Japan’s Costly
Ammonia Coal
Co-Firing
Strategy
September 28, 2022

Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Contents
Section 1.

Executive summary1

Section 2.

Overview of Japan’s decarbonization goals and the power sector’s role
2.1. Why Japan wants to use ammonia in power generation
2.2. Japan’s current emissions trend and targets
2.3. Policy framework for coal power plant retrofits

2
2
2
3

Section 3.

Summary of utilities’ ammonia co-firing strategies
3.1. Japan
3.2. Global

555Section 4.

Economic Analysis
4.1. Levelized cost of electricity
4.2. Cost comparison with carbon capture and storage (CCS) technologies

779

Section 5.

Greenhouse gas emissions
5.1. Carbon dioxide (CO2) emission reductions
5.2. Marginal abatement cost of ammonia coal co-firing
5.3. Nitrous oxide (N2O) emissions: no laughing matter

11
11
11
12

Section 6.

Safety and toxicity
6.1. Safety and toxicity
6.2. Ammonia-related regulations

13
13
13

Section 7.

Clean ammonia supply and demand
7.1. Current market size
7.2. Future market size
7.3. Energy security considerations
7.4. Clean ammonia’s role in decarbonization

15
15
16
17
18

Appendices19

Appendix A.

Retrofitting coal-fired power plants

19

Appendix B.

Ammonia production cost assumptions

21

About us

22

Table of figures
Figure 1: Levelized cost of electricity for retrofitting coal-fired power plants forammonia co-firing at different blend rates compared to new offshore wind inJapan
1
Figure 2: Historical carbon dioxide emissions in Japan .................................... 2
Figure 3: Japan’s annual electricity generation mix .......................................... 2
Figure 4: Coverage of Japan's proposed subsidy for clean hydrogen andammonia 4© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Figure 5: Jera’s Hekinan coal-fired power plant................................................ 5
Figure 6: Countries and major companies working on ammonia co-firing tech . 6
Figure 7: Comparison of levelized cost of electricity in 2024.............................. 8
Figure 8: Comparison of levelized cost of electricity in 2030.............................. 8
Figure 9: Comparison of levelized cost of electricity in 2050.............................. 8
Figure 10: LCOE comparison of different technologies.................................... 10
Figure 11: Emissions from power generation and production of green NH3 .... 11
Figure 12: Emissions from power generation and production of blue NH3....... 11
Figure 13: Emissions from power generation and production of gray NH3 ...... 11
Figure 14: Marginal abatement cost in 2030.................................................... 12
Figure 15: Marginal abatement cost in 2050.................................................... 12
Figure 16: No laughing matter: global warming potential of CO2 vs. N2O......... 12
Figure 17: Nitrous oxide (N2O) emission intensity for different ammonia co-firingratio ................................................................................................................. 12
Figure 18: Ammonia-related fire in China in 2013............................................ 13
Figure 19: Japan’s historical ammonia demand............................................... 15
Figure 20: Japan’s current ammonia demand size and targets for 2030 and
2050 ................................................................................................................ 16
Figure 21: Theoretical cumulative volume of ammonia supply globally(converted from clean hydrogen production projects proposed by developers) 16
Figure 22: Outlook on ammonia production costs for Japan ............................ 17
Figure 23: LCOE comparison (20% ammonia co-firing)................................... 19
Figure 24: LCOE comparison (50% ammonia co-firing)................................... 19
Figure 25: LCOE comparison (100% ammonia firing)...................................... 19
Figure 26: Impacts of coal-fired power plant upgrades to burn a blend with 20%
ammonia ......................................................................................................... 20
Table of tables
Table 1: Co-firing eligibility under the proposed capacity mechanism for
low/zero carbon ................................................................................................. 4
Table 2: Safety comparison of ammonia and natural gas ................................ 13
Table 3: Current regulations related to ammonia use ...................................... 14
Table 4: Ammonia demand size comparison ................................................... 17
Table 5: Suitability of ammonia for end uses in Japan ..................................... 18
Table 6: Costs of conversion to ammonia from hydrogen ................................ 21© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Section 1.

Executive summary

30xJapan wants to retrofit its existing coal power plants to enable co-firing of coalwith ammonia to reduce carbon dioxide emissions. This report examines thepotential emission reduction benefits, safety and energy security concerns aswell as economics of Japan’s proposed strategy.

Japan’s proposed 2050
ammonia demand target
compared to the current sizeof its domestic ammonia
market•The Japanese government has committed to reducing the country’s emissions by 46% by2030 relative to 2013 and reach net-zero emissions by 2050. Electricity generation remains
Japan’s largest source of emissions due to heavy reliance on thermal power plants, including
new coal-fired power plants built in recent years. Japanese utilities supported by thegovernment are exploring co-firing of ammonia at existing coal plants to reduce emissions.

•

The CO2 emissions from a coal power plant burning ammonia at a co-firing ratio of below
50% will still emit as much CO2 as a natural gas fueled combined cycle gas turbine. Coal
power plants co-firing ammonia may also emit more nitrous oxide, a greenhouse gas with
global warming potential 273 times larger than that of CO2 for a 100-year timescale.
Additionally, handling ammonia requires more care than coal due to its volatility and toxicity.

2.8x
LCOE of a retrofitted coalplant running on 100% green
ammonia produced in Japan
compared to offshore wind

$223/MWh
Levelized cost of electricity
generation in 2050 for a
retrofitted coal power plantrunning on green ammonia

Figure 1: Levelized cost of electricity for retrofitting coal-fired power plants for ammonia
co-firing at different blend rates compared to new offshore wind in Japan$/MWh (2021 real)
600

produced in Japan

500
400

100% NH3 firing
50% NH3 co-firing

300

Offshore wind

200
100
20% NH3 co-firing
0
2024
2030

2040

2050

Source: BloombergNEF. Ammonia co-firing cost range shows ammonia types. NH3 = ammonia.
•

The levelized cost of electricity (LCOE) generation for a retrofitted coal power plant in Japan
using a 50% clean ammonia co-firing ratio is expected to be at least $136/MWh in 2030. By
2050, the LCOE of a retrofitted coal power plant running 100% on clean ammonia is expected
to be at least $168/MWh. These values are costlier than the LCOE of renewable alternatives
such as offshore wind, onshore wind or solar with co-located batteries. Clean ammonia isbetter suited for decarbonization of applications such as fertilizer production than power.

© Bloomberg Finance L.P.2022•

As Japan’s domestic clean ammonia production remains more expensive than green
ammonia produced in Australia or blue ammonia produced in the Middle East, the country’s
proposed ammonia co-firing strategy would create new energy import dependence.

•

Corrects references to IHI and MHI in paragraphs three and four on page 5.

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

1Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Overview of Japan’s decarbonization
goals and the power sector’s role

Section 2.

Japan has set ambitious emission reduction targets by 2030 and 2050. The
power sector is the biggest source of emissions in Japan due to its heavy
reliance on fossil-fueled thermal power plants.

2.1.

Why Japan wants to use ammonia in power generation
Japanese incumbent utilities and the government are advocating for ammonia co-firing at existingcoal power plants for the following reasons:

2.2.

•

Japan has a relatively large – 49GW – fleet of coal power plants, which accounted for 30% ofelectricity supplied in fiscal year 2021. Co-firing coal with ammonia offers a pathway to
reduce carbon dioxide (CO2) emissions, without the need to phase out these coal plants.

•

Japanese incumbent utilities cite land constraints as a challenge for the development of
renewables, although Japan’s Ministry of the Environment analysis1 shows the country still
has ample space to add renewables.

•

The government and Japan’s thermal power industry hope commercialization of ammonia cofiring technology can bolster exports.

Japan’s current emissions trend and targets
Japan emitted 1,044 million tons of carbon dioxide (CO2) in fiscal year 2020 (Figure 2),
accounting for about 2% of global emissions. The power sector is Japan’s largest source ofemissions, accounting for 37% of emissions in FY2020, due to heavy reliance on fossil-fueled
thermal power plants (Figure 3).

Figure 2: Historical carbon dioxide emissions in Japan

Electricity mix

million tons of CO2
1,500
1,000
500

2020

2015

2010

2005

2000

1995

0

1990

Figure 3: Japan’s annual electricity generation mix

Agriculture
Residential
Non-power energy
Other
Commercial
Transport
Industry
Power

21%
6%
5%
30%

1%
36-38%

Nuclear20-22%
2%
19%

38%
20%
2021 actual

Hydrogen,ammonia
Renewables

Oil

Coal
Gas

2030 target

Source: National Institute for Environmental Studies. Note: Years Source: BNEF, Ministry of Economy, Trade, and Industry. Note:show Japan’s fiscal year starting from April to March.
Years show Japan’s fiscal year starting from April to March.

1© Bloomberg Finance L.P.2022

Japan’s Ministry of the Environment estimates the resource potential of solar and onshore to be 2,746GW
and 284GW (excluding unavailable sites due to topography and regulations), respectively. Japan had
installed 78GW of solar and 5GW of onshore wind by the end of 2021.

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

2Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

In 2021, Japan updated its nationally determined contribution (NDC) to the Paris Agreement toincrease its emission reduction target to 46% by 2030 compared to 2013 levels. Japan also
legislated its 2050 net-zero target. Japan is also signatory to the G-7 June 2022 Summit
statement calling for “a fully or predominantly decarbonized power sector” by 2035.
To meet its interim emission reduction target, Japan’s Sixth Strategic Energy Plan calls for
reducing coal’s share of electricity generation to 19% in 2030 from 30% in 2021. The plan calls forammonia and hydrogen to account for 1% of electricity supply in 2030.

2.3.

Policy framework for coal power plant retrofits
Japan has been implementing policy mechanisms to support the reduction of emissions from coal
power plants. In 2021, the country adopted a new efficiency standard for coal power that requires
power generators with coal plants to meet a fleet-wide energy efficiency of 43% by 2030. While
the goal of the plan is to phase out existing inefficient coal plants, the policy allows such plants toremain online if they adopt co-firing with ammonia or biomass2.
In May 2022, the government also introduced a new classification recognizing hydrogen andammonia as non-fossil energy sources from April 2023 onward, regardless of how the hydrogenand ammonia is produced.
Hydrogen color labels
The hydrogen industry uses labels such as green and blue as shorthand for how hydrogen ismade. Production methods differ on the volume of greenhouse gases they emit. The mostcommon hydrogen labels are:
• Green, made via electrolysis of water using renewable electricity – this releases few or nogreenhouse gas emissions.
• Blue, made via steam reforming of methane or gasification of coal coupled with CO 2 captureand storage (CCS) – this releases more emissions than green hydrogen, but less thangray.
• Gray, made via steam reforming of methane or gasification of coal without CCS – the mostcommon method today that releases large volumes of CO2.
The Japanese government is expanding its financial support for ammonia co-firing. In 2021,
Japan set up a 2 trillion yen ($14 billion) Green Innovation Fund for research and development(R&D) of key decarbonization technologies. The budget for R&D related to burning ammonia forelectricity generation was 68.8 billion yen ($482 million). Companies such as IHI Corporation,
Jera, Chiyoda Corp. and Mitsubishi Heavy Industries have received subsidies to launchdemonstration projects. See Section 3 for more details on these companies.
Another financial support for ammonia co-firing is a new capacity payment mechanism for lowand zero-carbon technologies. Japan’s Ministry of Economy, Trade, and Industry (METI) is
drafting a 20-year capacity auction mechanism for low- and zero-carbon technologies fromFY2023 to encourage new investment. The initial proposal allows for retrofitting of existing coalplants to burn ammonia however new coal plants would be ineligible (Table 1).

2© Bloomberg Finance L.P.2022

See Japan's New Coal Power Efficiency Standard Is Weak (web | terminal) for more details.

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

3Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Table 1: Co-firing eligibility under the proposed capacity mechanism for low/zero carbon
Types

Retrofits

New builds

H2 / NH3 co-firing at coal-fired
power plants

ApplicableNot applicable

H2 / NH3 co-firing at gas-fired
power plants

Applicable

Applicable

Biomass co-firing at coal-fired
power plants

Not applicableNot applicable

Conversion to biomass-only

ApplicableNot applicable

Source: BloombergNEF, METI. H2 = hydrogen. NH3 = ammonia.
The price cap in the new capacity auction could be around 50,000 yen/kW/year ($350/kW/year)
for ammonia co-firing at 20% energy content, according to METI’s estimate. Based on the latest
discussions, the minimum capacity requirement for ammonia co-firing would be 50MW. Winningcoal retrofit projects must be ready for power delivery within seven years from the auction date.
Japan is also considering a new subsidy to cover the costs of producing and transporting cleanhydrogen and ammonia relative to existing fuels (Figure 4). The precise details of the subsidy,
which was first unveiled on August 26, have yet to be determined. The support will consider theemissions associated with the hydrogen production process. While gray hydrogen projects will be
subsidized in the near term, such projects must eliminate emissions by a yet-to-be set deadline.
Figure 4: Coverage of Japan's proposed subsidy for clean hydrogen and ammonia
Domestic production

Power

+

-

Pipeline, transporto 220kV substations,Electrolysis: 260MW
km transmission linePower+
3km distribution line
H2

End-users

H2

H2

o 220kV substations,Electrolysis: 260MW
km transmission line
Overseas production
3km distribution line
H2

Shipping

Storage

Dehydrogenation

Pipeline:
Spherical H2 tanks: 10 tanks,
Source: Ministry of Economy, Tradeand Industry, BloombergNEF. Note: Blue dotted lines are covered by the subsidy.
m, diameter 273mm
each 2,000m 3 at 15.5bar
H2

Pipeline:
km, diameter 273mm

Spherical H2 tanks: 10 tanks,each 2,000m 3 at 15.5bar© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

4Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Section 3.

Summary of utilities’ ammonia cofiring strategies
Japanese companies are actively developing ammonia co-firing projects inJapan and increasingly overseas. One coal-fired power plant in Japan iscurrently going through a technical test of 20% ammonia co-firing. Japanesecompanies are also aiming to export their approach to India and Southeast
Asian countries. South Korea is also pursuing ammonia co-firing.

3.1.

Japan
Japan’s 10 vertically integrated regional utilities as well as Electric Power Development Co.,better known as J-Power, have committed to achieving net zero emissions by 2050. They all plan
to use clean fuels such as ammonia and hydrogen is one of the key decarbonization strategies
adopted by the Japanese utilities. These technologies including 20% ammonia co-firing andcarbon capture and storage (CCS) are yet to be fully commercialized in Japan, risking Japan'scommitment to fully/predominately decarbonize the power sector by 2035.

Figure 5: Jera’s Hekinan
coal-fired power plantJera, the thermal power joint venture of Tokyo Electric Power Co. (Tepco) and Chubu ElectricPower Co., is leading the efforts toward the commercialization of ammonia coal co-firing. The
company is currently testing 20% ammonia co-firing in collaboration with IHI Corporation at its
1GW Hekinan 4 coal-fired plant. It plans to trial 50% co-firing at its 1GW Hekinan 5 coal-fired
power plant by FY2028. The company wants to expand ammonia co-firing to more of its coalplants by the early 2030s, with the goal of reaching 100% ammonia-fueled thermal plants by
2050. To source ammonia, in February 2022, Jera announced a tender for a long-term (over 10
years) contract for carbon-free ammonia from FY2027. IHI also announced that it successfully
tested burning 100% liquid ammonia without nitrous oxide (N2O) emissions at a 2MW gas turbine.
Mitsubishi Heavy Industries (MHI), a competitor of IHI, is also developing ammonia co-firing forcoal-fueled thermal plants with Jera.

Source: Jera

Kyushu Electric is another utility active in this space. The company signed a memorandum of
understanding (MoU) with Norwegian chemical company Yara for procurement of blue ammonia
produced in Australia. Kyushu Electric has also partnered with Jera and Chugoku Electric to work
together for fuel cost reductions, transportation and storage of ammonia, and policy development.

3.2.

GlobalJapanese companies and the government are promoting their co-firing strategy overseas. At
COP26, Japanese Prime Minister Fumio Kishida announced a new $100 million fund to support
the development and export of hydrogen and ammonia co-firing through the Asia Energy
Transition Initiative. At the recent Quad meeting in May 2022, leaders from Australia, India, Japanand the US also agreed to collaborate in developing clean hydrogen and ammonia supply chains.

© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

5Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Figure 6: Countries and major companies working on ammonia co-firing tech

Exploring NH3
combustion techfor electricity
The Quad
Both

Source: BloombergNEF
Utilities in South Korea and India are also adopting ammonia co-firing as a means to continue
running their coal power plants. South Korea’s Ministry of Trade, Industry and Energy (MOTIE) isaiming to commercialize 20% ammonia co-firing technology at more than half of the country’s 43
coal-fired power plants by 2040. KEPCO Engineering & Construction, Doosan Enerbility, andSamsung C&T signed an MoU to collaborate on ammonia co-firing technologies in June 2022.
Additionally, Lotte Chemical signed an MoU with Japanese trading house Itochu to develophydrogen and ammonia infrastructure targeting the Japanese and Korean market. They also plan
to jointly invest in clean ammonia production facilities. India’s independent power producer Adani
Power signed an MoU with IHI and Kowa Company to collaborate on evaluating the feasibility ofammonia co-firing at Adani Power’s Mundra coal-fired power plant.
Japanese companies are also promoting the approach in Southeast Asia. In Indonesia, IHI andMHI are working together with local companies. MHI’s ammonia proposed co-firing project at theSuralaya co-fired power plant in Indonesia is expected to start operations around 2030. IHI is also
conducting technical feasibility with two local partners including Petroliam Nasional Bhd(Petronoas) for power plants in Malaysia. Jera and MHI are also working together with a local
company in Singapore to develop a 100% ammonia-fueled thermal plant on Jurong Island.
Japanese players want to develop ammonia supply chains by partnering with companies in othercountries, notably in Australia. Osaka Gas signed an MoU with Australia’s integrated energy
company AGL Energy to examine the feasibility of developing a green ammonia supply chain by
the end of 2022. Japanese trading house Itochu has also partnered with Australian companies
including Dalrymple Bay Infrastructure and North Queensland Bulk Ports Corp. to produce green
ammonia in Australia and export to other countries. IHI is also exploring a blue ammonia supply
chain between the United Arab Emirates (UAE) and Japan.

© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

6Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Section 4.

Economic Analysis
The levelized cost of electricity (LCOE) for a typical Japanese coal plant
retrofitted for ammonia co-firing at 50% or higher energy content is significantly
higher than zero-emission sources such as offshore wind. Ammonia co-firing is
unlikely to become an economically viable path for Japan to reduce power
sector emissions.

4.1.

Levelized cost of electricity
Our research estimates the levelized cost of electricity (LCOE)3 of coal-fired power plant retrofits
based on three types of ammonia: green ammonia produced in Japan, green ammonia imported
from Australia, and blue ammonia imported from the Middle East4. Ammonia is more expensive
than coal on an energy-equivalent basis due to ammonia’s lower energy content. This explains
the rise in LCOE with higher blends of ammonia. See Appendix A and Appendix B for moredetails on ammonia production costs and other assumptions.
Currently, the high costs of electrolyzers push up the costs of green hydrogen/ammonia. Japan’shigh costs of renewables also drive up the costs of domestically produced hydrogen/ammonia
relative to the molecules imported from Australia. Yet, we expect the costs of electrolyzer andrenewable energy projects to continue to decline to 2050, lowering the costs of greenhydrogen/ammonia. On the other hand, we expect the costs of blue hydrogen/ammonia imported
from the Middle East to change little over 2024-2030 since natural gas reforming is already a wellestablished process. The cost reductions of blue hydrogen/ammonia are also limited over 20302050, compared with green hydrogen/ammonia, largely due to an increase in future natural gas
prices, compensating for the fall in emission abatement costs. See 1H 2022 Hydrogen Levelized
Cost Update (web | terminal) for more details.
In 2024, when Jera aims to complete the technical test of 20% ammonia co-firing, coal retrofits
burning a 20% blend of locally produced green ammonia should be the most expensive($148/MWh), followed by retrofits with green ammonia imported from Australia ($108/MWh) andretrofits with blue ammonia imported from the Middle East ($97/MWh), as shown in Figure 7. Blue
ammonia is cheaper than green ammonia due to the technical maturity of natural gas reforming.
Japan’s domestic green ammonia is more expensive than green ammonia from Australia due tothe high costs of renewable projects in Japan despite the added cost of transporting ammonia
from Australia.

© Bloomberg Finance L.P.2022

3

Levelized cost of electricity, or LCOE, shows the long-term offtake price on a MWh-basis required to recoup
all project costs and achieve a required equity hurdle rate on the investment.

4

The United Arab Emirates (UAE) data was used as a proxy for the Middle East.

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

7

Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Figure 7: Comparison of levelized cost of electricity in 2024

2024$/MWh (2021 real)

310

188

182
128

Blue ammonia
from the Middle East

269

189

148

Green ammonia
from Australia

324

290

272

135

Green ammonia
from Japan

526

162

108
97

Onshore wind Solar + battery 80% coal - 20%50% coal - 50%100% ammonia+batteryammoniaammonia
Renewables

Coal retrofits

Source: BloombergNEF. Note: Four hours duration for energy storage systems.
In 2030-2040, the cost of coal retrofits using green ammonia from Australia could undercut thecosts of projects using blue ammonia from the Middle East, mainly due to cost reductions ofrenewable projects in Australia (Figure 8). The retrofits with locally produced green ammonia
continues to be the most expensive during this period based on our analysis. By 2050 (Figure 9),coal retrofits co-firing 20% locally produced green ammonia ($80/MWh) could become cheaper
than retrofits burning blue ammonia from the Middle East ($83/MWh). We expect retrofits co-firing
green ammonia imported from Australia to be the cheapest ($69/MWh) out to 2050.
Figure 8: Comparison of levelized cost of electricity in 2030

Figure 9: Comparison of levelized cost of electricity in 2050

2050

2030

Renewables

Source: BloombergNEF. Note: Four hours duration for energy
storage systems.

© Bloomberg Finance L.P.2022

80 10660

63

69

Renewables

168 Green ammonia
134
from Australia

100% ammonia

Onshore wind +battery

100% ammonia

Coal retrofits

99 83

80

63
47

50% coal - 50%
ammonia83

Offshore wind

Onshore wind +battery

71

89

80% coal - 20%
ammonia

103

Solar + battery

96

90 13680% coal - 20%
ammonia

135 102

131

140

123

103

Blue ammonia
from theMiddle East
223
Green ammonia
from Japan

174

Solar + battery

199
155

236

Offshore wind

230$/MWh (2021 real)

50% coal - 50%
ammonia

Green ammonia
322 from Japan
Blue ammonia
from the263
Middle East
184
224 Green ammonia
from Australia
155$/MWh (2021 real)

Coal retrofits

Source: BloombergNEF. Note: Four hours duration for energy
storage systems.

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

8Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Retrofitting coal plants to burn ammonia is economically unviable, especially with a high co-firingratio. Burning 20% ammonia at coal-fired plants would be more expensive than the running costs,
or short-run marginal costs, of CCGT plants in 2024-2030. However, the retrofits burning 20%
green ammonia from Australia could become cost competitive against CCGT in 2040 and
offshore wind in 2050. The retrofits with other ammonia types are also set to remain
uncompetitive throughout 2050. Yet, 20% ammonia co-firing would only cut CO2 emissions by
20% and emit more CO2 than CCGT. More analysis on emissions can be found in Section 5.1.
The retrofits with 50% and 100% ammonia blending are set to be far more expensive than 20%
ammonia blending and therefore uncompetitive against other low-emission technologies (Figure 7
to Figure 9) For instance, offshore wind is one of the most expensive renewable technologies inJapan. Yet, offshore wind would be cheaper than coal retrofits burning 50%+ ammonia in 2030
and onward. This underscores the importance of deploying more offshore wind and other types ofrenewable energy, not ammonia co-firing technologies, to decarbonize the power sector in a costcompetitive manner. Retrofitting coal-fired power plants with ammonia should be used forseasonal balancing, instead of baseload power, to recoup the high costs.
Based on our analysis on the relative costs of different types of ammonia, retrofitting coal-fired
power plants using domestically sourced green ammonia would not become cost competitive
against other ammonia options, due to the high costs of domestic green ammonia. This means,from an economic standpoint, Japan will need to import large volumes of ammonia from overseas
markets to fuel the retrofitted coal plants. The implication of high volumes of ammonia imports
from an energy security angle can be found in Section 7.3.
Proponents of retrofitting existing coal power plants would cite the need for investment in grid
infrastructure as well as balancing services for new renewable power plants as major challenges
for adding more renewables. Indeed, connecting renewable projects larger than 2MW to theJapanese grid can currently cost up to a few billion yen. The higher capital expenditure can push
up the LCOE of a solar plant5 by up to 37%. This would still be below the LCOE of a retrofitted
coal power plant running at 100% ammonia. More importantly, Japan can reduce the costs
required by improving its power market regulations. Japan’s grid infrastructure is currently
underutilized due to legacy contracts prioritizing usage by older thermal and nuclear power plants
regardless of their actual usage rates. Japan’s grid connection costs for new renewables are also
higher than most other OECD markets due to lack of a fair transparent manner for awarding new
network connections. Adding more renewables to Japan’s electricity system will certainly needmore balancing services. Fortunately, Japan already has a large fleet of pumped hydro assets,originally developed to store excess nuclear power at night. And as figures 7 through 9 show,
pairing renewables with energy storage would still be more economically viable than ammonia cofiring at the high blend rates required for decarbonization.

4.2.

Cost comparison with carbon capture and storage (CCS)
technologies
The emissions from fossil-fueled thermal power plants can be captured through chemical reaction
either before or after fuel combustion. In this report, we only consider post-combustion liquid
absorption capture, using an amine solvent that binds with CO2–the dominant capture technology

5© Bloomberg Finance L.P.2022

See Renewable Projects in Japan Challenged by Opaque Grid (web | terminal) for more details.

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

9Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

in the power sector. See LCOE Highlights: Hydrogen, CCS, Small Nuclear (web | terminal) for
more details.
Our analysis (Figure 10) shows that carbon capture and storage (CCS) technologies can becheaper than retrofitting coal plants for ammonia, especially at co-firing ratios above 50%.
However, the cost decline of CCS technologies highly depends on global CCS market growth.
Our cost forecast assumes that cumulative capacity would reach 30GW by 2030. If the
deployment falls below 30GW, the speed of cost reductions could be slower than our expectation.
Japan is unlikely to contribute to the pre-2030 deployment of CCS technologies. The country’s
current target is to begin operations of CCS projects in 2030 by starting feasibility tests by
FY2023 and making final investment decisions by FY2026.
Figure 10: LCOE comparison of different technologies$/MWh (2021 real)
600
500
100% NH3 firing

400

50% NH3 co-firing

300

Offshore wind200

Coal CCS
100
20% NH3 co-firing
0
2024
2030

CCGT CCS

2040

2050

Source: BloombergNEF. Note: CCS stands for carbon capture and storage. CCS LCOEs do not
capture the cost of CO2 transport and storage. Cost declines for CCS in 2024-2030 are contingent
on a ramp-up of deployments to around 30GW by 2030 for the technology. Financing years areused for 2030 and 2050 of CCS LCOE.
Once captured, CO2 needs to be permanently stored in a permeable underground layer
underneath a cap rock, or re-used as an industrial feedstock. The Japanese government has thus
far identified 11 sites in Japan that could store 16 billion metric tons of CO2, more than Japan’s
cumulative emissions between 2010-2020 (14.4 billion metric tons of CO2). While this may
suggest there is ample space to store emissions from Japan’s coal power plants, the technicaland economic feasibility of such an approach is still uncertain. For example, how to transport theemissions captured at a power plant to one of the 11 storage sites remains a key challenge.
Public acceptance also remains unclear. In addition, some CCS projects have failed to deploy inother markets due to technical and environmental challenges.
The Japanese government aims to gradually increase the volume of annual CO2 injections from2030 and reach 120-140 million tons of CO2 injections by 2050. This is equivalent to 11-13% ofJapan’s annual CO2 emissions in 2020, or the volume of emissions from up to 26GW of coal
power plants6.

6© Bloomberg Finance L.P.2022

The calculation assumes a 75% capacity factor, 0.9 tons of CO2 per MWh for emissions during electricity
generation, and a 90% capturing rate by CCS technology.

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

10Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Section 5.

Greenhouse gas emissions
Reduction in CO2 emissions is the main advantage of ammonia co-firing at coal
power plants. But burning ammonia can lead to emission of other greenhousegases such as nitrous oxide (N2O). And a coal power plant retrofitted to co-fireammonia at 50% or lower blend rates still emits more CO2 than a natural gas
fueled combined cycle gas turbine power plant.

5.1.

Carbon dioxide (CO2) emission reductions
Co-firing ammonia with coal can reduce CO2 emissions from a coal power plant. Figure 11, Figure
12, and Figure 13 show the emission reduction potential depending on the ammonia source, withgreen ammonia offering the best option. Japan’s current regulations do not differentiate thesource of ammonia. Even with green ammonia, at co-firing rates of 50% or lower, CO2 emissions
from a retrofitted coal plant would still be worse than a natural gas fueled combined cycle gas
turbine.

Figure 11: Emissions from power
Figure 12: Emissions from power
generation and production of green NH3 generation and production of blue NH3
ton of CO2 per MWh
0.90
0.73
0.48

0.40

0.68

Natural gas
fueled CCGT

100% ammonia

50%
ammonia/coalNatural gas
fueled CCGT

50%ammonia/coal

20% ammonia –80% coal

100% coal

100% ammonia

Natural gas
fueled CCGT

50%ammonia/coal

20% ammonia –80% coal

20% ammonia –80% coal

0.07

0.00

100% coal

0.40

0.40

100% coal

0.45

ton of CO2 per MWh
0.90
0.86
0.79

100% ammonia

ton of CO2 per MWh
0.90
0.72

Figure 13: Emissions from power
generation and production of gray NH3

Source: BloombergNEF. Note: Emissions for power generation and ammonia production. Gray (unabated) ammonia production
assumes 9kg of CO2 emissions to produce 1kg of hydrogen. Blue ammonia production assumes 90% CO2 capture rates of carbon
capture and storage (CCS) technologies for unabated hydrogen production.

5.2.

Marginal abatement cost of ammonia coal co-firing
Based on avoided CO2 emissions (in CO2 emissions intensity) and project costs (in LCOE), we
estimate (Figure 14) a carbon price of at least $300/ton of CO2 would be needed to make cleanammonia co-firing at 20% blend rate economically viable in 2030. By 2050 (Figure 15), the carbon
price needed to make 100% ammonia fueled retrofitted coal plants economically viable could be© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

11Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

reduced to around $159/ton of CO2. These values are far higher than Japan’s current “tax forclimate change mitigation” set at below $3/ton of CO2.
Figure 14: Marginal abatement cost in 2030

Figure 15: Marginal abatement cost in 2050

2030

2050

Marginal abatement cost ($/ton of CO2)
410

Marginal abatement cost ($/ton of CO2)

345

302

219

233

158

80% coal – 20%
green ammonia
from Australia

80% coal – 20%
blue ammonia from
the Middle East

Source: BloombergNEF

100% ammonia from100% ammonia from 100% ammonia from
Australia
Japan
the Middle East
Source: BloombergNEF

5.3.

Figure 16: No laughing
matter: global warming
potential of CO2 vs. N2O

GWP

CO2

80% coal – 20%
green ammonia
from Japan

Nitrous oxide (N2O) emissions: no laughing matter
Since the ammonia molecule includes nitrogen, ammonia combustion generates nitrous oxide,
colloquially referred to as laughing gas. Nitrous oxide’s global warming potential (GWP) is 273
times larger than that of CO2 for a 100-year timescale. Nitric oxide (NO) and nitrogen dioxide(NO2) are not greenhouse gases. Japan’s Central Research Institute of Electric Power Industry’s
research has shown at blend rates below 20%, higher rates of ammonia co-firing leads to higher
nitrous oxide emissions. Other studies have suggested nitrous oxide emissions rise until 40%
ammonia co-firing, while higher ammonia co-firing ratios lead to lower nitrous oxide emissions.
Retrofitted coal plants would likely need to invest in technologies to capture the nitrous oxide
emissions to ensure GHG emission reduction benefits. This in turn will further undermine the poor
economics of ammonia co-firing.

N 2O

Source: BloomberrgNEF,
EPA. Note: GWP for a 100year timescale.

Figure 17: Nitrous oxide (N2O) emission intensity for different ammonia co-firing ratio

Source: School of Energy and Environment at Anhui University of Technology in China© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

12Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Section 6.

Safety and toxicity
Ammonia needs to be handled with care due to its toxicity and flammability. The
regulatory framework around safety is another concern as current regulations
were not designed for ammonia use in power generation.

6.1.

Figure 18: Ammonia-related
fire in China in 2013

Safety and toxicity
Ammonia is colorless but has a distinct odor. The molecule can pose a big threat to human healthas it reacts with water to form ammonium hydroxide, which is corrosive and damages cells in the
body on contact. Thus, ammonia is classified as toxic under Japan’s regulations such as theIndustrial Safety and Health Act and the Poisonous and Deleterious Substances Control Act.
Japan’s High Pressure Gas Safety Institution reported 28 minor ammonia-related7 incidents, suchas leakage, in 2021. Other countries saw more severe cases. For example, at a poultry plant in
China’s Jinlin province, ammonia leakage caused a fire and killed 120 people in 2013. In thesame year, another ammonia leakage killed 15 and injured 25 at a frozen seafood plant inShanghai, China.

Source: Washington Post.
Table 2: Safety comparison of ammonia and natural gas
Ammonia

Natural gas (methane)

Flammability- Flammable- Flammable

Toxicity- Acute poisoning from inhaling- Skin/eye/respiratory damages- NoneClassification under the Industrial Safety
and Health Act- Specified Chemical Substance Type-3: a - Hazardous chemicals, flammablemass leakage causes acute poisoning- Hazardous chemicals, flammable

Classification under the Poisonous andDeleterious Substances Control Act- Deleterious substance- Not listed

Source: BloombergNEF, The Globally Harmonized System of Classification and Labelling of Chemical (GHS), Ministry of Health,
Labor, and Welfare of Japan. Safety levels are colored as dangerous, medium, and safe.

6.2.

Ammonia-related regulations

Japan’s current ammonia

Since ammonia has been traded internationally and processed domestically in Japan, the country

regulations were notdesigned for electricity

already has multiple regulations on ammonia. These are listed in Table 3 and cover handling,
marine transport, storage and supply of ammonia. However, Japan’s current ammonia regulations
were not designed for electricity generation. To ensure safety, Japan needs to implement new

generation

7© Bloomberg Finance L.P.2022

Ammonia-related accidents in this section distinguish ammonia from ammonium nitrates.

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

13

Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

regulations overseeing materials used for boilers, gas leakage at power plants, and safety/hazard
sign standards for ammonia use in the power sector.
Table 3: Current regulations related to ammonia use
Type

Relevant regulations

Facilities-

High Pressure Gas Safety Act
Industrial Safety and Health Act
Noise/Vibration Regulation Act
Act on the Prevention of Disaster in Petroleum Industrial Complexes and Other Petroleum Facilities
Building Standard Act
Port and Harbor Act
Fire Services Act
Poisonous and Deleterious Substances Control Act
Offensive Odor Control Law

Marine transport-

Ship Safety Act
Fire Services Act
Cabinet Order Concerning the Control of Hazardous Materials
Regulation Concerning the Control of Hazardous Materials
Port Regulation Act

Storage-

Fire Services Act
Regulation on Safety of General High Pressure Gas
Warehouse Business Act

Ammonia supply via
road or pipelines-

Road Traffic Act
Regulation on Safety of General High Pressure Gas
Regulation on Safety of Industrial Complexes
Seacoast Act
River Act

Source: Ministry of Land, Infrastructure, Transport, and Tourism
The government is mulling more stringent requirements for safe distance and empty space nearfacilities handling ammonia. Current regulations are based on the category of high-pressure gas
without considering ammonia’s toxicity. Under the current rules, ammonia facilities need to be 20
meters away from other high-pressure gas facilities, 30 meters away from facilities with many
people (such as schools, hospitals, and theaters), and 50 meters away from historical sites.
Empty space must also be secured within 15 meters of such facilities.
In addition, the government is aiming to revamp regulations for operation and maintenance atfossil-fueled power plants due to ammonia’s toxicity and flammability. Currently, regulations do
not require dedicated electric/boiler technicians and the submission of construction schedules forsmall thermal power plants.

© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

14

Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Section 7.

Clean ammonia supply and demand
Japan’s current ammonia demand is relatively small at around 1 million tons per
year, just shy of 1% of global production. The Japanese government wants togrow this demand by promoting ammonia co-firing at coal plants. Given thetechnology’s low economic competitiveness in electricity generation, promoting
the use of clean ammonia in other applications such as fertilizer production oreven shipping offers more advantages and opportunities for decarbonization.

7.1.

Current market size
Japan’s annual ammonia demand is about 1 million tons8, less than 1% of global production9, in
2021. Around 80% of this demand is met through domestic production, using imported fossil fuelfeedstock. The remaining 20% is imported10 from countries including Indonesia, Australia, andMalaysia.
Figure 19: Japan’s historical ammonia demand

thousand tons of NH3
1,200

1,000

1,124
200

1,095

1,121

221

241

1,070

1,114

1,105
963
244

244

271
203

800

Other

600

Import
400

901

863

863

783

853

848

Production

743

200

0
2015

2016

2017

2018

2019

2020

2021

Source: Japan Fertilizer & Ammonia Producers Association, BloombergNEF. Note: Years show
Japan’s fiscal year starting from April to March.

8

Japan Fertilizer & Ammonia Producers Association

9

International Energy Agency (IEA)

10© Bloomberg Finance L.P.2022

Tariff item number for ammonia is 2814-10 for Japan customs.

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

15

Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

7.2.

Future market size
Japan’s ambitious ammonia target underscores its desire to keep existing coal-fired power plants,
which could otherwise become stranded in the country’s push for decarbonization.
IEA’s scenarios suggest global ammonia production could grow to 217-222 million tons by 2030
and to 254-319 million tons by 2050 from 185 million tons in 2020. Japan’s government aims toincrease its ammonia demand to 3 million tons by 2030 and 30 million tons by 2050 from 1 million
tons in 2021 (Figure 20). These targets do not include a breakdown by use case. Japan’sammonia demand target seems ambitious given that the 2050 target would be equivalent to about
11% of IEA’s global demand projection in 2050.

Figure 20: Japan’s current ammonia demand size andtargets for 2030 and 2050

million tons of NH 3 per year

million tons of NH 3 per year

30

29

Figure 21: Theoretical cumulative volume of ammonia
supply globally (converted from clean hydrogen production
projects proposed by developers)

Volume needed
for the targetedvolumeGreen ammonia
Blue ammonia

6.1

5.2
3.9

4.1

3.0

1.2

3
2

2021 actual 2030 target

5.9
4.5

Current demand
1

7.82050 target

Source: BloombergNEF, Ministry of Economy, Trade, andIndustry, Japan Fertilizer & Ammonia Producers Association.

0.2

0.6
0.6

1.5

2.0

2.0

2.6

2021

'25

'30

'35

'40

N/A

Source: BloombergNEF. Note: The volume of ammonia isconverted from the volume of hydrogen assuming all hydrogen
supply pipeline was used for ammonia production.

BloombergNEF tracks the volume of clean hydrogen supply pipeline proposed by developers
globally. Assuming all of those were used for clean ammonia production, the cumulative volume
of clean ammonia supply would be only 6.1 million tons of ammonia per year in 2040 (Figure 21)– much less than Japan’s 2050 target, showing how ambitious Japan’s ammonia demand target
is. At the same time, not all clean hydrogen supply projects would be for ammonia production.
To sense-check the Japanese government’s ammonia demand targets, we have estimated (Table4) the volume of ammonia needed for co-firing at different blend rates, assuming coal power
plants are only retired after 45 years of operation. By 2030, if all of Japan’s coal power plants
were to co-fire ammonia at a 20% blend rate, annual demand would reach 22.6 million tons,
significantly higher than the government’s 3 million tons target. This suggests the government
expects few coal plants will be co-firing with ammonia in 2030. By 2050, if all remaining coal
power plants try to run only on ammonia, annual demand would reach 40.4 million tons, higher
than the government’s 30 million tons. This suggests the government is assuming some coal
power retirements and/or usage of carbon capture and storage at some coal plants.

© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

16

Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Table 4: Ammonia demand size comparison
2030: 20% ammonia co-firing

2040: 50% ammonia co-firing

2050: 100% ammonia firing

45GW

35GW

16GW

22.6 million tons ofammonia/year

43.7 million tons ofammonia/year

40.4 million tons ofammonia/year3

Not applicable

30

Cumulative coal capacity
NH3 Ammonia burned by
all coal-fired power
plantsGovernment target

Source: BloombergNEF. Note: The volume of ammonia needed per GW per year is assumed to be 500,000 tons for 20% co-firing,
1,250,000 tons of ammonia for 50% co-firing, and 2,500,000 tons of ammonia for 100% firing. Efficient coal-fired power plants
include ultra-super critical plants. Inefficient coal-fired power plants include sub-critical and supercritical plants.

7.3.

Energy security considerations
Coal retrofits could enable existing coal-fired power plants to stay in the market. However, as
discussed in Section 5, it would be crucial for coal-fired power plants to blend at least 50%
ammonia to limit CO2 emissions below that of natural gas-fired CCGT plants. Since Japan is yet
to commercialize 20% co-firing technology, it would take time to achieve 50%+ levels. The
immaturity of ammonia co-firing technology means that Japan would need to continue thermal
coal imports for many years to come, putting its energy security at risk.
Figure 22: Outlook on ammonia production costs for Japan$ per ton of NH 3 (2021 real)
2,500

2,000
Green ammonia in
Japan

1,500

Green ammonia from
Australia

1,000Blue ammonia from
Middle East

500

0

2030

2040

2050

Source: BloombergNEF. Note: See Appendix B for more details.
In addition, Japan would likely need to rely on clean ammonia from other countries due to the highcost of domestically sourced green ammonia. Green ammonia produced in Japan is set to costmore than green ammonia imported from Australia throughout 2050, as shown in Figure 22.
Similarly, Japanese green ammonia could be more expensive than blue ammonia imported from
the Middle East until 2040.

© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

17

Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Consequently, Japan’s energy security may worsen by switching from coal imports to coal andammonia imports. By relying on two imported commodities to operate coal-fired power plants,
rather than one, Japan runs the risk of worsening its long-term energy security.

7.4.

Clean ammonia’s role in decarbonization
To identify whether clean ammonia can play a role in decarbonization of a particular sector, weneed to consider four factors:
1.

Are the technologies for ammonia usage in that application already mature?

2.

What is the competitiveness of clean ammonia compared to fossil fuels used in thatapplication?

3.

How competitive is clean ammonia compared to other decarbonization approaches for thatapplication?

4.

How willing are customers for that application to pay for clean ammonia?

Table 5 summarizes these factors for clean ammonia usage in Japan.
Table 5: Suitability of ammonia for end uses in JapanUse case

Fertilizers

Shipping

Electricity generation(Seasonal balancing)Electricity generation(Baseload)Use-case
opportunity

High

MediumMediumLow

Maturity of thetechnology?

MatureTesting/R&D began

Testing/R&D began

Testing/R&D began

Competitive withexisting fossil
fuel processes?

Could be competitive
given current gas prices

Costlier

Costlier

Costlier

Competitive withalternative lowcarbon
processes?

No other low-carbon
process than green/blueammonia for
decarbonizing fertilizers

Methanol and ammonia
are the only two
promising low-carbon
fuels. Methanol is moremature than ammonia.

Depends on the uptake ofhydrogen-fired power
plants and carbon captureand storage (CCS)No

Customers
willing to pay
more for cleanammonia?

Yes.
Limited decarbonization
options are available.

Yes.
IMO’s 50% emissions
reduction target. Limited
decarbonization options
are available.

Possibly yes.
To decarbonize existingfossil-fueled assets.

Possibly yes.
To decarbonize existingfossil-fueled assets.

Source: BloombergNEF, BloombergNEF Talk: Where Are We in the Hydrogen Hype Cycle? (web | terminal). Note: Suitability levels
are colored as high, medium, and low. The Japanese government wants to use ammonia as fuel for industrial processes, but BNEF
hasn’t analyzed ammonia use for industry. For the power sector, solar and wind together with batteries have the potential todecarbonize 70% to 80% of electricity generation on a least-cost basis. Yet the last 20% to 30% shares of generation are hard to
decarbonize: these tend to be hours that are difficult to reach cost-efficiently for renewables, such as high demand hours during
winter or evening peak.

© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

18

Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Appendices
Appendix A. Retrofitting coal-fired power plants
Scenarios
Below is a list of variables used to create the scenarios and cost ranges for retrofitting coal-fired
power plants for burning ammonia in this research.
•

Different ammonia co-firing ratio (20%, 50%, 100%)•

Production methods of ammonia (See Appendix B for more details).

•

Operation year (2024, 2030, 2040, 2050)•

Plant lifetime (15 years, 25 years)•

Financing (75% debt, 100% equity)

In this note, visuals (for Figure 1, Figure 7, Figure 8, Figure 9, Figure 10, Figure 14, Figure 15,
Figure 23,Figure 24, and Figure 25) assume a 25-year lifetime for retrofitted power plants and a
75% debt ratio, or gearing rate, for financing. Data for other scenarios and inputs used for LCOE
calculation can be found in the accompanying data for this note.
Figure 23: LCOE comparison (20%ammonia co-firing)

Figure 24: LCOE comparison (50%ammonia co-firing)

Figure 25: LCOE comparison (100%ammonia firing)$/MWh (2021 real)
600$/MWh (2021 real)
600$/MWh (2021 real)
600

500

500

500

400

400

400

300

300

300

200

200

200

100

100

0

0

100
0
2024 2030

2040

2050

2024 2030

2040

2050

2024 2030

2040

2050

Source: BloombergNEF. Note: Four hours duration for energy storage systems.

© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

19Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Retrofits
Coal-fired power plants require upgrades to allow for blending of ammonia.

20% ammonia co-firing
Our discussions with companies in Japan indicate that for 20% co-firing, retrofit includes
upgrading burners and additional balance of plant expenses to receive and store ammonia(Figure 26). These upgrades come at an estimated 11% premium in capex. Since this research
focuses on coal power plant retrofits, we assumed 11% of capex for new coal-fired power plants
in Japan as capex needed for retrofits.
Controlling the exhaust NOx emission will be key in each plant’s combustion strategy. Based on
the available information, we estimate a 20% ammonia blend would reduce the power plant’s
thermal efficiency by around 12%.
Figure 26: Impacts of coal-fired power plant upgrades to burn a blend with 20% ammonia

Emissions (tCO2/MWh)-20%

Opex ($/kW/yr)
Efficiency (%, HHV)

10%
-12%

Capex ($/MW)

11%

Source: BloombergNEF, manufacturer interviews. Note: The efficiency impact is in relative
percent, not percentage points. 20% ammonia blend refers a blend by energy content, notvolume. HHV is high heating value.
To calculate levelized cost of electricity (LCOE) of coal power plants blending 20% ammonia, weapplied the above changes to the benchmark costs for Japan’s coal-fired power plants detailed inour 1H 2022 LCOE Update (web | terminal). We subsequently calculated the LCOE in our Energy
Project Valuation Model (web | terminal).
Ammonia blending ratio refers to the blend split by energy content, not volumetric. Hence, thedecline in the volume of CO2 emissions would be equivalent to the co-firing ratio. For example,
coal-fired retrofits for 20% ammonia blending would reduce CO2 emissions by 20%.

More than 20% ammonia co-firing
Coal retrofits with more than 20% ammonia co-firing have not been tested or commercialized.
Hence, our research applied the same retrofit cost assumptions used in 20% co-firing as theretrofit costs for more than 20% co-firing including 50% and 100%. In reality, a higher ammonia
co-firing ratio will likely require higher capex because boilers would require major upgrades oreven replacements. Storage tanks for ammonia would also need to be bigger at a higher co-firingratio. More advanced equipment to capture NOX emissions would be needed as well.

© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

20Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

Appendix B. Ammonia production cost
assumptions
Our research incorporates three different types of ammonia: green ammonia produced in Japan,
green ammonia imported from Australia, and blue ammonia imported from the Middle East. Fuelammonia prices are estimated by the costs of hydrogen production, conversion to ammonia, andshipping to Japan.

Hydrogen production
Since ammonia is produced from hydrogen, we rely on the hydrogen production costs derived
from BNEF’s Hydrogen Project Valuation Model (web | terminal). Below are the assumptions oftechnologies used for hydrogen production.
•

Japan: alkaline electrolysis using fixed-axis PV projects and western electrolyzers•

Australia: alkaline electrolysis using tracking PV projects and western electrolyzers•

Middle East: steam methane reforming using natural gas

Conversion to ammonia from hydrogen
Next, we added the cost of converting hydrogen to ammonia based on the following assumptions.
We expect economies of scale to kick in post-2027 and push down the conversion cost going
forward.
Table 6: Costs of conversion to ammonia from hydrogen$/kg of H2, real 2021
2022-2027

1.41

2028-2049

Linear interpolation for each year using values
for 2027 and 2050

2050

0.87

Source: BloombergNEF

Transportation of ammonia
Ammonia produced outside Japan needs to be shipped to Japan. Below is our assumption ontransportation costs added to ammonia produced in Australia and the Middle East. Shipping
ammonia is already matured, so these transportation costs are used throughout the modeling
period:© Bloomberg Finance L.P.2022•

Ammonia from Australia: $0.3/kg of hydrogen (real 2021)•

Ammonia from the Middle East: $0.4/kg of hydrogen (real 2021)

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

21

Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

About usContact details
Client enquiries:• Bloomberg Terminal: press <Help> key twice• Email: support.bnef@bloomberg.net
Isshu Kikuma

Japan Energy Analyst

Meredith Annex

Head of Heating and Hydrogen

Tifenn Brandily

Transition Risk Analyst

David Kang

Head of Japan-Korea ResearchMartin Tengler

Lead Hydrogen Analyst

Copyright© Bloomberg Finance L.P. 2022. This publication is the copyright of Bloomberg Finance L.P. in connection
with BloombergNEF. No portion of this document may be photocopied, reproduced, scanned into anelectronic system or transmitted, forwarded or distributed in any way without prior consent of BloombergNEF.

Disclaimer
The BloombergNEF ("BNEF"), service/information is derived from selected public sources. Bloomberg
Finance L.P. and its affiliates, in providing the service/information, believe that the information it uses comesfrom reliable sources, but do not guarantee the accuracy or completeness of this information, which is subject
to change without notice, and nothing in this document shall be construed as such a guarantee. The
statements in this service/document reflect the current judgment of the authors of the relevant articles orfeatures, and do not necessarily reflect the opinion of Bloomberg Finance L.P., Bloomberg L.P. or any of theiraffiliates (“Bloomberg”). Bloomberg disclaims any liability arising from use of this document, its contents
and/or this service. Nothing herein shall constitute or be construed as an offering of financial instruments or as
investment advice or recommendations by Bloomberg of an investment or other strategy (e.g., whether or not
to “buy”, “sell”, or “hold” an investment). The information available through this service is not based on
consideration of a subscriber’s individual circumstances and should not be considered as information
sufficient upon which to base an investment decision. You should determine on your own whether you agreewith the content. This service should not be construed as tax or accounting advice or as a service designed tofacilitate any subscriber’s compliance with its tax, accounting or other legal obligations. Employees involved inthis service may hold positions in the companies mentioned in the services/information.
The data included in these materials are for illustrative purposes only. The BLOOMBERG TERMINAL service
and Bloomberg data products (the “Services”) are owned and distributed by Bloomberg Finance L.P. (“BFLP”)
except (i) in Argentina, Australia and certain jurisdictions in the Pacific islands, Bermuda, China, India, Japan,
Korea and New Zealand, where Bloomberg L.P. and its subsidiaries (“BLP”) distribute these products, and (ii)in Singapore and the jurisdictions serviced by Bloomberg’s Singapore office, where a subsidiary of BFLP
distributes these products. BLP provides BFLP and its subsidiaries with global marketing and operational
support and service. Certain features, functions, products and services are available only to sophisticatedinvestors and only where permitted. BFLP, BLP and their affiliates do not guarantee the accuracy of prices orother information in the Services. Nothing in the Services shall constitute or be construed as an offering offinancial instruments by BFLP, BLP or their affiliates, or as investment advice or recommendations by BFLP,BLP or their affiliates of an investment strategy or whether or not to “buy”, “sell” or “hold” an investment.
Information available via the Services should not be considered as information sufficient upon which to base

© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

22Japan’s Costly Ammonia Coal Co-Firing Strategy
September 28, 2022

an investment decision. The following are trademarks and service marks of BFLP, a Delaware limited
partnership, or its subsidiaries: BLOOMBERG, BLOOMBERG ANYWHERE, BLOOMBERG MARKETS,
BLOOMBERG NEWS, BLOOMBERG PROFESSIONAL, BLOOMBERG TERMINAL and BLOOMBERG.COM.
Absence of any trademark or service mark from this list does not waive Bloomberg’s intellectual property
rights in that name, mark or logo. All rights reserved. © 2022 Bloomberg.

© Bloomberg Finance L.P.2022

No portion of this document may be reproduced, scanned into an electronic system, distributed, publicly
displayed or used as the basis of derivative works without the prior written consent of Bloomberg Finance
L.P. For more information on terms of use, please contact sales.bnef@bloomberg.net. Copyright andDisclaimer notice on page 26 applies throughout.

23