization, the carbon
footprint of hydrogen is a critical issue. Japan and hydrogen exporters should collaboratively leadinternational discussions on standards for hydrogen carbon footprint. It is also expected that thedevelopment of hydrogen/ammonia and fuel cell technologies through collaboration between Japan andhydrogen exporters can contribute to the development of relevant international markets.
Collaboration will open windows of more concrete business opportunities. Areas for government togovernment cooperation and business matching may be explored through workshops and in-depth
discussions among stakeholders, including government, academia, businesses, and financial institutions.

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APPENDIX: MAJOR ASSUMPTIONS
For hydrogen production, this study uses the same assumptions as in IEA’s “The Future of
Hydrogen”16 (2030 cost assumptions). However, for green hydrogen production, this study considers twocases. The base case assumes an electrolyzer CAPEX of $700/kW in 2030 (IEA), and the low-cost caseassumes an electrolyzer CAPEX of $336/kW based on interviews with global electrolyzer manufacturers,
as reported by the Ministry of Energy, Chile.
The study also uses figures provided in IEA’s “The Future of Hydrogen” for the cost evaluation ofhydrogen liquefaction, MCH conversion and reconversion, NH3 production, hydrogen shipping, andhydrogen export/receiving ports. However, since this study treats hydrogen production and NH3 production
as separate processes in the cases of green hydrogen and blue hydrogen production with coal, this study
also uses NH3 conversion cost estimations from the Institute of Applied Energy’s report17.
Feedstock cost assumptions have a significant impact on hydrogen production costs. and since thisstudy applies the same cost and technical specification assumptions to all the countries, the differences inhydrogen supply cost and carbon footprint among the countries addressed are largely attributable to thecountry-specific differences in feedstock and fuel costs and emission factors (Table A1).
Projections of future renewable power generation costs or fossil fuel costs are not included within thescope of this study. For Chile, the renewable power generation cost and capacity factor for 2030 was
provided by the Ministry of Energy of Chile. For Australia, assumptions for the future cost and capacity
factor have been derived from a study by the Australian national science agency, CISRO18. For the UnitedStates, the data for renewable power generation is from EIA’s annual energy outlook study19.
Shipping distance is another important factor that affects hydrogen supply costs. Assumptions ofshipping distances is shown in Table A2. For Chile, since solar PV resources are located in the northernpart of the country and wind resources in the south, the study considers two different ports: one in the
North and the other in the South.
As mentioned above, for the CAPEX of blue hydrogen production, this study uses IEA’s assumptions,in which the CCS cost is already incorporated in the overall CAPEX. According to IEA’s assumptions,
CAPEX for hydrogen production with natural gas reforming will have a nearly 50% markup with CCS
compared with no CCS ($910/kWH2 without CCS and $1,360/kWH2 with CCS (2030)), and 4% markup forcoal gasification ($2,670/kWH2 without CCS and $2,780/kWH2 with CCS (2030)). For blue NH3 production
from natural gas, CCS results in 28% CAPEX cost increase ($905/ton-NH3 without CCS and $1,260/tonNH3 with CCS).

16 IEA (2019), The Future of Hydrogen, IEA, Paris https://www.iea.org/reports/the-future-of-hydrogen
17 The Institute of Applied Energy (2016). “Research on the introduction scenario of an energy carrier total system / Cost

analysis of energy carrier technologies, Impact evaluation of long term global energy supply and demand, Development of
scenario on hydrogen technologies and utilization.” Research commissioned by NEDO.
18 Graham, P., Hayward, J., Foster J. and Havas, L. 2021, GenCost 2020-21: Final report, Australia.
19 U.S. EIA, “Levelized Cost of New Generation Sources in the Annual Energy Outlook 2021”,
https://www.eia.gov/outlooks/aeo/pdf/electricity_generation.pdf

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TABLE A1. MAJOR ASSUMPTIONS ON FEEDSTOCK AND FUEL COSTS AND EMISSION
FACTORS
Grid Electricity

Price($/kWh)PV

Emissionfactor(kg‐
LCOE
CO2/kWh) ($/kWh)Natural gas

Wind

CapacityfactorLCOE($/kWh)Capacityfactor

Upstream
Combustion emission
emissionfactorfactor(kg‐
Price(kg‐CO2‐
CO2/mmbt Price($/mmbtu) eq/mmbtu) u)($/ton)

Chile

0.07

0.10

0.017

32%

0.021

64%

5.2

Australia

0.09

0.40

0.019

32%

0.031

46%

6.2

US

0.07

0.27

0.031

29%

0.031

41%

4.2 53.1

Saudi Arabia

0.05

0.30

4.0

Japan

0.17

0.42

8.5

Very low sulfer fueloil (VLSFO)

Coal

Upstream
emissionfactor(kg‐CO2‐
eq/ton)Emissionfactor(kg‐
CO2/MJ)

Price($/ton)

Water

Price
($/ton)

0.5
4.4

16.2

74.03

400

0.078

4.4

0.03

TABLE A2. ASSUMPTIONS ON SHIPPING DISTANCE
Resource country
Chile (North)
Chile (South)
Australia
US
Saudi Arabia

1.5
1.0

Port in Resource country

Port in Japan

Mejillones, Antofagasta
Cabo Negro, Magallanes
Melbourne
Houston (via Panama canal)
Ras Tanura

Yokohama

Distance(nautical miles)
9,192
9,259
4,907
9,254
6,593

Source: https://sea-distances.org/

22
Contact: report@tky.ieej.or.jp